Animal and Plant Health Inspection Service, USDA.
Affirmation of interim rule as final rule.
We are adopting as a final rule, without change, an interim rule that amended the gypsy moth regulations by adding 4 counties in Indiana, 6 counties in Michigan, 11 counties in Ohio, 4 cities and 3 counties in Virginia, and 2 counties in Wisconsin to the list of generally infested areas. As a result of the interim rule, the interstate movement of regulated articles from those areas is restricted. The interim rule was necessary to prevent the artificial spread of the gypsy moth to noninfested States.
The interim rule became effective on July 27, 1999.
Ms. Coanne E. O'Hern, Operations Officer, Invasive Species and Pest Management Staff, PPQ, APHIS, 4700 River Road Unit 134, Riverdale, MD 20737-1236; (301) 734-8247.
In an interim rule effective and published in the
Comments on the interim rule were required to be received on or before September 27, 1999. We did not receive any comments. Therefore, for the reasons given in the interim rule, we are adopting the interim rule as a final rule.
This action also affirms the information contained in the interim rule concerning Executive Orders 12372 and 12988 and the Paperwork Reduction Act.
Further, for this action, the Office of Management and Budget has waived the review process required by Executive Order 12866.
This rule affirms an interim rule that amended the gypsy moth regulations by adding 4 counties in Indiana, 6 counties in Michigan, 11 counties in Ohio, 4 cities and 3 counties in Virginia, and 2 counties in Wisconsin to the list of generally infested areas. As a result of the interim rule, the interstate movement of regulated articles from those areas is restricted. The interim rule was necessary to prevent the artificial spread of the gypsy moth to noninfested States.
The following analysis addresses the economic effect of the interim rule on small entities, as required by the Regulatory Flexibility Act.
This action affects the interstate movement of regulated articles and outdoor household articles (OHA's) from and through areas in Indiana, Michigan, Ohio, Virginia, and Wisconsin that are newly regulated for gypsy moth. There are several types of restrictions that apply to the newly regulated areas. These restrictions will have their primary effect on persons moving OHA's, nursery stock, Christmas trees, logs and wood chips, and mobile homes interstate from a generally infested area to any area that is not generally infested.
Under the regulations, OHA's may not be moved interstate from a generally infested area into or through a noninfested area unless they are accompanied by either a certificate issued by an inspector or an OHA document issued by the owner of the articles, attesting to the absence of all life stages of the gypsy moth. Most individual homeowners moving their own articles who comply with the regulations choose to self-inspect and issue an OHA document. This takes a few minutes and involves no monetary cost. Individuals may also have State-certified pesticide applicators, trained by the State or U.S. Department of Agriculture (USDA), inspect and issue certificates.
Generally, regulated articles (such as logs, pulpwood, wood chips, mobile homes, nursery stock, and Christmas trees) may only be moved interstate from a generally infested area if they are accompanied by a certificate or limited permit issued by an inspector. However, logs, wood chips, and pulpwood may be moved without a certificate or limited permit if the person moving the articles attaches a statement to the waybill stating that he or she has inspected the articles and has found them free of all life stages of the gypsy moth. This exception minimizes the costs of moving logs, pulpwood, and wood chips interstate. Regulated articles may also be moved interstate from a generally infested area without a certificate if they are moved by the U.S. Department of Agriculture for experimental or scientific purposes and they are accompanied by a permit issued by the Administrator of the Animal and Plant Health Inspection Service.
Persons moving regulated articles interstate from a generally infested area may obtain a certificate or limited permit from an inspector or a qualified certified applicator. Inspectors will issue these documents at no charge, but costs may result from delaying the movement of commercial articles while waiting for the inspection. Certificates for interstate movement of mobile homes from a generally infested area may also be obtained from qualified certified applicators.
When inspection of regulated articles or OHA's reveals gypsy moth, treatment is often necessary. The preferred treatment, scraping egg masses and spraying caterpillars, costs $10 to $30 per shipment on average. Fumigation is another alternative, but it is more expensive, at $75 to $100 per shipment, and it may damage the shipment. Treatment is done by qualified certified applicators, most of which are small businesses. These businesses might
Nurseries and Christmas tree growers that move a substantial number of shipments interstate from the generally infested areas would be able to minimize treatment costs by treating their premises for gypsy moths under a compliance agreement with USDA. Treatment would cost businesses between $10 and $20 per acre. This alternative would enable nurseries and Christmas tree growers to issue their own certificates for interstate shipments and would be less costly than treating individual shipments. The entities that would be most likely to choose this alternative are nurseries that move a substantial number of shipments interstate from the generally infested areas and that treat their premises for other pests in addition to the gypsy moth. Producers that do not operate under a compliance agreement with APHIS, but that treat their premises under this option, would receive certification for each shipment from an inspector.
There are approximately 687 entities in the newly regulated areas that will incur costs from the interim rule. These entities include 286 nurseries, 179 Christmas tree growers, 85 loggers, and 41 sawmills. The vast majority of these entities are small businesses.
Approximately 100 of the affected entities are in Indiana. These entities include 70 nurseries, 20 loggers, and 10 Christmas tree growers. Nurseries in Indiana sold an average of $127,206 worth of crops in 1997, and Christmas tree growers had average sales of $16,332. Average sales figures for loggers and sawmills in Indiana are not available, but nationwide, loggers and sawmills averaged sales of $3.3 million in 1992. Only about 10 percent of the affected entities' shipments are expected to leave the generally infested area, and only half of those, or 5 percent overall, will require treatment.
Approximately 187 of the affected entities are in Michigan. There are approximately 19 nurseries and 168 Christmas tree growers in the newly regulated areas. We do not expect that any treatments will be necessary for shipments from the newly regulated areas in Michigan because gypsy moth populations are low in those areas due to climatic conditions. However, time, salary, and recordkeeping costs for self-inspections will be incurred for shipments leaving the regulated areas. We estimate that 50 percent of the Christmas trees, 20 percent of the logs, and less than 2 percent of the nursery stock produced in the newly regulated areas are shipped interstate to noninfested areas. Nurseries and Christmas tree growers will also incur a $30 per acre fee for gypsy moth inspections, which are mandated by the State as a licensing requirement. This inspection fee represents about 1.5 percent of the average per-acre value of sales of harvested cut Christmas trees in Michigan in 1997.
Approximately 240 of the affected entities are in Ohio, including 135 nurseries, at least 96 Christmas tree growers, and 9 sawmills. Nurseries in the newly regulated areas had average sales of $19,218 in 1997, while Christmas tree growers averaged $22,505. Sawmills averaged $1.7 million in shipments in 1992, indicating that at least some of them are not small businesses. We do not know how many shipments are likely to be shipped out of the newly regulated areas in Ohio.
There are approximately 98 affected entities in Virginia and 62 affected entities in Wisconsin. However, we do not anticipate any additional costs for entities in the newly regulated areas in Virginia and Wisconsin since they do not send shipments interstate from the generally infested areas.
Under these circumstances, the Administrator of the Animal and Plant Health Inspection Service has determined that this action will not have a significant economic impact on a substantial number of small entities.
Agricultural commodities, Plant diseases and pests, Quarantine, Reporting and recordkeeping requirements, Transportation.
7 U.S.C.147a, 150bb, 150dd, 150ee, 150ff, 161, 162, and 164-167; 7 CFR 2.22, 2.80, and 371.2(c).
Agricultural Research Service, USDA.
Final rule.
The Department of Agriculture (USDA) is establishing a fee schedule for loans of materials, and establishing a fee schedule for copying of materials from the collections of the National Agricultural Library. Fees generated will be used to defray costs of document delivery and maintenance of the collection.
Effective April 1, 2000.
Address all correspondence to Eileen McVey, Access Services Librarian, Document Delivery Services Branch, National Agricultural Library, Agricultural Research Service, Room 300, 10301 Baltimore Ave., Beltsville MD 20705-2351. Telephone: 301-504-6503. Email: userfees@nal.usda.gov
Carol Ditzler, Head Document Delivery Services Branch, National Agricultural Library, Agricultural Research Service, Room 300, 10301 Baltimore Ave., Beltsville MD 20705-2351.
This rule was published as a proposed rule for comment on August 16, 1999. Two comments were received. One comment indicated that fee changes were reasonable and that the price increase was viewed as having a positive effect upon the ability of patrons to obtain materials. The second comment viewed the increase in fees as excessive in terms of photocopying. The National Agricultural Library believes the fees are comparable to those of other research libraries. A random sampling of 15 academic and research libraries that do charge flat fees indicated a photocopy charge that ranged from a low of $8.00 when using OCLC IFM service to a high of $25.00 for non-IFM requests. (IFM is a service provided by the Online Computer Library Center (OCLC) in Dublin, Ohio, which credits and debits charges for libraries that participate resulting in a reduction of costs for invoicing.) The library, therefore, considers a flat fee of $13.00 for photocopies on the low side of a median cost for such services.
This rule has been reviewed under Executive Order 12866, and it has been
The Department of Agriculture certifies that this rule will not have a significant impact on a substantial number of small entities as defined in the Regulatory Flexibility Act, Pub. L. No. 96-534, as amended (5 U.S.C. 601,
In accordance with the Office of Management and Budget (OMB) regulations (5 CFR part 1320) which implement the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 35), the information collection and record keeping requirements that will be imposed in implementation of this proposed rule have been submitted to OMB. This collection was approved by OMB on September 30, 1999, with OMB NO.: 0518-0027 and an expiration date of 09/30/2002.
Section 1410A of the National Agricultural Research, Extension, and Teaching Policy Act of 1977 (7 U.S.C. 3125a), as added by section 1606(a) of Pub. L. 101-624, expanded existing statutory authorities for the NAL. In particular, section 1410A(e) authorized the NAL Director to make copies of NAL bibliographies, to make microforms and other reproductions of books and other library materials in USDA, to provide any other library and information products and services, and to sell those products and services at such price (not less than the total costs of disseminating the products and services) as the Secretary of Agriculture deems appropriate. Receipts from such sales must be deposited to the credit of appropriations available to the NAL and remain available until expended.
Currently, USDA regulations (7 CFR part 1, Appendix A) supply a fee schedule for copying of NAL materials requested under the Freedom of Information Act (FOIA), 5 U.S.C. 552. NAL in this regulation adopts a fee schedule for copying of NAL materials pursuant to interlibrary loan or other research requests, and to cover the costs of interlibrary loans of materials from NAL collections.
The NAL will charge fees for interlibrary loans of original materials from the NAL collection to other non-Federal and non-USDA libraries and institutions in the United States and Canada. By original materials, it is meant that NAL will provide loans of original works, and not copies, except in rare instances where works are too fragile or valuable for shipment. Libraries are encouraged to obtain materials locally and to view the NAL as a library of last resort. Loans directly to individuals are not permitted.
A flat fee per loaned item will be charged. Fees generated will be used to recover actual processing costs and to offset general wear and tear on the collection when items are loaned. The amount is based on a study of current library costs and market comparisons. There will be no charge for renewals.
Costs for replacement of lost or damaged materials will be the actual cost to purchase a replacement or a flat fee if the exact cost cannot be determined. A processing cost will be added to all lost or damaged materials.
The NAL will charge a fee for photocopying and reproduction services separate from the fee schedule applicable to FOIA requests under 7 CFR part 1, Appendix A, for paper copying, duplication, and reproduction services provided to non-USDA and non-federal libraries and institutions in the United States. These services will be provided only in response to an interlibrary loan request from a library. Use of the interlibrary loan system ensures that NAL receives the request in an appropriate form and format for response. In some exceptions, services will be provided for requests from individuals who have not been able to obtain materials through their local resources or who have made special arrangements with the Special Collections section using their forms.
Copying of articles is subject to a maximum limitation of 50 pages per article for purposes of copyright compliance. This is based on CONTU Guidelines (National Commission on New Technological Uses of Copyright Works), and the Code of Federal Regulations (Title 17, and Title 37, Volume 1).
The NAL will charge in its schedule of fees for photocopying of paper materials and paper copying of microfiche or microfilm. NAL is switching from a per page-based charge to a per item flat fee because, historically, the average request is between 10 and 20 pages. Establishing a flat fee allows the customer to estimate their costs more effectively and allows the library to eliminate the cost of multiple steps currently necessary in determining pro-rated fees. Fees established are based on actual costs (staffing, contract costs, supplies, copier maintenance, normal wear and tear on the collection, delivery costs, etc.) as well as based on a review of comparable fees across the nation charged by other research and academic libraries. All fees will apply to non-USDA and non-federal library requests that meet standard interlibrary loan format requirements and apply to copying of materials from the NAL collections only.
NAL also will charge a flat rate for the costs of duplication of NAL owned microfiche and microfilm. Photographic services from NAL Special Collections will be charged at cost for reproduction of the photo product, plus a flat rate for preparation costs.
The National Technical Information Service (NTIS) within the United States Department of Commerce provides a number of services to Federal Agencies, one of which is billing and collection services. NAL uses NTIS as the preferred method for invoicing and payment of fees under this fee schedule. Use of NTIS by NAL is preferred because it is the only agency currently providing this service to Federal offices. NAL encourages institutional users to establish deposit accounts with NTIS if needed. Payment for services will be made by check, money order or credit card in U.S. funds directly to the NTIS upon receipt of an invoice from NTIS. Subject to service charges for the actual costs of performing the invoicing service, funds received by NTIS will be returned to NAL to the credit of the appropriation account charged with the costs of providing the loan or copying service.
Agricultural research, Agriculture, Libraries, Research, User fees.
For the reasons set out in the preamble, chapter V of Title 7 of the Code of Federal Regulations is amended as set forth below:
Part 505 is added to read as follows:
5 U.S.C. 301; 7 U.S.C. 3125a.
(b) Loans will be made at a flat fee of $15.00 per loaned item.
(c) Cost for replacement of lost or damaged items will be the actual cost to purchase a replacement plus a $50.00 processing fee; or if the cost cannot be determined, a flat rate of $75.00 for monographs or $150.00 for audiovisuals per item, plus a $50.00 processing fee.
(d) All services in this section will incur a billing surcharge per invoice generated in addition to the above fees which may change as vendor's charges change. This fee, currently $10.00, is billed as a direct cost recovery based on charges to the library by the billing vendor. Interlibrary loan requests submitted by participants in the ILL Fee Management (IFM) program under the Online Computer Library Center, Inc. (OCLC) will not incur the billing surcharge as their activities will not generate an invoice.
(b) Paper copies of microfilm or microfiche will be produced at a flat fee of $13.00 for requests delivered domestically and $16.00 for requests requiring delivery to a international address. This charge is for each document requested with a maximum of 50 pages per article for copyright compliance.
(c) Duplication of NAL owned microfiche will be charged a flat fee of $13.00 per each 5 microfiche duplicated or fraction thereof. Duplication of NAL owned microfilm will be charged a flat fee of $20.00 for each reel produced.
(d) Photographic services from NAL Special Collections will be charged at cost for reproduction of the photo product (slides, transparencies, etc.) plus a preparation fee of $25.00 per half hour or fraction thereof.
(e) All services in this section will incur a billing surcharge, currently $10.00, per invoice generated in addition to the above fees. This fee is a direct cost recovery based on charges to the library by the billing vendor and is subject to change. Interlibrary loan requests submitted by participants in the IFM program on OCLC will not incur the billing surcharge as their activities will not generate an invoice.
Agricultural Marketing Service, USDA.
Interim final rule with request for comments.
This rule increases the quantity of Class 3 (Native) spearmint oil produced in the Far West that handlers may purchase from, or handle for, producers during the 1999-2000 marketing year. This interim final rule increases the Native spearmint oil salable quantity by 102,311 pounds from 1,125,755 pounds to 1,228,066 pounds, and the allotment percentage by 5 percent from 55 percent to 60 percent. The Spearmint Oil Administrative Committee (Committee), the agency responsible for local administration of the marketing order for spearmint oil produced in the Far West, recommended this rule to avoid extreme fluctuations in supplies and prices and thus help to maintain stability in the Far West spearmint oil market.
Effective on February 11, 2000 through May 31, 2000; comments received by April 10, 2000 will be considered prior to issuance of a final rule.
Interested persons are invited to submit written comments concerning this rule. Comments must be sent to the Docket Clerk, Fruit and Vegetable Programs, AMS, USDA, room 2525-S, P.O. Box 96456, Washington, DC 20090-6456; Fax: (202) 720-5698, or E-mail: moab.docketclerk@usda.gov. All comments should reference the docket number and the date and page number of this issue of the
Robert J. Curry, Northwest Marketing Field Office, Marketing Order Administration Branch, Fruit and Vegetable Programs, AMS, USDA, 1220 SW Third Avenue, room 369, Portland, Oregon 97204-2807; telephone: (503) 326-2724, Fax: (503) 326-7440; or George Kelhart, Technical Advisor, Marketing Order Administration Branch, Fruit and Vegetable Programs, AMS, USDA, room 2525-S, P.O. Box 96456, Washington, DC 20090-6456; telephone: (202) 720-2491, Fax: (202) 720-5698.
Small businesses may request information on complying with this regulation by contacting Jay Guerber, Marketing Order Administration Branch, Fruit and Vegetable Programs, AMS, USDA, room 2525-S, P.O. Box 96456, Washington, DC 20090-6456; telephone (202) 720-2491; Fax: (202) 720-5698, or E-mail: Jay.Guerber@usda.gov.
This rule is issued under Marketing Order No. 985 (7 CFR Part 985), regulating the handling of spearmint oil produced in the Far West (Washington, Idaho, Oregon, and designated parts of Nevada, and Utah), hereinafter referred to as the “order.” This order is effective under the Agricultural Marketing Agreement Act of 1937, as amended (7 U.S.C. 601-674), hereinafter referred to as the “Act.”
The Department of Agriculture (Department) is issuing this rule in conformance with Executive Order 12866.
This rule has been reviewed under Executive Order 12988, Civil Justice Reform. Under the provisions of the marketing order now in effect, salable quantities and allotment percentages may be established for classes of spearmint oil produced in the Far West. This rule increases the quantity of Native spearmint oil produced in the Far West that may be purchased from or handled for producers by handlers during the 1999-2000 marketing year, which ends on May 31, 2000. This rule will not preempt any State or local laws, regulations, or policies, unless they present an irreconcilable conflict with this rule.
The Act provides that administrative proceedings must be exhausted before parties may file suit in court. Under section 608c(15)(A) of the Act, any handler subject to an order may file with the Secretary a petition stating that the order, any provision of the order, or any obligation imposed in connection with the order is not in accordance with law and request a modification of the order or to be exempted therefrom. A handler is afforded the opportunity for a hearing on the petition. After the hearing the Secretary would rule on the petition. The Act provides that the district court of the United States in any district in which the handler is an inhabitant, or has his or her principal place of business, has jurisdiction to review the Secretary's ruling on the petition, provided an action is filed not later than 20 days after the date of the entry of the ruling.
The U.S. production of spearmint oil is concentrated in the Far West, primarily Washington, Idaho, and Oregon (part of the area covered by the order). Spearmint oil is also produced in the Midwest. The production area covered by the order normally accounts for approximately 63 percent of the annual U.S. production of Scotch spearmint oil and approximately 93 percent of the annual U.S. production of Native spearmint oil.
This rule increases the quantity of Native spearmint oil that handlers may purchase from, or handle for, producers during the 1999-2000 marketing year, which ends on May 31, 2000. This rule increases the salable quantity from 1,125,755 pounds to 1,128,066 pounds and the allotment percentage from 55 percent to 60 percent for Native spearmint oil for the 1999-2000 marketing year.
The salable quantity is the total quantity of each class of oil that handlers may purchase from, or handle for, producers during a marketing year. The salable quantity calculated by the Committee is based on the estimated trade demand. The total salable quantity is divided by the total industry allotment base to determine an allotment percentage. Each producer is allotted a share of the salable quantity by applying the allotment percentage to the producer's individual allotment base for the applicable class of spearmint oil.
The initial salable quantity and allotment percentages for Scotch and Native spearmint oils for the 1999-2000 marketing year were recommended by the Committee at its October 7, 1998, meeting. The Committee recommended salable quantities of 1,199,190 pounds and 1,125,755 pounds, and allotment percentages of 65 percent and 55 percent, respectively, for Scotch and Native spearmint oils. A proposed rule was published in the November 17, 1998, issue of the
Pursuant to authority contained in sections 985.50, 985.51, and 985.52 of the order, at its January 13, 2000, meeting, the Committee unanimously recommended that the allotment percentage for Native spearmint oil for the 1999-2000 marketing year be increased by 5 percent from 55 percent to 60 percent. Taking into consideration the following discussion on adjustments to the Native spearmint oil salable quantity, the 1999-2000 marketing year salable quantity of 1,125,755 pounds will therefore be increased to 1,228,066 pounds.
The original total industry allotment base for Native spearmint oil for the 1999-2000 marketing year was established at 2,046,828 pounds and was revised during the year to 2,046,214 pounds to reflect a loss of 614 pounds of base due to non-production of some producers' total annual allotments. When the revised total allotment base of 2,046,214 pounds is applied to the originally established allotment percentage of 55, the 1999-2000 marketing year salable quantity of 1,125,755 pounds is effectively modified to 1,125,418 pounds.
By increasing the salable quantity and allotment percentage, this rule makes an additional amount of Native spearmint oil available by releasing such oil from the reserve pool. When applied to each individual producer, the 5 percent allotment percentage increase allows each producer to take up to an amount equal to 5 percent of their allotment base from their Native spearmint oil reserve. If a producer does not have any reserve pool oil, or has less than 5 percent of their allotment base in the reserve pool, the increase in allotment percentage will actually make less than such amount available to the market. Currently, producers receiving 10,020 pounds of additional allotment through this increase do not have any Native spearmint oil in reserve. Thus, rather than 102,311 additional pounds, this action effectively makes an additional 92,291 pounds of Native spearmint oil available to the market.
The following table summarizes the Committee recommendation:
(A) Estimated 1999-2000 Allotment Base—2,046,828 pounds. This is the figure the original 1999-2000 salable quantities and allotment percentages were based on.
(B) Revised 1999-2000 Allotment Base—2,046,214 pounds. This is 614
(C) Initial 1999-2000 Allotment Percentage—55 percent.
(D) Initial 1999-2000 Salable Quantity—1,125,755 pounds. This figure is 55 percent of 2,046,828 pounds.
(E) Initial Adjustment to the 1999-2000 Salable Quantity—1,125,418 pounds. This figure reflects the salable quantity available after the beginning of the 1999-2000 marketing year due to the 614 pound reduction in the industry allotment base to 2,046,214 pounds.
(F) Increase in Allotment Percentage—5 percent. This percentage increase was recommended by the Committee at its January 13, 2000, meeting.
(G) Revised 1999-2000 Allotment Percentage—60 percent. This figure is derived by adding the 5 percent increase to the initial 1999-2000 allotment percentage of 55 percent.
(H) Computed Increase in the 1999-2000 Salable Quantity—102,311 pounds. This is the product of the revised 1999-2000 allotment base of 2,046,214 and the 5 percent increase.
(I) Revised 1999-2000 Salable Quantity—1,228,066 pounds. This figure is 60 percent of the estimated 1999-2000 allotment base of 2,046,214 pounds.
(J) Effective Increase in the 1999-2000 Salable Quantity—92,291 pounds. This figure represents the amount of Native spearmint oil actually being made available by this action based on the adjustments described herein.
In making this latest recommendation, the Committee considered all available information on supply and demand. The 1999-2000 marketing year began on June 1, 1999. Handlers have indicated that with this action, the available supply of both Scotch and Native spearmint oils appears adequate to meet anticipated demand through May 31, 2000. Without the increase, the Committee believes the industry would not be able to meet market needs. As of January 13, 2000, approximately 25,000 pounds of Native spearmint oil was available for market. The average for sales of Native spearmint oil from January 1 to May 31 over the past 5 years is 208,994 pounds. However, average sales for the period June 1 through December 31 for the past 5 years are 953,978 pounds. The Far West spearmint oil industry has sold 1,206,290 pounds of Native spearmint oil through January 13, 2000. Therefore, based on past history the industry may require at least about 40,000 additional pounds of Native to meet the five year average annual market demand. This action has the effect of adding 92,291 pounds of Native spearmint oil to the amount available for market, bringing the total available supply for the period January 13 through May 31, 2000, up to approximately 117,300 pounds.
The Department, based on its analysis of available information, has determined that the salable quantity and allotment percentage for Native spearmint oil for the 1999-2000 marketing year should be increased to 1,228,066 and 60 percent, respectively.
This rule relaxes the regulation of Native spearmint oil and will allow growers to meet market needs and improve returns. In conjunction with the issuance of this rule, the Committee's revised marketing policy statement for the 1999-2000 marketing year has been reviewed by the Department. The Committee's marketing policy statement, a requirement whenever the Committee recommends implementing volume regulations or recommends revisions to existing volume regulations, meets the intent of section 985.50 of the order. During its discussion of revising the 1999-2000 salable quantities and allotment percentages, the Committee considered: (1) The estimated quantity of salable oil of each class held by producers and handlers; (2) the estimated demand for each class of oil; (3) prospective production of each class of oil; (4) total of allotment bases of each class of oil for the current marketing year and the estimated total of allotment bases of each class for the ensuing marketing year; (5) the quantity of reserve oil, by class, in storage; (6) producer prices of oil, including prices for each class of oil; and (7) general market conditions for each class of oil, including whether the estimated season average price to producers is likely to exceed parity. Conformity with the Department's “Guidelines for Fruit, Vegetable, and Specialty Crop Marketing Orders” has also been reviewed and confirmed.
The increase in the Native spearmint oil salable quantity and allotment percentage allows for anticipated market needs for this class of oil. In determining anticipated market needs, consideration by the Committee was given to historical sales, and changes and trends in production and demand.
Pursuant to requirements set forth in the Regulatory Flexibility Act (RFA), the AMS has considered the economic impact of this action on small entities. Accordingly, the AMS has prepared this initial regulatory flexibility analysis.
The purpose of the RFA is to fit regulatory actions to the scale of business subject to such actions in order that small businesses will not be unduly or disproportionately burdened. Marketing orders issued pursuant to the Act, and rules issued thereunder, are unique in that they are brought about through group action of essentially small entities acting on their own behalf. Thus, both statutes have small entity orientation and compatibility.
There are 7 spearmint oil handlers subject to regulation under the marketing order and approximately 119 producers of Scotch spearmint oil and 105 producers of Native spearmint oil in the regulated production area. Small agricultural service firms are defined by the Small Business Administration (SBA) (13 CFR 121.201) as those having annual receipts of less than $5,000,000, and small agricultural producers have been defined as those whose annual receipts are less than $500,000.
Based on the SBA's definition of small entities, the Committee estimates that 2 of the 7 handlers regulated by the order could be considered small entities. Most of the handlers are large corporations involved in the international trading of essential oils and the products of essential oils. In addition, the Committee estimates that 25 of the 119 Scotch spearmint oil producers and 7 of the 105 Native spearmint oil producers would be classified as small entities under the SBA definition. Thus, a majority of handlers and producers of Far West spearmint oil may not be classified as small entities.
The Far West spearmint oil industry is characterized by producers whose farming operations generally involve more than one commodity, and whose income from farming operations is not exclusively dependent on the production of spearmint oil. Crop rotation is an essential cultural practice in the production of spearmint oil for weed, insect, and disease control. A normal spearmint oil producing operation would have enough acreage for rotation such that the total acreage required to produce the crop would be about one-third spearmint and two-thirds rotational crops. An average spearmint oil producing farm would thus have to have considerably more acreage than would be planted to spearmint during any given season. To remain economically viable with the added costs associated with spearmint oil production, most spearmint oil producing farms would fall into the category of large businesses.
Small spearmint oil producers represent a minority of farming operations and are more vulnerable to market fluctuations. Such small farmers
Based on projections available at the meeting, the Committee considered alternatives to the 5 percent increase. The Committee not only considered leaving the salable quantity and allotment percentage unchanged, but also looked at various increases ranging from 1 percent to 15 percent. The Committee reached its recommendation to increase the salable quantity and allotment percentage for Native spearmint oil after careful consideration of all available information, and believes that the level recommended will achieve the objectives sought. Without the increase, the Committee believes the industry would not be able to meet market needs. As of January 13, 2000, approximately 25,000 pounds of Native spearmint oil was available for market. The past 5-year average of Native spearmint oil sales from January 1 to May 31 is 208,994 pounds, whereas the 5-year average for the period June 1 through December 31 is 953,978 pounds. The Far West spearmint oil industry has sold 1,206,290 pounds of Native spearmint oil this season through January 13, 2000. Therefore, based on historical sales the industry may require about 40,000 additional pounds of Native oil to meet the five-year average annual market demand. This action has the effect of adding 92,291 pounds of Native spearmint oil to the amount available for market, bringing the total available supply for the period January 13 through May 31, 2000, up to approximately 117,300 pounds.
Annual salable quantities and allotment percentages have been issued for both classes of spearmint oil since the order's inception. Reporting and recordkeeping requirements have remained the same for each year of regulation. Accordingly, this action will not impose any additional reporting or recordkeeping requirements on either small or large spearmint oil producers and handlers. All reports and forms associated with this program are reviewed periodically in order to avoid unnecessary and duplicative information collection by industry and public sector agencies. The Department has not identified any relevant Federal rules that duplicate, overlap, or conflict with this rule.
Finally, the Committee's meeting was widely publicized throughout the spearmint oil industry and all interested persons were invited to attend and participate on all issues. Interested persons are also invited to submit information on the regulatory and informational impacts of this action on small businesses.
A small business guide on complying with fruit, vegetable, and specialty crop marketing agreements and orders may be viewed at the following website: http://www.ams.usda.gov/fv/moab.html. Any questions about the compliance guide should be sent to Jay Guerber at the previously mentioned address in the
After consideration of all relevant matter presented, including that contained in the prior proposed and final rules in connection with the establishment of the salable quantities and allotment percentages for Scotch and Native spearmint oils for the 1999-2000 marketing year, the Committee's recommendation and other available information, it is found that to revise section 985.218 (42 FR 2799) to change the salable quantity and allotment percentage for Native spearmint oil, as hereinafter set forth, will tend to effectuate the declared policy of the Act.
This rule invites comments on a revision to the salable quantity and allotment percentage for Native spearmint oil for the 1999-2000 marketing year. A 60-day comment period is provided. Any comments received will be considered prior to finalization of this rule.
Pursuant to 5 U.S.C. 553, it is also found and determined upon good cause that it is impracticable, unnecessary, and contrary to the public interest to give preliminary notice prior to putting this rule into effect and that good cause exists for not postponing the effective date of this rule until 30 days after publication in the
Marketing agreements, Oils and fats, Reporting and recordkeeping requirements, Spearmint oil.
7 U.S.C. 601-674.
[
The salable quantity and allotment percentage for each class of spearmint oil during the marketing year beginning on June 1, 1999, shall be as follows:
(b) Class 3 (Native) oil—a salable quantity of 1,288,066 pounds and an allotment percentage of 60 percent.
Board of Governors of the Federal Reserve System.
Final rule.
The Board of Governors has amended its Regulation A on Extensions of Credit by Federal Reserve Banks to reflect its approval of an increase in the basic discount rate at each Federal Reserve Bank. The Board acted on requests submitted by the Boards of Directors of the twelve Federal Reserve Banks.
The amendments to part 201 (Regulation A) were effective February
Jennifer J. Johnson, Secretary of the Board, at (202) 452-3259; for users of Telecommunications Device for the Deaf (TDD), contact Diane Jenkins, at (202) 452-3544, Board of Governors of the Federal Reserve System, 20th and C Streets NW, Washington, D.C. 20551.
Pursuant to the authority of sections 10(b), 13, 14, 19, et al., of the Federal Reserve Act, the Board has amended its Regulation A (12 CFR part 201) to incorporate changes in discount rates on Federal Reserve Bank extensions of credit. The discount rates are the interest rates charged to depository institutions when they borrow from their district Reserve Banks.
The “basic discount rate” is a fixed rate charged by Reserve Banks for adjustment credit and, at the Reserve Banks’ discretion, for extended credit. In increasing the basic discount rate from 5 percent to 5.25 percent, the Board acted on requests submitted by the Boards of Directors of the twelve Federal Reserve Banks. The new rates were effective on the dates specified below. The 25-basis-point increase in the discount rate was associated with a similar increase in the federal funds rate approved by the Federal Open Market Committee and announced at the same time.
The Board and the Reserve Banks remain concerned that over time increases in demand will continue to exceed the growth in potential supply, even after taking account of the pronounced rise in productivity growth. Such trends could foster inflationary imbalances that would undermine the economy’s record economic expansion.
Against the background of their long-run goals of price stability and sustainable economic growth and of the information currently available, the Board and the Reserve Banks believe the risks are weighted mainly toward conditions that may generate heightened inflation pressures in the foreseeable future.
Pursuant to section 605(b) of the Regulatory Flexibility Act (5 U.S.C. 605(b)), the Board certifies that the change in the basic discount rate will not have a significant adverse economic impact on a substantial number of small entities. The rule does not impose any additional requirements on entities affected by the regulation.
The provisions of 5 U.S.C. 553(b) relating to notice and public participation were not followed in connection with the adoption of the amendment because the Board for good cause finds that delaying the change in the basic discount rate in order to allow notice and public comment on the change is impracticable, unnecessary, and contrary to the public interest in fostering price stability and sustainable economic growth.
The provisions of 5 U.S.C. 553(d) that prescribe 30 days prior notice of the effective date of a rule have not been followed because section 553(d) provides that such prior notice is not necessary whenever there is good cause for finding that such notice is contrary to the public interest. As previously stated, the Board determined that delaying the changes in the basic discount rate is contrary to the public interest.
Banks, banking, Credit, Federal Reserve System.
12 U.S.C. 343
The rates for adjustment credit provided to depository institutions under § 201.3(a) are:
By order of the Board of Governors of the Federal Reserve System, February 4, 2000.
Federal Aviation Administration, DOT.
Final rule.
This amendment adopts a new airworthiness directive (AD), applicable to General Electric Company (GE) CF6-80C2 series turbofan engines. This amendment requires removal from service of affected fan mid shafts prior to reaching a new, lower cyclic life limit, and replacement with serviceable parts. This amendment is prompted by recent component test data. The actions specified by this AD are intended to prevent fan mid shaft failure, which could result in an uncontained engine failure and damage to the aircraft.
April 10, 2000.
The service information referenced in this AD may be obtained from General Electric Company via Lockheed Martin Technology Services, 10525 Chester Road, Suite C, Cincinnati, Ohio 45215, telephone 513-672-8400, fax 513-672-8422. This information may be examined at the Federal Aviation Administration (FAA), New England Region, Office of the Regional Counsel, 12 New England Executive Park, Burlington, MA.
William S. Ricci, Aerospace Engineer, Engine Certification Office, FAA, Engine and Propeller Directorate, 12 New England Executive Park, Burlington, MA 01803-5299; telephone 781-238-7742, fax 781-238-7199.
A proposal to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) to include an airworthiness directive (AD) that is applicable to General Electric Company (GE) CF6-80C2 series turbofan engines was published in the
Interested persons have been afforded an opportunity to participate in the making of this amendment. Due consideration has been given to the comments received.
Two commenters concur with the rule as proposed.
After careful review of the available data, including the comments noted above, the FAA has determined that air safety and the public interest require the adoption of the rule as proposed.
There are approximately 1,796 engines of the affected design in the worldwide fleet. The FAA estimates that 230 engines installed on aircraft of US registry will be affected by this AD and that required parts will cost approximately $90,085 per engine. Based on these figures, the total cost impact of the AD on US operators is estimated to be $20,719,600.
The regulations adopted herein will not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this final rule does not have federalism implications under Executive Order (EO) 13132.
For the reasons discussed above, I certify that this action (1) Is not a “significant regulatory action” under EO 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A final evaluation has been prepared for this action and it is contained in the Rules Docket. A copy of it may be obtained from the Rules Docket at the location provided under the caption
Air transportation, Aircraft, Aviation safety, Safety.
Accordingly, pursuant to the authority delegated to me by the Administrator, the Federal Aviation Administration amends part 39 of the Federal Aviation Regulations (14 CFR part 39) as follows:
49 U.S.C. 106(g), 40113, 44701.
This airworthiness directive (AD) applies to each engine identified in the preceding applicability provision, regardless of whether it has been modified, altered, or repaired in the area subject to the requirements of this AD. For engines that have been modified, altered, or repaired so that the performance of the requirements of this AD is affected, the owner/operator must request approval for an alternative method of compliance in accordance with paragraph (c) of this AD. The request should include an assessment of the effect of the modification, alteration, or repair on the unsafe condition addressed by this AD; and, if the unsafe condition has not been eliminated, the request should include specific proposed actions to address it.
To prevent fan mid shaft failure, which could result in an uncontained engine failure and damage to the aircraft, accomplish the following:
(a) Remove from service affected fan mid shafts and replace with a serviceable part, as follows:
GE CF6-80C2 Service Bulletin (SB) No. 72-958, dated December 10, 1998, contains information on this subject.
(1) For fan mid shafts that have accumulated 9,000 or more cycles-since-new (CSN) on the effective date of this AD, remove from service within 3,500 cycles-in-service (CIS) after the effective date of this AD, or prior to accumulating 15,000 CSN, whichever occurs first.
(2) For fan mid shafts that have accumulated 1,800 CSN or more, but less
(3) For fan mid shafts that have accumulated less than 1,800 CSN on the effective date of this AD, remove from service prior to accumulating 6,800 CSN.
GE CF6-80C2 SB 72-750, Revision 2, dated September 4, 1998, contains information on reworking fan mid shafts that results in changing the P/N. After that rework, this AD would not apply to engines containing the reworked fan mid shaft.
(b) Except for the provisions of paragraph (a) of this AD, no fan mid shafts, P/N 9326M74P04 or 9326M74P05, may remain in service beyond 6,800 CSN.
(c) An alternative method of compliance or adjustment of the compliance time that provides an acceptable level of safety may be used if approved by the Manager, Engine Certification Office (ECO). Operators shall submit their request through an appropriate FAA Principal Maintenance Inspector, who may add comments and then send it to the Manager, ECO.
Information concerning the existence of approved alternative methods of compliance with this airworthiness directive, if any, may be obtained from the ECO.
(d) Special flight permits may be issued in accordance with sections 21.197 and 21.199 of the Federal Aviation Regulations (14 CFR 21.197 and 21.199) to operate the aircraft to a location where the requirements of this AD can be accomplished.
(e) This amendment becomes effective on April 10, 2000.
Federal Aviation Administration, DOT.
Final rule.
This amendment adopts a new airworthiness directive (AD), applicable to certain Boeing Model 737-200 series airplanes that requires removal of the existing emergency floor path lighting system and replacement with an FAA-approved emergency floor path lighting system. This amendment is prompted by information indicating that the existing emergency floor path lighting system does not provide adequate lighting and cueing for safe evacuation of the airplane in the event of an emergency. The actions specified by this AD are intended to prevent such inadequate lighting and cueing, which could delay or impede the flight crew and passengers when exiting the airplane during an emergency.
March 16, 2000.
Information pertaining to this amendment may be examined at the Federal Aviation Administration (FAA), Transport Airplane Directorate, Rules Docket, 1601 Lind Avenue, SW., Renton, Washington; or at the FAA, Small Airplane Directorate, Campus Building, 1701 Columbia Avenue, Suite 2-160, College Park, Georgia.
Eugene Evans, Aerospace Engineer, ACE-116A, FAA, Small Airplane Directorate, Atlanta Aircraft Certification Office, One Crown Center, 1895 Phoenix Boulevard, suite 450, Atlanta, Georgia 30349; telephone (770) 703-6081; fax (770) 703-6097.
A proposal to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) to include an airworthiness directive (AD) that is applicable to certain Boeing Model 737-200 series airplanes was published in the
Interested persons have been afforded an opportunity to participate in the making of this amendment. Due consideration has been given to the comments received.
One commenter concurs with the proposed rule.
Another commenter requests that the compliance time be extended to six months so that it will have adequate time to integrate the affected airplanes into the maintenance cycle.
The FAA concurs. The FAA has determined that such an extension of the compliance time to within 6 months after the effective date of the AD will not adversely affect safety. The final rule has been revised accordingly.
After careful review of the available data, including the comments noted above, the FAA has determined that air safety and the public interest require the adoption of the rule with the changes previously described. The FAA has determined that these changes will neither increase the economic burden on any operator nor increase the scope of the AD.
There are approximately 40 Boeing Model 737-200 series airplanes of the affected design in the worldwide fleet. The FAA estimates that 4 airplanes of U.S. registry will be affected by this AD, that it will take approximately 12 work hours per airplane to accomplish the removal of the system, and that the average labor rate is $60 per work hour. It will take approximately 40 work hours per airplane to accomplish the required replacement with an FAA-approved system. Required parts for the replacement will cost approximately $10,000 for a new system, per airplane. Based on these figures, the cost impact of the AD on U.S. operators is estimated to be $524,800, or $13,120 per airplane.
The cost impact figure discussed above is based on assumptions that no operator has yet accomplished any of the requirements of this AD action, and that no operator would accomplish those actions in the future if this AD were not adopted.
The regulations adopted herein will not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this final rule does not have federalism implications under Executive Order 13132.
For the reasons discussed above, I certify that this action: (1) Is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT
Air transportation, Aircraft, Aviation safety, Safety.
49 U.S.C. 106(g), 40113, 44701.
This AD applies to each airplane identified in the preceding applicability provision, regardless of whether it has been otherwise modified, altered, or repaired in the area subject to the requirements of this AD. For airplanes that have been modified, altered, or repaired so that the performance of the requirements of this AD is affected, the owner/operator must request approval for an alternative method of compliance in accordance with paragraph (b) of this AD. The request should include an assessment of the effect of the modification, alteration, or repair on the unsafe condition addressed by this AD; and, if the unsafe condition has not been eliminated, the request should include specific proposed actions to address it.
To prevent inadequate lighting and cueing of the emergency floor path lighting system, which could delay or impede the flight crew and passengers when exiting the airplane during an emergency, accomplish the following:
(a) Within 6 months after the effective date of this AD, remove the existing photoluminescent emergency floor path lighting system from the airplane. Replace it with an emergency floor path lighting system in accordance with Supplemental Type Certificate ST01829AT, dated February 11, 1999, or an FAA-approved emergency floor path lighting system that is installed in accordance with a method approved by the Manager, Atlanta Aircraft Certification Office (ACO), FAA, Small Airplane Directorate.
(b) An alternative method of compliance or adjustment of the compliance time that provides an acceptable level of safety may be used if approved by the Manager, Atlanta ACO. Operators shall submit their requests through an appropriate FAA Principal Maintenance Inspector, who may add comments and then send it to the Manager, Atlanta ACO.
Information concerning the existence of approved alternative methods of compliance with this AD, if any, may be obtained from the Atlanta ACO.
(c) Special flight permits may be issued in accordance with sections 21.197 and 21.199 of the Federal Aviation Regulations (14 CFR 21.197 and 21.199) to operate the airplane to a location where the requirements of this AD can be accomplished.
(d) This amendment becomes effective on March 16, 2000.
Federal Aviation Administration (FAA), DOT.
Final rule.
This action revises the legal description of the Burlington, VT, Class C airspace area by changing the operating hours to be consistent with the current operational requirements. Specifically, the Class C airspace area will be designated effective during the specific days and hours of operation of the Burlington Tower and Approach Control facility as established in advance by a Notice to Airmen (NOTAM). The effective dates and times thereafter will be continuously published in the Airport/Facility Directory. This action will not change the actual dimensions, configuration, or operating requirements of the Burlington Class C airspace area.
February 24, 2000.
Terry Brown, Airspace and Rules Division, ATA-400, Office of Air Traffic Airspace Management, Federal Aviation Administration, 800 Independence Avenue, SW., Washington, DC 20591; telephone: (202) 267-8783.
The Burlington Airport Traffic Control Tower is reducing its hours of operation. The Burlington Class C airspace area remains an essential safety measure in support of the ongoing airport operation requirements.
On November 15, 1999, the FAA published an NPRM (64 FR 61803) that proposed to revise the legal description of the Burlington, VT, Class C airspace area by changing the operating hours to be consistent with the current operational requirements. Interested parties were invited to participate in this rulemaking proceeding by submitting comments on the proposal to the FAA. No comments objecting to the proposal were received. However, one error was found in the coordinates of the legal description in the notice for the Burlington International Airport, VT. Except for the change in the coordinates, this amendment is the same as that proposed in the notice.
This amendment to part 71 of The Federal Aviation Regulations (14 CFR part 71) revises the legal description of the Burlington Class C airspace area located at Burlington, VT. The legal description will use the operating hours for the Class C airspace area which are consistent with the current requirements. The Class C airspace area is designated effective during the specific days and hours of operation of the Burlington facility as established in advance by a NOTAM. This action is a technical amendment to the legal description and will not change the actual dimensions, configuration, or operating requirements of the Burlington Class C airspace area.
The coordinates for this airspace docket are based on North American Datum 83. Class C airspace areas are published in paragraph 4000 of FAA Order 7400.9G, dated September 1, 1999, and effective September 16, 1999, which is incorporated by reference in 14 CFR 71.1. The Class C airspace area listed in this document will be published subsequently in the Order.
The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. Therefore, this Regulation: (1) Is not a “significant regulatory action” under Executive Order 12866; (2) is not a “Significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. Since this is a routine matter that will only affect air traffic procedures and air navigation, it is certified that this proposed rule, when promulgated, will not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Act.
Airspace, Incorporation by reference, Navigation (air).
49 U.S.C. 106(g), 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959-1963 Comp., p. 389.
That airspace extending upward from the surface to and including 4,400 feet MSL within a 5-mile radius of the Burlington International Airport, and that airspace extending upward from 2,200 feet MSL to 4,400 feet MSL within a 10-mile radius of Burlington International Airport from the 360° bearing from the airport clockwise to the 180° bearing from the airport, excluding the airspace within Restricted Area R-6501; and that airspace extending upward from 1,500 feet MSL to 4,400 feet MSL within a 10-mile radius of the airport from the 180° bearing from the airport clockwise to the 360° bearing from the airport. This Class C airspace area is effective during the specific dates and times established in advance by a Notice to Airmen. The effective date and time will thereafter be continuously published in the Airport/Facility Directory.
Minerals Management Service (MMS), Interior.
Corrections to Final Regulations.
This document contains corrections to the final rule titled “Postlease Operations Safety” that was published Tuesday, December 28, 1999 (64 FR 72756). We are correcting a section title and adding a word in the section that was inadvertently omitted.
January 27, 2000.
Kumkum Ray, (703) 787-1600.
The final regulations that are the subject of these corrections supersede 30 CFR 250, subpart A, General, regulations on the effective date and affect all operators and lessees on the Outer Continental Shelf.
With respect to the corrections, the title of § 250.142 is inaccurate and the word “District” was omitted inadvertently in the section.
As published, the final regulations contain errors which may prove to be misleading and are in need of clarification.
We may approve departures to the operating requirements. You may apply for a departure by writing to the District or Regional Supervisor.
Postal Rate Commission.
Final Rule.
This rule adopts final changes in Commission rules of practice. These changes adopt certain special rules of practice on a permanent basis, make several other procedural improvements, and make minor technical corrections and conforming changes. Adoption of these rules will aid in effective administration of Commission proceedings.
February 10, 2000.
Send correspondence concerning this document to Margaret P. Crenshaw, Secretary, Postal Rate Commission, 1333 H Street NW., Suite 300, Washington, DC 20268-0001.
Stephen L. Sharfman, General Counsel, Postal Rate Commission, 1333 H Street NW., Suite 300, Washington, DC 20268-001, 202-789-6820.
Initial notice of proposed rule: 63 FR 46732 (September 2, 1998).
Supplementary notice of proposed rule: 64 FR 72622 (Dec. 28, 1999).
The Commission initiated this rulemaking to amend its rules of
Five sets of comments suggesting improvements were received. Commenters generally supported the integration of the special rules into the current rules of practice and procedure, but gave a mixed response to the possibility of electronic filing requirements. Some commenters suggested that several technical and procedural rules were outdated in light of current technology and practice. Certain “streamlining” measures also were proposed.
In order no. 1274, the Commission proposed specific changes in the rules which address the aforementioned areas of interest, as well as commenters' remarks. See order no. 1274 (64 FR 72622, Dec. 28, 1999). Proposed modifications included the incorporation of most of the special rules and minor updates of several current rules to reflect internal Commission changes since the rules were first promulgated. The proposed rules generally have been tested in numerous Commission proceedings, and have proven to be effective and efficient.
The Commission narrowed the scope of the rulemaking by limiting its consideration to Subpart A—Rules of General Applicability (rules 1-43). Thus, to the extent commenters' remarks encompassed Subparts B through F (rules 51-92), which include regulations pertaining to the initiation of dockets, they were deferred for consideration to a later rulemaking.
Three sets of comments were received in response to order no. 1274. The comments are available for public inspection in the Commission's docket section, and can be accessed electronically at www.prc.gov. The comments essentially support the proposed revisions as reasonable and appropriate. However, there are some concerns with regard to the revised filing deadlines for various pleadings in Commission proceedings. Also, commenters suggest that clarification of some rules may be necessary. Finally, several minor technical amendments to the Commission's rules are proposed. Each comment will be addressed in turn.
One commenter maintains that the shortened deadline for objections to discovery requests which the Commission proposes in rules 26(c), 27(c) and 28(c) is too severe and may result in “increased motions practice and other inefficiencies.” According to the commenter, a backlog of responses to interrogatories during extensive discovery in an omnibus rate case has been experienced frequently under the current 10-day deadline. This situation would be exacerbated if the period for responses was shortened. Moreover, the proposed 7-day deadline does not reflect incorporation of the special rules, but rather is an untested proposal.
The commenter presents a valid argument. The shortened time period for objections to discovery was proposed in conjunction with the abbreviated pleading periods prescribed by the special rules. However, the Commission recognizes that the special rules have been tested and proven successful in numerous Commission proceedings, whereas the proposal at issue is untried. As such, the Commission will not implement this shortened deadline as a final rule, and the current 10-day deadline will remain in effect. The proposed abbreviated deadline may instead be considered for implementation as a special rule during the docket no. R2000-1 omnibus rate case or other Commission proceeding.
One commenter suggests that the period for participants to file motions to compel responses to discovery be shortened from the current 14 days to 10 days. The commenter argues that the abbreviated time period will effectively reduce those outstanding discovery disputes pending against a participant both during and after the hearing stage of its case-in-chief. Further, the shortened deadline would be consistent with the current, somewhat analogous 10-day period for response to a motion provided by rule 21(b).
The Commission declines to modify rules 26(d), 27(d) and 28(d) as proposed by the commenter. While the commenter's proposal has merit, the shortened time frame has never been tested as a special rule to gauge its effectiveness. The Commission therefore would be inclined to direct that the proposal first be applied in a particular case to determine its feasibility prior to any promulgation of a rule.
One commenter argues against the adoption of the Commission's proposal to shorten the deadline for responses to motions from 10 to seven days. According to the commenter, this abbreviated period is not a special rule and has not been tested in the course of a major rate proceeding. The commenter maintains that the shortened deadline would be difficult to meet and would likely result in numerous filings for extension of time to reply.
While not a special rule, the abbreviated time frame nonetheless has been imposed in a number of instances where motions have been seriously contested, and met with success. Additionally, the special rules require responses to motions to compel discovery in seven days, and applying this time period to all motions practice will eliminate confusion. In light of these considerations, the Commission is not persuaded by the commenter's arguments. The Commission's proposal will be implemented.
One commenter notes that the Commission did not incorporate the special rule addressing exhibits in its revised rules. That special rule specifies what information must be included in each exhibit, such as cross-references
The Commission agrees that the special rule on exhibits merits inclusion in the rules of practice and procedure. That rule was not proposed for incorporation in order no. 1274 based on the Commission's assessment that the current rules and the revised rule on library references sufficiently addressed the filing of exhibits. See order no. 1273 (64 FR 67487, Dec. 2, 1999). However, it is possible that the special rule on exhibits would provide more comprehensive guidance on the matter. As suggested, this special rule is incorporated into current rule 31(b), documentary material.
One commenter questions whether it is the intention of the Commission to amend rule 10 to allow pleadings to be filed either in hardcopy form or on computer diskettes on a document-by-document basis.
The proposed amendment to rule 10 does allow participants to select the medium of filing on a document-by-document basis. Under the proposed rule, a participant is not required to select only one form of filing for all of that participant's documents in a given proceeding.
Under rule 10, any participant filing a hardcopy document must present an original and 24 copies of the document. One commenter proposes that the number of required hard copies be reduced, given the availability of such documents on the Commission's web site and the potential time savings associated with a reduced filing requirement.
The Commission declines to amend rule 10 as requested, but notes that an alternative option was proposed by the Commission in order no. 1274. The proposed rule 10 allows for the electronic filing of documents, with a reduced number of hard copies. Thus, participants may submit a filing on computer diskette (in compliance with rule 10(c) specifications), accompanied by only one printed original and three hard copies of that filing.
One commenter suggests that Commission rule 12(d) (service list) be modified to designate the service list on the Commission's web site as the current service list for effective service of documents. Such a modification would decrease the likelihood of participants utilizing out-of-date service lists, as is possible with reliance on a hardcopy service list, particularly in complex, multi-party cases.
The Commission finds this proposal reasonable, and will so amend rule 12(d). Each participant is responsible for ensuring that its listing on the Commission's web site (www.prc.gov) is accurate, and should promptly notify the Commission of any errors.
The Postal Service suggests that rule 12(e), which describes the method of service of documents, be amended to include the Postal Service's street address. The Commission finds this proposal reasonable, and therefore amends rule 12(e) to read, in relevant part, “. . . Chief Counsel, Rates and Classification, U.S. Postal Service, 475 L'Enfant Plaza, SW., Room 6536, Washington, DC 20260-1137.”
One commenter notes that the current rule 18 (nature of proceedings) essentially allows participants the right to request a hearing without specifying the grounds for the request. In this regard, rule 18 is inconsistent with other Commission rules which require that the underlying purpose for a hearing request be cited. The commenter suggests that the phrase “Except as otherwise provided in these rules” be added to rule 18 to eliminate this inconsistency.
The Commission is in favor of eliminating any perception of inconsistency in its rules of practice and procedure. To this end, rule 18(a) (proceedings to be set for hearing) will be modified as proposed.
A commenter suggests that language be added to the rule to better signal the reader that the deadline imposed for responses to motions to strike, in the new rule 21(c), varies from the deadlines otherwise imposed in rule 21.
The Commission finds no compelling reason to add such language to rule 21(b). In the first instance, the same 7-day day deadline is imposed for responses to motions to strike in rule 21(c) and for answers to motions in rule 21(b). Furthermore, the potential for different deadlines for responses already is highlighted, as the revised rule 21(b) provides, in relevant part: “Within seven days after a motion is filed, or such other period as the rules provide or the Commission or presiding officer may fix, any participant may file and serve an answer. . . .”
One commenter suggests that the new rule 25 be renumbered as “25a,” thereby eliminating the need to renumber the current discovery rules. In this manner, confusion regarding the renumbered rules may be avoided in future cases, when the rules pertaining to discovery are researched, and past Commission documents referring to the current rule numbers are cited.
While the Commission understands this concern, it declines to act on this suggestion, as the
The proposed rule 25 provides, in relevant part, that “[d]iscovery requests of this nature are permissible for the purpose of the development of rebuttal testimony and may be made up to 20 days prior to the filing date for final rebuttal testimony.” One commenter suggests that the Commission's intent to limit the extended discovery period for
It is agreed that modification of rule 25 as suggested is consistent with the intent of the rule and Commission precedent. The Commission therefore modifies rule 25 to read as follows, in relevant part: “Discovery requests of this nature are permissible only for the purpose of the development of rebuttal testimony and may be made up to 20 days prior to the filing date for final rebuttal testimony.”
Several minor technical amendments to the Commission's rules of practice and procedure are now made. In rule 12(d), the phrase “by each participating with the address” is changed “by each participant with the address.” In rule 12(e), which provides for the method of service of documents in Commission proceedings, the word “persons” is changed to “individuals” to conform with the inserted special rules. In rule 26(c), the phrase “service of interrogatories” is substituted for the phrase “the request for production,” as that rule addresses interrogatories for the purpose of discovery. In rule 26(g), the word “party” is changed to “participant,” in accordance with Commission terminology. Likewise, in rule 27(c), all references to “party” are changed to “participant.” In rule 27(e), “[s]uch compelled documents or things shall be made available to the participants making the motion * * *” is changed to “[s]uch compelled documents or things shall be made available to the participant making the motion * * *” In rule 30(e)(1), the phrase “including the Postal Service” is deleted, as the term “participant” used in the sentence in question encompasses the Postal Service. Finally, the Commission notes that a minor typographical error and some superfluous text in order no. 1274 which was highlighted by a commenter was, in fact, corrected in the associated
For the reasons discussed above, the Commission hereby amends Subpart A of its rules of practice and procedure as set forth in the attachment to this order. [Note: material in the attachment appears below, conformed to Office of the Federal Register style requirements.]
The first ordering paragraph states that the Commission adopts the provisions set out in the attachment as the final rules amending 39 CFR 3001.1-43. The second paragraph states that the rules are effective upon publication in the
Administrative practice and procedure, Postal Service.
39 U.S.C. 404(b); 3603, 3622-24, 3661, 3662, 3663.
This part shall be referred to as the “rules of practice.” Each section, paragraph, or subparagraph shall include only the numbers and letters to the right of the decimal point. For example, “3001.24
(e)
(q)
(d)
(b)
a. Redesignate paragraph (c) as (d),
b. Revise redesignated paragraph (d); and
c. Add new paragraph (c) to read as follows:
(c)
(d)
a. Revise paragraph (b),
b. Revise paragraph (d), and
c. Revise paragraph (e) to read as follows:
(b)
(d)
(e)
(a)
In any proceeding noticed for a proceeding on the record pursuant to § 3001.17(a) the Commission shall give due notice of any prehearing conference or hearing by including the time and place of the conference or hearing in the notice of proceeding or by subsequently issuing a notice of prehearing conference or hearing. Such notice of prehearing conference or hearing shall give the title and docket designation of the proceeding, a reference to the original notice of proceeding and the date of such notice, and the time and place of the conference or hearing. Such notice shall be published in the
(a)
Notwithstanding the provisions of § 3001.20, any person may appear as a limited participator in any case that is noticed for a proceeding pursuant to § 3001.17(a), in accordance with the following provisions;
a. Revise paragraph (b), and
b. Add new paragraph (c) to read as follows:.
(b)
(c)
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(a)
(b)
(c)
(d)
(e)
(a)
(b)
(c)
(d)
(e)
(a) Rules 26 through 28 allow discovery reasonably calculated to lead to admissible evidence during a noticed proceeding. Generally, discovery against a participant will be scheduled to end prior to the receipt into evidence of that participant's direct case. An exception to this procedure shall operate in all proceedings brought under 39 U.S.C. 3622, 3623, 3661 and 3662 when a participant needs to obtain information (such as operating procedures or data) available only from the Postal Service. Discovery requests of this nature are permissible only for the purpose of the development of rebuttal testimony and may be made up to 20 days prior to the filing date for final rebuttal testimony.
(b) The discovery procedures set forth in rules 26 through 28 are not exclusive. Participants are encouraged to engage in informal discovery whenever possible to clarify exhibits and testimony. The results of these efforts may be introduced into the record by stipulation, by supplementary testimony or exhibit, by presenting selected written interrogatories and answers for adoption by a witness at the hearing, or by other appropriate means. In the interest of reducing motion practice, parties also are expected to use informal means to clarify questions and to identify portions of discovery requests considered overbroad or burdensome.
(c) If a participant or an officer or agent of a participant fails to obey an order of the Commission or the presiding officer to provide or permit discovery pursuant to §§ 3001.26 to 3001.28, the Commission or the presiding officer may make such orders in regard to the failure as are just, and among others, may direct that the matters regarding which the order was made or any other designated facts shall be taken to be established for the purposes of the proceeding in accordance with the claim of the participants obtaining the order, or prohibit the disobedient participant from introducing designated matters in evidence, or strike the evidence, complaint or pleadings or parts thereof.
(e)(1)
(2)
(3)
a. Revise paragraph (b)(1),
b. Revise paragraph (c),
c. Revise paragraph (e), and
d. Revise paragraph (f).
e. Revise paragraphs (k)(3)(i)(
(b)
(c)
(e)
(f)
(k) * * *
(3) * * *
(i) * * *
(
(
(
(
(4)
a. Revise paragraphs (e)(4) introductory text and (e)(4)(i),
b. Revise paragraph (g)(1)(iii), and
c. Revise paragraph (g)(2)(iii).
(e) * * *
(4) The public announcement required by this section may consist of the Secretary:
(i) Publicly posting a copy of the document in the office of the Secretary of the Commission at 1333 H Street, NW., Suite 300, Washington, DC 20268-0001;
(g) * * *
(1) * * *
(iii) Ten copies of such requests must be received by the office of the Secretary no later than three working days after the issuance of the notice of meeting to which the request pertains. Requests received after that time will be returned to the requester with a statement that the request was untimely received and that copies of any nonexempt portions of the transcript or minutes for the meeting in question will ordinarily be available in the office of the Secretary 10 working days after the meeting.
(2) * * *
(iii) Ten copies of such requests should be filed with the office of the Secretary as soon as possible after the issuance of the notice of meeting to which the request pertains. However, a single copy of the request will be accepted. Requests to close meetings must be received by the office of the Secretary no later than the time scheduled for the meeting to which such a request pertains.
Federal Communications Commission.
Final rule.
This document denies Petitions for Reconsideration of the Report and Order in this proceeding. It reaffirms the previously established fee of five percent of gross revenues received from feeable ancillary or supplementary services provided by DTV stations. It also reaffirms the conclusion that home shopping, infomercial, and direct marketing services are not feeable.
January 15, 1999.
Mania Baghdadi, Policy and Rules Division, Mass Media Bureau (202) 418-2120.
This is a summary of the Commission's Memorandum Opinion and Order, (“
1. In our Report and Order (“
2. The National Association of Broadcasters and the Association for Maximum Service Television have filed a joint petition (the “NAB/MSTV Petition”) asking us to set the fee at two percent of gross revenues rather than five percent. The Office of Communication Inc. of the United Church of Christ, the Benton Foundation, the Center for Media Education, the Civil Rights Forum and Media Access Project have filed a joint petition (the “UCC,
3. Pursuant to the 1996 Act, the Commission has assigned each existing broadcast television station an additional channel to convert to digital technology. We are requiring broadcasters to provide on their DTV bitstream at least one over-the-air video program signal at no direct charge to viewers. 47 CFR 73.624(b). Aside from this requirement, we have given broadcasters great flexibility in the services they provide over their DTV bitstream. They may offer a wide range of ancillary or supplementary services such as computer software distribution, data transmission, teletext, interactive materials, aural messages, paging services, audio signals, and subscription video.
4. The 1996 Act requires broadcasters to pay a fee to the U.S. Treasury to the extent they use their DTV bitstream to provide ancillary or supplementary services—
(A) For which the payment of a subscription fee is required in order to receive such services, or
(B) For which the licensee directly or indirectly receives compensation from a third party in return for transmitting material furnished by such a third party (other than commercial advertisements used to support broadcasting for which a subscription fee is not required). 47 U.S.C. 336(e)(1).
The 1996 Act directed the Commission to establish a program to assess and collect this fee based on the following three objectives:
• “To recover for the public a portion of the value of the public spectrum resource made available for such commercial use”;
• “To avoid unjust enrichment through the method employed to permit such uses of that resource”;
• To “recover for the public an amount that, to the extent feasible, equals but does not exceed (over the term of the license) the amount that would have been recovered had such services been licensed pursuant to [the competitive bidding process.]” 47 U.S.C. 336(e)(2).
5. In the
6. NAB/MSTV argue that we failed to consider two studies they submitted that they believe call for a fee of two percent of gross revenues rather than five percent. The first study, prepared by Jerry Hausman, purports to establish “the low and declining value of comparable spectrum,” and also that digital ancillary or supplementary services “face significant business and technological uncertainty.” The second study, prepared by Kent Anderson, describes several surveys of technology licensing fees in the private sector. The Association of Local Television Stations (“ALTV”) submitted comments supporting the NAB/MSTV Petition. The National Cable Television Association (“NCTA”) filed an opposition to the petition.
7. Contrary to NAB/MSTV's suggestion, we did consider the two studies in reaching our decision in the
8. The Anderson Study describes several surveys of royalty rates used in licensing various technologies in the private sector. Although we did not cite the Anderson Study explicitly and our discussion of the issue was brief, the
9. Aside from this concern, the Anderson Study can actually be read to
10. We now turn to the Hausman Study. Based on an econometric study of the FCC's previous auctions, Hausman reports that prices for spectrum auctioned by the Commission have been decreasing over time on a per megahertz per population basis. He also posits that there will be significant sunk cost investments required to provide DTV ancillary or supplementary services, and also significant business and technological uncertainty facing these services. Hausman concludes that “the combination of overall declining auction results over time and the significant business and technological uncertainty with respect to sunk costs would lead to an expected outcome of relatively low auction results for spectrum used for ancillary services.” Noting that the
11. As an initial matter, we question a number of the underlying assertions made in the Hausman Study. Even assuming it is true that there is a downward trend in per megahertz, per population prices for the spectrum auctions the Commission has previously held, this does not necessarily mean that an auction of the spectrum used for DTV ancillary or supplementary services would follow this trend. As we stated in the
12. In addition, we question the Hausman Study's assertions regarding the degree of uncertainty and sunk costs DTV licensees will face in providing ancillary or supplementary services. Whether or not they choose to provide ancillary or supplementary services, DTV licensees will need to invest in DTV facilities in order to provide a free, over-the-air digital broadcast service. Given this, it would appear that the incremental or marginal cost of providing any feeable ancillary or supplementary services may not be as significant as Hausman and NAB/MSTV suggest. The most substantial costs incurred by broadcasters, such as transmitters and towers, will be sunk or fixed costs that are already incurred in connection with the provision of nonfeeable services, thus minimizing the additional investment required to provide feeable services. We consequently agree with NCTA that the risk associated with offering ancillary or supplementary services will be diminished by the fact that DTV licensees will be providing nonfeeable broadcast services.
13. We also think Hausman and NAB/MSTV overstate the level of uncertainty broadcasters face in developing ancillary or supplementary services. We fully recognize developing and implementing these services will entail challenges and risks. But broadcasters are not venturing into completely uncharted territory. They have been authorized to provide ancillary services on parts of their analog signals for years, although these services have been limited due to the lack of capacity on analog channels. Broadcasters have also become increasingly involved over the years in developing and selling programming carried on cable networks, and they can translate this experience into providing subscription programming over their DTV bitstream should that appear profitable to them. More recently, a number of broadcasters have invested in internet-related companies, suggesting that the internet's interactive and datacasting applications, which potentially could also be offered over the DTV bitstream, may prove profitable.
14. Aside from the questions we have about some of the Hausman Study's underlying assertions, we have a more fundamental objection to the conclusion NAB/MSTV seek to draw from it. In particular, neither NAB/MSTV nor Hausman provides a persuasive basis to conclude that Hausman's assertions, even taken at face value, require us to set the fee at two percent rather than five percent of gross revenues. The Hausman Study seems to acknowledge this in that it has no firm recommendation on the level of the fee, only suggesting that the FCC initially set the fee “toward the low end of the range” and that the Commission “might consider” initially setting the fee at one percent or less. For its part, the NAB/MSTV Petition argues that the studies it has submitted “provide [ ] strong support for the Commission to set a low initial fee” and concludes that the fee should be two percent of gross revenues, yet it provides no rationale why a “low fee” necessarily means a fee of two percent as opposed to five percent.
15. We continue to think that a fee of five percent of gross revenues is reasonable in light of the criteria set forth in Section 336(e). A central theme underlying NAB/MSTV's arguments and the studies they have submitted is that we should set the fee so as not “to discourage the development of new ancillary and supplementary services” and to “promote [ ] the efficient use of digital spectrum.” We agree that this is a worthy goal and, indeed, Section 1 of the Communications Act states that one of the Act's purposes is to promote an “efficient” radio communication service. 47 U.S.C. 151. But this general policy cannot trump the specific statutory criteria set forth in Section 336(e)(2) for establishing the fee, none
16. In the end, implementing Section 336(e) is not, to paraphrase one of the parties, an exact science. NAB/MSTV acknowledge that the Commission has “broad discretion under the Act in setting the fee level.” In exercising this discretion, we have sought to promote the efficient use of the spectrum and the development of innovative ancillary or supplementary services by DTV licensees. But this discretion is bounded by Section 336(e), which requires us to design the fee not only to approximate the revenue that would have been received had these services been licensed through an auction, but also to recover a portion of the value of the spectrum used for these services and avoid “unjust enrichment” of DTV licensees who have been given the exclusive right to apply for DTV channels without having to bid for them at an auction. Weighing these factors and the comments submitted in the proceeding—some of which argued for a fee of less than one percent while others argued for a fee of over ten percent—we established a fee of five percent of gross revenues generated from feeable ancillary or supplementary services. The amount raised by this fee will vary with the gross revenues from these services,
17. In the
18. UCC,
19. UCC,
20. We think UCC,
21. Section 336(e)(1), which defines the “services to which fees apply,” speaks only in terms of “ancillary or supplementary services” in delineating in subsections (A) and (B) the two types of such services that are subject to fees. In doing so, it necessarily excludes from the fees requirement services that are not “ancillary or supplementary” to begin with. Although the Act does not define the phrase “ancillary or supplementary services,” the Commission did so in implementing Section 336 in its DTV rulemaking proceeding, Fifth
22. Traditional home shopping, infomercial, or direct marketing services are video broadcast signals and are offered at no direct charge to viewers. As such, they fall outside the scope of our definition of “ancillary or supplementary services,” and therefore are not subject to fees under Section 336(e)(1) of the Act. We think this is consistent with Congress's intent in enacting Section 336(e)(1). To be sure, we adopted our definition of “ancillary or supplementary services” after
23. Further evidence of this can be found in Section 336(b)(3), which states, among other things, that “no ancillary or supplementary service shall have any rights to carriage under section 614 or 615,”
24. We do not agree with UCC,
25. But where, as here, the service is a video broadcast signal provided at no direct charge to viewers, it is not feeable, even though the broadcaster may be receiving compensation from a third party to carry the service. As HSN and ValueVision point out, to hold otherwise would mean that “all the affiliates of the ABC, CBS and NBC broadcast television networks arguably would be subject to fees for their free, over-the-air broadcast services because they receive compensation from their networks for airing network programming.” These are video broadcast signals provided to viewers at no direct charge, and therefore are not ancillary or supplementary services and are not subject to fees. We consequently deny UCC,
26. We make one final note. Our decision in the
27. The action contained herein has been analyzed with respect to the Paperwork Reduction Act of 1995 and found to impose no new or modified reporting and record-keeping requirements or burdens on the public. In addition, the Final Regulatory Flexibility Act Analysis set forth in the
28. Accordingly, pursuant to the authority granted by 47 U.S.C. 4(i), 303, 336(e), and 47 CFR 1.429, the Petition for Reconsideration filed jointly by the National Association of Broadcasters and the Association for Maximum Service Television, and the Petition for Reconsideration filed jointly by the Office of Communication Inc. of the United Church of Christ, the Benton Foundation, the Center for Media Education, the Civil Rights Forum and Media Access Project, are both hereby
1. This proceeding is terminated.
Television, television broadcasting.
Federal Communications Commission.
Final rule.
This document revises the Amateur Radio Service rules to simplify the Amateur Radio Service operator license structure; streamlines the
Effective April 15, 2000.
William T. Cross, Public Safety and Private Wireless Division, Wireless Telecommunications Bureau, (202) 418-0680, TTY (202) 418-7233.
This is a summary of the Commission's
1. In the
2. By this action, the Commission simplifies the Amateur Radio Service operator license structure; streamlines the number of examination elements; and reduces the emphasis on telegraphy that underlies the current license structure to the greatest extent possible, consistent with the international Radio Regulations. Specifically, the Commission amends the rules to reduce the number of operator license classes from six to three, reduce the number of telegraphy examination elements from three to one, reduce the number of written examination elements from five to three, authorize Advanced Class amateur radio operators to prepare and administer examinations for the General Class amateur radio operator license, and eliminate Radio Amateur Civil Emergency Service (RACES) station licenses.
3. The Regulatory Flexibility Act (RFA) requires that an agency prepare a regulatory flexibility analysis for notice-and-comment rulemaking proceedings, unless the agency certifies that “the rule will not, if promulgated, have a significant economic impact on a substantial number of small entities.” 5 U.S.C. 605(b). In the
Amateur radio, Examinations, Radio, Volunteer examiners.
For the reasons discussed in the preamble, the Federal Communications Commission amends 47 CFR part 97 as follows:
48 Stat. 1066, 1082, as amended; 47 U.S.C. 154, 303. Interpret or apply 48 Stat. 1064-1068, 1081-1105, as amended; 47 U.S.C. 151-155, 301-609, unless otherwise noted.
(a) * * *
(b) The person named in an operator license grant of Novice, Technician, Technician Plus, General or Advanced Class, who has properly submitted to the administering VEs a FCC Form 605 document requesting examination for an operator license grant of a higher class, and who holds a CSCE indicating that the person has completed the necessary examinations within the previous 365 days, is authorized to exercise the rights and privileges of the higher operator class until final disposition of the application or until 365 days following the passing of the examination, whichever comes first.
(b) A station within 1600 m (1 mile) of an FCC monitoring facility must protect that facility from harmful interference. Failure to do so could result in imposition of operating restrictions upon the amateur station by a District Director pursuant to § 97.121 of this part. Geographical coordinates of the facilities that require protection are listed in § 0.121(c) of this chapter.
(c) * * *
(2) If the routine environmental evaluation indicates that the RF electromagnetic fields could exceed the limits contained in § 1.1310 of this chapter in accessible areas, the licensee must take action to prevent human exposure to such RF electromagnetic fields. Further information on evaluating compliance with these limits can be found in the FCC's OET Bulletin Number 65, “Evaluating Compliance with FCC Guidelines for Human Exposure to Radiofrequency Electromagnetic Fields.”
(a) Any qualified person is eligible to apply for a new operator/primary station, club station or military recreation station license grant. No new license grant will be issued for a Novice, Technician Plus, or Advanced Class operator/primary station or a RACES station.
(a) * * *
(3) May apply to the FCC for renewal of the license grant for another term in accordance with § 1.913 of this chapter. Application for renewal of a Technician Plus Class operator/primary station license will be processed as an application for renewal of a Technician Class operator/primary station license.
(iii) For a club station or military recreation station license grant showing a call sign obtained through the sequential call sign system, and for a club or military recreation station license grant showing a call sign obtained through the vanity call sign system but whose grantee does not want to have the vanity call sign reassigned to the station, the application must be presented in document form to a Club Station Call Sign Administrator who must submit the information thereon to the FCC in an electronic batch file. The Club Station Call Sign Administrator must retain the collected information for at least 15 months and make it available to the FCC upon request. RACES station license grants will not be renewed.
(e) For a station having a control operator who has been granted an operator license of Novice Class or Technician Class and who has received credit for proficiency in telegraphy in accordance with the international requirements.
(f) * * *
(10) A station having a control operator holding a Novice Class operator license or a Technician Class operator license and who has received credit for proficiency in telegraphy in accordance with the international requirements may only transmit a CW emission using the international Morse code or phone emissions J3E and R3E.
(c) * * *
(2) The 28.1-28.5 MHz segment when the control operator is a Novice Class operator or a Technician Class operator who has received credit for proficiency in telegraphy in accordance with the international requirements; or
(f) No station may transmit with a transmitter power exceeding 50 W PEP on the UHF 70 cm band from an area specified in footnote US7 to § 2.106 of Part 2, unless expressly authorized by the FCC after mutual agreement, on a case-by-case basis, between the District Director of the applicable field facility and the military area frequency coordinator at the applicable military base. An Earth station or telecommand station, however, may transmit on the 435-438 MHz segment with a maximum of 611 W effective radiated power (1 kW equivalent isotropically radiated power) without the authorization otherwise required. The transmitting antenna elevation angle between the lower half-power (−3 dB relative to the peak or antenna bore sight) point and the horizon must always be greater than 10
(b) The frequency bands and segments and emissions authorized to the control operator are available to stations transmitting communications in RACES on a shared basis with the amateur service. In the event of an emergency which necessitates the invoking of the President's War Emergency Powers under the provisions of Section 706 of the Communications Act of 1934, as amended, 47 U.S.C. 606, RACES stations and amateur stations participating in RACES may only transmit on the following frequency segments:
Each applicant must pass an examination for a new amateur operator license grant and for each change in operator class. Each applicant for the class of operator license grant specified below must pass, or otherwise receive examination credit for, the following examination elements:
(a) Amateur Extra Class operator: Elements 1, 2, 3, and 4;
(b) General Class operator: Elements 1, 2, and 3;
(c) Technician Class operator: Element 2.
(a) A telegraphy examination must be sufficient to prove that the examinee has the ability to send correctly by hand and
(b) A written examination must be such as to prove that the examinee possesses the operational and technical qualifications required to perform properly the duties of an amateur service licensee. Each written examination must be comprised of a question set as follows:
(1) Element 2: 35 questions concerning the privileges of a Technician Class operator license. The minimum passing score is 26 questions answered correctly.
(2) Element 3: 35 questions concerning the privileges of a General Class operator license. The minimum passing score is 26 questions answered correctly.
(3) Element 4: 50 questions concerning the privileges of an Amateur Extra Class operator license. The minimum passing score is 37 questions answered correctly.
(a) The administering VEs must give credit as specified below to an examinee holding any of the following license grants or license documents:
(1) An unexpired (or expired but within the grace period for renewal) FCC-granted Advanced Class operator license grant: Elements 1, 2, and 3.
(2) An unexpired (or expired but within the grace period for renewal) FCC-granted General Class operator license grant: Elements 1, 2, and 3.
(3) An unexpired (or expired but within the grace period for renewal) FCC-granted Technician Plus Class operator (including a Technician Class operator license granted before February 14, 1991) license grant: Elements 1 and 2.
(4) An unexpired (or expired but within the grace period for renewal) FCC-granted Technician Class operator license grant: Element 2.
(5) An expired or unexpired FCC-granted Novice Class operator license grant: Element 1.
(6) A CSCE: Each element the CSCE indicates the examinee passed within the previous 365 days.
(7) An unexpired (or expired less than 5 years) FCC-issued commercial radiotelegraph operator license or permit: Element 1.
(8) An expired FCC-issued Technician Class operator license document granted before March 21, 1987: Element 3.
(9) An expired or unexpired FCC-issued Technician Class operator license document granted before February 14, 1991: Element 1.
(a) Each telegraphy message and each written question set administered to an examinee must be prepared by a VE holding an Amateur Extra Class operator license. A telegraphy message or written question set may also be prepared for the following elements by a VE holding an operator license of the class indicated:
(1) Element 3: Advanced Class operator.
(2) Elements 1 and 2: Advanced, General, or Technician (including Technician Plus) Class operators.
(a) Each examination for an amateur operator license must be administered by a team of at least 3 VEs at an examination session coordinated by a VEC. Before the session, the administering VEs or the VE session manager must ensure that a public announcement is made giving the location and time of the session. The number of examinees at the session may be limited.
(b) * * *
(3) Be a person who holds an amateur operator license of the class specified below:
(i) Amateur Extra, Advanced or General Class in order to administer a Technician Class operator license examination;
(ii) Amateur Extra or Advanced Class in order to administer a General Class operator license examination;
(iii) Amateur Extra Class in order to administer an Amateur Extra Class operator license examination.
Department of Defense (DOD).
Final rule.
The Acting Director of Defense Procurement has issued a final rule amending the Defense Federal Acquisition Regulation Supplement (DFARS) to authorize the senior procurement executives for the Army, Navy, and Air Force, and the Directors of the Defense Commissary Agency and the Defense Logistics Agency, to approve certain class deviations from the Federal Acquisition Regulation (FAR) and the DFARS.
February 10, 2000.
Ms. Kathleen Fenk, Defense Acquisition Regulations Council, PDUSD(AT&L)DP(DAR), IMD 3D139, 3062 Defense Pentagon, Washington, DC 20301-3062. Telephone (703) 602-0296; telefax (703) 602-0350. Please cite DFARS Case 99-D027.
This final rule amends DFARS Parts 201 and 225 to authorize the senior procurement executives for the Army, Navy, and Air Force, and the Directors of the Defense Commissary Agency and the Defense Logistics Agency, to approve certain class deviations from the FAR and the DFARS. The rule also contains amendments to reflect the title change of the “Under Secretary of Defense for Acquisition and Technology” to the “Under Secretary of Defense for Acquisition, Technology, and Logistics.”
This rule was not subject to Office of Management and Budget review under Executive Order 12866, dated September 30, 1993.
This final rule does not constitute a significant revision within the meaning of FAR 1.501 and Public Law 98-577 and publication for public comment is not required. However, DoD will consider comments from small entities concerning the affected DFARS subparts in accordance with 5 U.S.C. 610. Such comment should cite DFARS Case 99-D027.
The Paperwork Reduction Act does not apply because the rule does not impose any information collection requirements that require the approval of the Office of Management and Budget under 44 U.S.C. 3501, et seq.
Government procurement.
41 U.S.C. 421 and 48 CFR Chapter 1.
(d)(i) * * *
V. Deviations: If a recommended revision of DFARS is a FAR deviation, identify the deviation and include under separate TAB a justification for the deviation that addresses the requirements of 201.402(2). The justification should be in the form of a memorandum for the Director of Defense Procurement, Office of the Under Secretary of Defense (Acquisition, Technology, and Logistics).
a. In paragraph (1)(i) introductory text by removing “Under Secretary of Defense (Acquisition and Technology) (USD (A&T))”; and adding in its place “USD (AT&L)”;
b. In paragraph (1)(ii) by removing the parenthetical “(A&T)” both places it appears and adding in its place “(AT&L)”;
c. In paragraph (2)(ii) by removing the parenthetical “(A&T)” and adding in its place “(AT&L)”; and
d. By revising paragraphs (3) through (5) to read as follows:
(3) Contracting activities must obtain the appropriate approval (see 201.404) for any class deviation (as defined in FAR subpart 1.4) from the FAR or DFARS, before its inclusion in a department/agency or component supplement or any other contracting regulation document such as a policy letter or clause book.
(4) Each department and agency must develop and, upon approval by USD(AT&L)DP, implement, maintain, and comply with a plan for controlling the use of clauses other than those prescribed by FAR or DFARS.
(5) Departments and agencies must submit requests for the Secretary of Defense, USD(AT&L), and USD(AT&L)DP approvals required by this section through the Director of the DAR Council.
(1) The Director of Defense Procurement, Office of the Under Secretary of Defense (Acquisition, Technology, and Logistics) (USD(AT&L)DP), is the approval authority within DoD for any individual or class deviation from—
(i) FAR 3.104, Procurement Integrity, or DFARS 203.104, Procurement Integrity;
(ii) FAR Subpart 27.4, Rights in Data and Copyrights, or DFARS Subpart 227.4, Rights in Data and Copyrights;
(iii) FAR part 30, Cost Accounting Standards Administration, or DFARS part 230, Cost Accounting Standards Administration;
(iv) FAR subpart 31.1, Applicability, or DFARS subpart 231.1, Applicability (contract cost principles);
(v) FAR subpart 31.2, Contracts with Commercial Organizations, or DFARS subpart 231.2, Contracts with Commercial Organizations; or
(vi) FAR part 32, Contract Financing (except subparts 32.7 and 32.8 and the payment clauses prescribed by subpart 32.1), or DFARS part 232, Contract Financing (except subparts 232.7 and 232.8).
(2) Submit requests for deviation approval through department/agency channels to the approval authority in paragraph (1) of this section, 201.403, or 201.404, as appropriate. Submit deviations that require USD(AT&L)DP approval through the Director of the DAR Council. At a minimum, each request must—
(1) Individual deviations, except those described in 201.402(1) and paragraph (2) of this section, must be approved in accordance with the department/agency plan prescribed by 201.304(4).
(2) Contracting officers outside the United States may deviate from prescribed nonstatutory FAR and DFARS clauses when—
(i) Contracting for support services, supplies, or construction, with the governments of North Atlantic Treaty Organization (NATO) countries or other allies (as described in 10 U.S.C. 2341(2)), or with United Nations or NATO organizations; and
(ii) Such governments or organizations will not agree to the standard clauses.
(b)(i) Except as provided in paragraph (b)(ii) of this section, USD(AT&L)DP is the approval authority within DoD for any class deviation.
(ii) The senior procurement executives for the Army, Navy, and Air Force, and the Directors of the Defense Commissary Agency and the Defense Logistics Agency, may approve any class deviation, other than those described in 201.402(1), that does not—
(A) Have a significant effect beyond the internal operating procedures of the department or agency;
(B) Have a significant cost or administrative impact on contractors or offerors;
(C) Diminish any preference given small business concerns by the FAR or DFARS; or
(D) Extend to requirements imposed by statute or by regulations of other agencies such as the Small Business Administration and the Department of Labor.
Department of Defense (DoD).
Final rule.
The Acting Director of Defense Procurement has issued a final rule amending the Defense Federal Acquisition Regulation Supplement (DFARS) to address use of a Federal Acquisition Regulation (FAR) provision that invites offerors to propose alternatives to Government-unique standards. This DFARS rule instructs DoD contracting officers not to use the FAR provision, since DoD uses the Single Process Initiative to encourage offerors to propose alternatives to Government-unique specifications and standards.
February 10, 2000.
Ms. Melissa Rider, Defense Acquisition Regulations Council, PDUSD (AT&L) DP (DAR), IMD 3D139, 3062 Defense Pentagon, Washington, DC 20301-3061. Telephone (703) 602-4245; telefax (703) 602-0350. Please cite DFARS Case 99-D024.
This final DFARS rule supplements the final FAR rule that was published at 64 FR 51834 on September 24, 1999 (Federal Acquisition Circular 97-14, Item V) to implement Office of Management and Budget Circular A-119, Federal Participation in the Development and Use of Voluntary Consensus Standards and in Conformity Assessment Activities. The FAR rule added a provision at FAR 52.211-7 to permit offerors to propose voluntary consensus standards as alternatives to Government-unique standards included in a solicitation. In accordance with the prescription at FAR 11.107(b), use of the provision is optional for agencies that use the categorical method of reporting their use of voluntary consensus standards to the National Institute of Standards and Technology. DoD uses the categorical method of reporting. In addition, DoD uses the Single Process Initiative procedures at DFARS 211.273 and 252.211-7005 to encourage offerors to propose industry standards as alternatives to Government-unique specifications and standards. Therefore, this DFARS rule specifies that the provision at FAR 52.211-7 will not be used in DoD solicitations.
DoD published a proposed rule at 64 FR 61056 on November 9, 1999. One source submitted comments in response to the proposed rule. DoD considered those comment in the development of the final rule.
This rule was not subject to Office of Management and Budget review under Executive Order 12866, dated September 30, 1993.
DoD certifies that this final rule will not have a significant economic impact on a substantial number of small entities within the meaning of the Regulatory Flexibility Act, 5 U.S.C. 601,
The Paperwork Reduction Act does not apply because the rule does not impose any information collection requirements that require the approval of the Office of Management and Budget under 44 U.S.C. 3501,
Government procurement.
41 U.S.C. 421 and 48 CFR Chapter 1.
(b) DoD uses the categorical method of reporting. Do not use the provision at FAR 52.211-7, Alternatives to Government-Unique Standards, in DoD solicitations.
Department of Defense (DoD).
Final rule.
The Acting Director of Defense Procurement has issued a final rule amending the Defense Federal Acquisition Regulation Supplement (DFARS) to implement Section 8120 of the DoD Appropriations Act for fiscal year 1999, as amended by Section 144 of Title I, Division C, of the Omnibus Consolidated and Emergency Supplemental Appropriations Act, 1999. Section 8120 places restrictions on the award of contracts to companies in which the People's Republic of China or the People's Liberation Army of the People's Republic of China owns more than 50 percent interest.
February 10, 2000.
Ms. Amy Williams, Defense Acquisition Regulations Council, PDUSD (AT&L) DP (DAR), IMD 3D139, 3062 Defense Pentagon, Washington, DC 20301-3062. Telephone (703) 602-0288; telefax (703) 602-0350. Please cite DFARS Case 98-D305.
This rule finalizes the interim rule that was published at 64 FR 8727 on February 23, 1999. DoD received no public comments on the interim rule.
The interim rule implemented Section 8120 of the DoD Appropriations Act for fiscal year 1999 (Public Law 105-262). Section 8120 places restrictions on the award of contracts to companies owned or partially owned by the People's Republic of China or the People's Liberation Army of the People's Republic of China. This final rule also incorporates the provisions of Section 144 of Title I, Division C, of the Omnibus Consolidated and Emergency Supplemental Appropriations Act, 1999 (Public Law 105-277). Section 144 of Public Law 105-277 amended Section 8120 of Public Law 105-262 to restrict contract award only if the Secretary of Defense determines that the People's Republic of China or the People's Liberation Army of the People's Republic of China owns more than 50 percent interest in a company. The Secretary of Defense has delegated the authority for such determinations to the Director of Defense Procurement.
This rule was not subject to Office of Management and Budget review under Executive Order 12866, dated September 30, 1993.
DoD certifies that this final rule will not have a significant economic impact on a substantial number of small entities within the meaning of the Regulatory Flexibility Act, 5 U.S.C. 601,
The Paperwork Reduction Act does not apply because the rule does not impose any information collection requirements that require the approval of the Office of Management and Budget under 44 U.S.C. 3501,
Government procurement.
41 U.S.C. 421 and 48 CFR Chapter 1.
2. Sections 225.771-2 through 225.771-4 are revised and section 225.771-5 is added to read as follows:
This section implements Section 8120 of the DoD Appropriations Act for fiscal year 1999 (Pub. L. 105-262), as amended by Section 144 of Title I, Division C, of the Omnibus Consolidated and Emergency Supplemental Appropriations Act, 1999 (Pub. L. 105-277).
If using fiscal year 1999 funds made available by Title III (Procurement) or Title IV (Research, Development, Test and Evaluation) of Pub. L. 105-262, do not award or renew a contract with any company in which the Director of Defense Procurement has determined that the People's Republic of China or the People's Liberation Army of the People's Republic of China owns more than 50 percent interest.
(a) Forward any information that the People's Republic of China or the People's Liberation Army of the People's Republic of China owns more than 50 percent interest in a company, through the head of the agency, to the Director, Defense Procurement, ATTN: OUSD (AT&L) DP/FC, 3060 Defense Pentagon, Washington, DC 20301-3060.
(b) Upon verification of the information, the Director of Defense Procurement will ask the General Services Administration to list the company as ineligible on the List of Parties Excluded from Federal Procurement and Nonprocurement Programs.
Use the provision at 252.225-7017, Prohibition on Award to Companies Owned by the People's Republic of China, in solicitations for contracts that will use fiscal year 1999 funds made available by Title III or IV of Pub. L. 105-262.
As prescribed in 225.771-5, use the following provision:
(a)
(b)
(c)
Department of Defense (DoD).
Interim rule with request for comments.
The Acting Director of Defense Procurement has issued an interim rule amending the Defense Federal Acquisition Regulation Supplement (DFARS) to implement Section 811 of the National Defense Authorization Act for Fiscal Year 2000. Section 811 amends statutory provisions pertaining to the DoD Pilot Mentor-Protege Program.
Interested parties should submit written comments to: Defense Acquisition Regulations Council, Attn: Ms. Susan Schneider, PDUSD (AT&L) DP (DAR), IMD 3D139, 3062 Defense Pentagon, Washington, DC 20301-3062. Telefax (703) 602-0350.
E-mail comments submitted via the Internet should be addressed to: dfars@acq.osd.mil
Please cite DFARS Case 99-D307 in all correspondence related to this rule. E-mail comments should cite DFARS Case 99-D307 in the subject line.
Ms. Susan Schneider, (703) 602-0326.
This interim rule revises DFARS Subpart 219.71 and Appendix I to implement Section 811 of the National Defense Authorization Act for Fiscal Year 2000 (Public Law 106-65). Section 811 amends statutory provisions pertaining to the DoD Pilot Mentor-Protege Program. The amendments revise the procedures for reimbursement
This rule was not subject to Office of Management and Budget review under Executive Order 12866, dated September 30, 1993.
DoD does not expect this rule to have a significant economic impact on a substantial number of small entities within the meaning of the Regulatory Flexibility Act, 5 U.S.C. 601,
The Paperwork Reduction Act (44 U.S.C. 3501,
1.
a. Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
b. The accuracy of the agency's estimate of the burden of the information collection;
c. Ways to enhance the quality, utility, and clarity of the information to be collected; and
d. Ways to minimize the burden of the information collection on respondents, including the use of automated collection techniques or other forms of information technology.
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A determination has been made under the authority of the Secretary of Defense that urgent and compelling reasons exist to publish this interim rule prior to affording the public an opportunity to comment. This interim rule implements Section 811 of the National Defense Authorization Act for Fiscal Year 2000. Section 811 amends statutory provisions pertaining to the DoD Pilot Mentor-Protege Program. Section 811 became effective on October 5, 1999. DoD will consider comments received in response to this interim rule in the formation of the final rule.
Government procurement.
41 U.S.C. 421 and 48 CFR Chapter 1.
This subpart implements the Pilot Mentor-Protege Program established under Section 831 of the National Defense Authorization Act for Fiscal Year 1991 (Pub. L. 101-510; 10 U.S.C. 2302 note). The purpose of the Program is to provide incentives for DoD contractors to assist small disadvantaged businesses in enhancing their capabilities and to increase participation of such firms in Government and commercial contracts. Qualified organizations employing the severely disabled, as defined in Section 8064A of Pub. L. 102-172, are also eligible to participate as protege firms.
DoD policy and procedures for implementation of the Program are contained in Appendix I, Policy and Procedures for the DoD Pilot Mentor-Protege Program.
The Program includes—
(a) Mentor firms that are prime contractors with at least one active subcontracting plan negotiated under FAR Subpart 19.7.
(b) Protege firms that are small disadvantaged business (SDB) concerns as defined at 219.001(1), or qualified organizations employing the severely disabled, eligible for receipt of Federal contracts and selected by the mentor firm.
(c) Mentor-protege agreements that establish a developmental assistance program for a protege firm.
(d) Incentives that DoD may provide to mentor firms, including:
(1) Reimbursement for developmental assistance costs through—
(i) A separately priced contract line item on a DoD contract; or
(ii) A separate contract, upon written determination by the Director, Small and Disadvantaged Business Utilization, Office of the Under Secretary of Defense (Acquisition, Technology, and Logistics) SADBU, OUSD (AT&L)), that unusual circumstances justify reimbursement using a separate contract; or
(2) Credit toward SDB subcontracting goals, established under a subcontracting plan negotiated under FAR Subpart 19.7, for developmental assistance costs that are not reimbursed.
The procedures for application, acceptance, and participation in the Program are in Appendix I, Policy and Procedures for the DoD Pilot Mentor-Protege Program. The Director, SADBU, OUSD (AT&L), approves contractors as mentor firms, approves mentor-protege agreements, and forwards approved mentor-protege agreements to the contracting officer when program funding is available through a DoD program manager.
Contracting officers must—
(a) Negotiate an advance agreement on the treatment of developmental assistance costs for either credit or reimbursement if the mentor firm proposes such an agreement, or delegate authority to negotiate to the administrative contracting officer (see FAR 31.109).
(b) Modify (without consideration) applicable contract(s) to incorporate the clause at 252.232-7005, Reimbursement of Subcontractor Advance Payments—DoD Pilot Mentor-Protege Program, when a mentor firms provides advance payments to a protege firm under the Program and the mentor firm requests reimbursement of advance payments.
(c) Modify (without consideration) applicable contract(s) to incorporate other than customary progress payments for small disadvantaged businesses in accordance with FAR 32.504(c) if a mentor firm provides such payments to a protege firm and the mentor firm requests reimbursement.
(d) Modify applicable contract(s) to establish a contract line item for reimbursement of developmental assistance costs if—
(1) A DoD program manager has made funds available for that purpose; and
(2) The contractor has an approved mentor-protege agreement.
(e) Negotiate and award a separate contract for reimbursement of developmental assistance cost if—
(1) A DoD program manager has made funds available for that purpose;
(2) The contractor has an approved mentor-protege agreement; and
(3) The Director, SADBU, OUSD (AT&L), has made a determination in accordance with 219.7102(d)(1)(ii).
(f) Authorized reimbursement for costs of assistance furnished to a protege firm in excess of $1,000,000 in a fiscal year only after receipt of a written determination from the Director, SADBU, OUSD (AT&L).
(g) Advise contractors of reporting requirements in Appendix I.
(h) Provide a copy of the approved Mentor-Protege agreement to the Defense Contract Management Command administrative contracting officer responsible for conducting the annual performance review (see Appendix I, Section I-112).
(a) Development assistance provided under an approved mentor-protege agreement is distinct from, and must not duplicate, any effort that is the normal and expected product of the award and administration of the mentor firm's subcontracts. The mentor firm must accumulate and charge costs associated with the latter in accordance with its approved accounting practices. Mentor firm costs that are eligible for reimbursement are set forth in Appendix I.
(b) Before incurring any costs under the Program, mentor firms must establish the accounting treatment of developmental assistance costs eligible for reimbursement or credit. Advance agreements are encouraged. To be eligible for reimbursement under the Program, the mentor firm must incur the costs before October 1, 2005.
(c) If the mentor firm is suspended or debarred while performing under an approved mentor-protege agreement, the mentor firm may not be reimbursed or credited for developmental assistance costs incurred more than 30 days after the imposition of the suspension or debarment.
(d) Developmental assistance costs incurred by a mentor firm before October 1, 2005, that are eligible for crediting under the Program, may be credited toward subcontracting plan goals as set forth in Appendix I.
Mentor and protege firms must report on the progress made under mentor-protege agreements as indicated in Appendix I, Section I-111.
The Defense Contract Management Command will conduct annual performance reviews of all mentor-protege agreements as indicated in Appendix I, Section I-112.
(a) This Appendix I to 48 CFR Chapter 2 implements the Pilot Mentor-Protege Program (hereinafter referred to as the “Program”) established under Section 831 of Pub. L. 101-510, the National Defense Authorization Act for Fiscal Year 1991 (10 U.S.C. 2302 note). The purpose of the Program is to—
(1) Provide incentives to major DoD contractors, performing under at least one active approved subcontracting plan negotiated with DoD or another Federal agency, to assist small disadvantaged business (SDB) concerns or qualified organizations employing the severely disabled (hereinafter referred to as “protege firms”) in enhancing their capabilities to satisfy DoD and other contract and subcontract requirements;
(2) Increase the overall participation of protege firms as subcontractors and suppliers under DoD contracts, other Federal agency contracts, and commercial contracts; and
(3) Foster the establishment of long-term business relationships between protege firms and such contractors.
(b) Under the Program, eligible companies approved as mentor firms will enter into mentor-protege agreements with eligible protege firms to provide appropriate developmental assistance to enhance the capabilities of the protege firms to perform as subcontractors and suppliers. According to the law, DoD may provide the mentor firm with either cost reimbursement or credit against SDB subcontracting goals established under contracts with DoD or other Federal agencies.
(c) DoD will measure the overall success of the Program by the extent to which the Program results in—
(1) An increase in the dollar value of subcontracts awarded to protege firms by mentor firms under DoD contracts;
(2) An increase in the dollar value of contract and subcontract awards to protege firms (under DoD contracts, contracts awarded by other Federal agencies, and commercial contracts) from the date of their entry into the Program until 2 years after the conclusion of the agreement;
(3) An increase in the number and dollar value of subcontracts awarded to a protege firm (or former protege firm) by its mentor firm (or former mentor firm);
(4) An increase in subcontracting with SDB concerns in industry categories where SDBs traditionally have not participated within the mentor firm's vendor base;
(5) The involvement of emerging SDBs in the Program; and
(6) An increase in the employment level of protege firms from the date of entry into the Program until 2 years after the completion of the agreement.
(d) This policy sets forth the procedures for participation in the Program applicable to companies that are interested in receiving—
(1) Reimbursement through a separate contract line item in a DoD contract or a separate contract with DoD; or
(2) Credit toward SDB subcontracting goals for costs incurred under the Program.
A small disadvantaged business whose size is no greater than 50 percent of the numerical size standard applicable to the standard industrial code for the supplies or services that the protege firm provides or would provide to the mentor firm.
An institution determined by the Secretary of Education to meet the requirements of 34 CFR 608.2. The term also means any nonprofit research institution that was an integral part of such a college or university before November 14, 1986.
An institution meeting the definition of “Minority Institution” at FAR 26.301.
(a) At any time between October 1, 1991, and September 30, 2002, companies interested in becoming mentor firms that want to take credit toward SDB subcontracting goals for costs incurred for providing developmental assistance to one or more protege firms must apply to DoD for participation in the Program pursuant to the application process set forth at I-106(a).
(b) At any time between October 1, 1991, and September 30, 2002, companies interested in becoming mentor firms that are able to identify funding from a DoD program manager(s) to provide developmental assistance to one or more protege firms must apply to DoD for participation in the Program, pursuant to the application process set forth at I-106(d).
Activities under the Program may occur only during the following periods:
(a) From October 1, 1991, until September 30, 2002, companies that have been approved for participation in the Program as mentor firms pursuant to I-102, General Procedures, may enter into mentor-protege agreements, pursuant to I-107, Mentor Protege Agreements.
(b) From October 1, 1991, until September 30, 2005, DoD may reimburse a mentor firm's costs of providing developmental assistance to its protege firm only if a DoD program manager has identified the funding for such costs and—
(1)(i) For mentor-protege agreements entered into prior to October 1, 1999, the mentor firm incurs such costs after DoD and the mentor firm enter into a separate contract, cooperative agreement, or other agreement; or
(ii) For mentor-protege agreements entered into on or after October 1, 1999, the mentor firm incurs such costs after DoD and the mentor firm enter into a separate contract based upon a determination by the Director, Small and Disadvantaged Business Utilization, Office of the Under Secretary of Defense (Acquisition, Technology, and Logistics) (SADBU, OUSD (AT&L)), that unusual circumstances justify using a separate contract; or
(2) The mentor firm incurs such costs pursuant to the execution of a separately priced contract line item added to a DoD contract(s).
(c) From October 1, 1991, until September 30, 2005, a mentor firm may receive credit toward the attainment of its goals for subcontract awards to SDBs, for unreimbursed costs incurred in providing developmental assistance to its protege firms, only it such costs are incurred pursuant to an approved mentor-protege agreement.
(a) An entity may qualify as a protege firm if it is—
(1) An SDB concern as defined at 219.001, paragraph (1) of the definition of “small disadvantaged business concern,” that is—
(i) Eligible for the award of Federal contracts; and
(ii) A small business according to the Small Business Administration (SBA) size standard for the Standard Industrial Classification (SIC) code that represents the contemplated supplies or services to be provided by the protege firm to the mentor firm; or
(2) A qualified organization employing the severely disabled as defined in Pub. L. 102-172, section 8064A.
(b) A protege firm may self-certify to a mentor firm that it meets the eligibility requirements in paragraph (a)(1) or (2) of this section. Mentor firms may rely in good faith on a written representation that the entity meets the requirements of paragraph (a)(1) or (2) of this section, except for a protege's status as a small disadvantaged business concern (see FAR 19.703(b)).
(c) A protege firm may have only one active DoD mentor-protege agreement.
(a) Mentor firms will be solely responsible for selecting protege firms. Mentor firms are encouraged to identify and select protege firms that are defined as emerging SDB concerns.
(b) The selection of protege firms by mentor firms may not be protested, except as in paragraph (c) of this section.
(c) In the event of a protest regarding the size or disadvantaged status of an entity selected to be a protege firm as defined in I-104(a)(1), the mentor firm must refer the protest to the SBA to resolve in accordance with 13 CFR Part 121 (with respect to size) or 13 CFR 124 (with respect to disadvantaged status).
(d) For purposes of the Small Business Act, no determination of affiliation or control (either direct or indirect) may be found between a protege firm and its mentor firm on the basis that the mentor firm has agreed to furnish (or has furnished) to its protege firm, pursuant to a mentor-protege agreement, any form of developmental assistance described in I-107(f).
(e) If at any time pursuant to paragraph (c) of this section, the SBA determines that an SDB protege firm is not an SDB concern, assistance that the mentor firm furnishes to such a concern after the date of the determination may not be considered assistance furnished under the Program.
(a) On or after October 1, 1991, a company that is interested in becoming a mentor firm that is seeking credit toward SDB subcontracting goals for costs incurred under the Program must submit a request to the Director, SADBU, OUSD (AT&L), for approval as a mentor firm under the Program. The Director will evaluate the request based on the extent to which the company's proposal addresses the items listed in paragraphs (b) and (c) of this section. To the maximum extent possible, a company should limit its request to not more than 10 pages, single-spaced. A company may identify more than one protege in its request for approval under the Program. The request must include the information required in paragraphs (b) and (c) of this section and may cover one or more proposed mentor-protege relationships.
(b) A company must indicate whether it is interested in participating in the Program pursuant to I-100(d)(1) or (2) and must submit the following information:
(1) A statement that the company is currently performing under at least one
(2) The number of proposed mentor-protege relationships covered by the request for approval as a mentor firm.
(3) A summary of the company's historical and recent activities and accomplishments under its SDB program.
(4) The total dollar amount of DoD contracts and subcontracts that the company received during the 2 preceding fiscal years. (Show prime contracts and subcontracts separately per year.)
(5) The total dollar amount of all other Federal agency contracts and subcontracts that the company received during the 2 preceding fiscal years. (Show prime contracts and subcontracts separately per year.)
(6) The total dollar amount of subcontracts that the company awarded under DoD contracts during the 2 preceding fiscal years.
(7) The total dollar amount of subcontracts that the company awarded under all other Federal agency contracts during the 2 preceding fiscal years.
(8) The total dollar amount and percentage of subcontracts that the company awarded to all SDB firms under DoD contracts and other Federal agency contracts during the 2 preceding fiscal years. (Show DoD subcontract awards separately.) If the company presently is required to submit a Standard Form (SF) 295, Summary Subcontract Report, the request must include copies of the final reports for the 2 preceding fiscal years.
(9) The number and total dollar amount of subcontracts that the company awarded to the identified protege firm(s) during the 2 preceding fiscal years (if any). (Show DoD subcontract awards and other Federal agency subcontract awards separately.)
(c) In addition to the information required in paragraph (b) of this section, companies must submit the following information for each proposed mentor-protege relationship:
(1) Information on the company's ability to provide developmental assistance to the identified protege firm and how that assistance will potentially increase subcontracting opportunities in industry categories where SDBs are not dominant in the company's vendor base.
(2) A letter of intent indicating that both the mentor firm and the protege firm will negotiate a mentor-protege agreement. The letter of intent must be signed by both parties and must contain the following information:
(i) The name, address, and telephone number of both parties.
(ii) The protege firm's business classification, based upon the SIC code(s) that represents the contemplated supplies or services to be provided by the protege firm to the mentor firm.
(iii) A statement that the protege firm meets the eligibility criteria in I-104(a)(1) or (2).
(iv) A preliminary assessment of the developmental needs of the protege firm, and the proposed developmental assistance the mentor firm envisions providing the protege firm to address those needs and enhance the protege firm's ability to perform successfully under contracts or subcontracts with DoD and other Federal agencies and commercial contracts.
(v) an estimate of the dollar amount and type of subcontracts that the mentor firm will award to the protege firm, and the period of time over which the mentor firm will make those awards.
(vi) Information as to whether the protege firm's development will be concentrated on a single major system, a service or supply program, research and development programs, initial production, or mature systems, or in the mentor firm's overall contract base.
(3) An estimate of the cost of the developmental assistance program and the period of time over which the mentor firm will provide assistance.
(4) A statement from the protege firm indicating its commitment to comply with the requirements for reporting and for review of the agreement during the duration of the agreement and for 2 years thereafter.
(d) A company that has identified Program funds to be made available through a DoD program manager must provide the information in paragraphs (b) and (c) of this section through the appropriate program manager and the cognizant Director, SADBU, to the Director, SADBU, OUSD(AT&L), with a letter signed by the appropriate program manager indicating the amount of funding that has been identified for the developmental assistance program. The company must submit a justification and endorsement from the cognizant Director, SADBU, when requesting—
(1) Reimbursement of developmental costs in excess of $1,000,000;
(2) Reimbursement through a separate contract; or
(3) A Program participation term greater than 3, but not more than 5, years.
(e) Companies seeking credit toward SDB subcontracting goals for the cost of developmental assistance, or reimbursement with funds made available by a DoD program manager, must submit four copies of the information specified in paragraphs (b) and (c) of this section to the Director, SADBU, OUSD(AT&L), ATTN: Pilot Mentor-Protege Program Manager, 1777 North Kent Street, Suite 9100, Arlington, VA 22209. Upon receipt of this information, the Director, SADBU, OUSD(AT&L), will review and evaluate each request and, to the maximum extent possible, within 30 days advise each applicant of approval or rejection of its request to become a mentor firm.
(f) A company approved as a mentor firm, either for credit or for reimbursement through funds made available by a DoD program manager, proceed with the negotiation of the mentor-protege agreement with the identified protege firm(s).
(g) Companies that apply for participation in the Program pursuant to paragraph (e) of this section, and are not approved, will be provided the reasons and an opportunity to submit additional information for reconsideration.
(h) A company may not be approved for participation in the Program as a mentor firm if, at the time of requesting participation in the Program, it is currently debarred or suspended from contracting with the Federal Government pursuant to FAR subpart 9.4.
(i) If the mentor firm is suspended or debarred while performing under an approved mentor-protege agreement, the mentor firm—
(1) May continue to provide assistance to its protege firms pursuant to approved mentor-protege agreements entered into prior to the imposition of such suspension or debarment;
(2) May not be reimbursed or take credit for any costs of providing developmental assistance to its protege firm, incurred more than 30 days after the imposition of such suspension or debarment; and
(3) Must promptly give notice of its suspension or debarment to its protege firm and the Director, SADBU, OUSD (AT&L).
(a) A signed mentor-protege agreement for each mentor-protege relationship identified under I-106(b)(2) must be submitted to the Director, SADBU, OUSD (AT&L), and approved before developmental assistance costs may be incurred. To the maximum extent possible, such mentor-protege agreements will be approved within 5 business days of receipt.
(b) Each signed mentor-protege agreement submitted for approval under the Program must include—
(1) The name, address, and telephone number of the mentor firm and the protege firm and a point of contact within the mentor firm who will administer the developmental assistance program;
(2) The SIC code that represents the contemplated supplies or services to be provided by the protege firm to the mentor firm and a statement that, at the time the agreement is submitted for approval, the protege firm, if an SDB concern, does not exceed the size standard for the appropriate SIC code;
(3) A developmental program for the protege firm specifying the type of assistance identified in paragraph (f) of this section that will be provided. The developmental program also must include—
(i) Factors to assess the protege firm's developmental progress under the Program, including milestones for providing the identified assistance;
(ii) The anticipated number, dollar value, and type of subcontracts to be awarded the protege firm consistent with the extent and nature of the mentor firm's business, and the period of time over which the subcontracts will be awarded; and
(iii) The dollar value of the technical assistance program, broken out per year;
(4) A program participation term for the agreement that does not exceed 3 years. Requests for an extension of the agreement for a period not to exceed an additional 2 years are subject to the approval of the Director, SADBU, OUSD (AT&L), and are contingent upon the endorsement and submission of justification for such an extension from the cognizant Director, SADBU. The justification must detail the unusual circumstances that warrant a term in excess of 3 years;
(5) Procedures for the mentor firm to notify the protege firm in writing at least 30 days in advance of the mentor firm's intent to voluntarily withdraw its participation in the Program. A mentor firm may voluntarily terminate its mentor-protege agreement(s) only if it no longer wants to be a participant in the Program as a mentor firm. Otherwise, a mentor firm must terminate a mentor-protege agreement for cause;
(6) Procedures for a protege firm to notify the mentor firm in writing at least 30 days in advance of the protege firm's intent to voluntarily terminate the mentor-protege agreement;
(7) Procedures for the mentor firm to terminate the mentor-protege agreement for cause which provide that—
(i) The mentor firm must furnish the protege firm a written notice of the proposed termination, stating the specific reasons for such action, at least 30 days in advance of the effective date of such proposed termination;
(ii) The protege firm must have 30 days to respond to such notice of proposed termination, and may rebut any findings believed to be erroneous and offer a remedial program;
(iii) Upon prompt consideration of the protege firm's response, the mentor firm must either withdraw the notice of proposed termination and continue the protege firm's participation, or issue the notice of termination; and
(iv) The decision of the mentor firm regarding termination for cause, conforming with the requirements of this section, will be final and is not reviewable by DoD; and
(8) Additional terms and conditions as may be agreed upon by both parties.
(c) Mentor firms must send a copy of any termination notices to the Director, SADBU, OUSD (AT&L), and the Defense Contract Management Command administrative contracting officer responsible for conducting the annual performance review, and, where funding is made available through a DoD program manager, must provide a copy to the program manager and to the contracting officer.
(d) Termination of a mentor-protege agreement will not impair the obligations of the mentor firm to perform pursuant to its contractual obligations under Government contracts and subcontracts. Termination of all or part of the mentor-protege agreement will not impair the obligations of the protege firm to perform pursuant to its contractual obligations under any contract awarded to the protege firm by the mentor firm.
(e) Only developmental assistance provided after DoD approval of the mentor-protege agreement may be reimbursed.
(f) The mentor-protege agreement may provide for the mentor firm to furnish any or all of the following types of developmental assistance:
(1) Assistance by mentor firm personnel in—
(i) General business management, including organizational management, financial management, and personnel management, marketing, business development, and overall business planning;
(ii) Engineering and technical matters such as production inventory control and quality assurance; and
(iii) Any other assistance designed to develop the capabilities of the protege firm under the developmental program.
(2) Award of subcontracts under DoD contracts or other contracts on a noncompetitive basis.
(3) Payment of progress payments for the performance of subcontracts by a protege firm in amounts as provided for in the subcontract; but in no event may any such progress payment exceed 100 percent of the costs incurred by the protege firm for the performance of the subcontract. Provision of progress payments by a mentor firm to an SDB protege firm at a rate other than the customary rate for SDBs must be implemented in accordance with FAR 32.504(c).
(4) Advance payments under such subcontracts. The mentor firm must administer advance payments in accordance with FAR subpart 32.4.
(5) Loans.
(6) Investment(s) in the protege firm in exchange for an ownership interest in the protege firm, not to exceed 10 percent of the total ownership interest. Investment may include, but are not limited to, cash, stock, and contribution in kind.
(7) Assistance that the mentor firm obtains for the protege firm from one or more of the following:
(i) Small Business Development Centers established pursuant to Section 21 of the Small Business Act (15 U.S.C. 648).
(ii) Entities providing procurement technical assistance pursuant to 10 U.S.C. Chapter 142 (Procurement Technical Assistance Centers).
(iii) Historically Black colleges and universities.
(iv) Minority institutions of higher education.
(g) A mentor firm may not require a protege firm to enter into a mentor-protege agreement as a condition for award of a contract by the mentor firm, including a subcontract under a DoD contract awarded to the mentor firm.
(a) DoD will reimburse a mentor firm only for the cost of developmental assistance incurred by the mentor firm and provided to a protege firm under I-107(f)(1) and (7), and pursuant to an approved mentor-protege agreement. For agreements entered into prior to October 1, 1999, DoD will provide reimbursement only through a separate contract, cooperative agreement, or other agreement entered into between DoD and the mentor firm, awarded for the purpose of providing developmental assistance to one or more protege firms; a separately priced contract line item in a DoD contract; or inclusion of program costs in indirect expense pools. For agreements entered into on or after October 1, 1999, DoD will provide reimbursement only through a separately priced contract line item in a DoD contract; or through a separate contract if the Director, SADBU, OUSD(AT&L), determines the unusual circumstances justify reimbursement using a separate contract. No other means for the reimbursement of the costs of developmental assistance provided under I-107(f)(1) and (7) are authorized under the Program.
(b) Costs included in indirect expense pools will be reimbursed only to the extent that the costs are otherwise reasonable, allocable, and allowable.
(c) Assistance provided in the form of progress payments to SDB protege firms in excess of the customary progress payment rate for SDBs, will be reimbursed only if implemented in accordance with FAR 32.504(c).
(d) Assistance provided in the form of advance payments will be reimbursed only if the payments have been provided to a protege firm under subcontract terms and conditions similar to those in the clause at FAR 52.232.12, Advance Payments. Reimbursements of any advance payments will be made pursuant to the inclusion of the clause at FARS 252.232-7005, Reimbursement of Subcontractor Advance Payments—DoD Pilot Mentor-Protege Program, in appropriate contracts. In requesting reimbursement, the mentor firm agrees that the risk of any financial loss due to the failure or inability of a protege firm to repay any unliquidated advance payments will be the sole responsibility of the mentor firm.
(e) No other forms of developmental assistance are authorized for reimbursement under the Program.
(f) The total amount reimbursed to a mentor firm for costs of assistance furnished to a protege firm in a fiscal year may not exceed $1,000,000 unless the Director, SADBU, OUSD(AT&L), determines in writing that unusual circumstances justify reimbursement at a higher amount. Request for authority to reimburse in excess of $1,000,000 must detail the unusual circumstances and must be endorsed and submitted by the program manager and the cognizant Director, SADBU.
(a) Developmental assistance costs incurred by a mentor firm for providing assistance to a protege firm pursuant to an approved mentor-protege agreement, that have not been reimbursed through a separate contract, cooperative agreement, or other agreement entered into between DoD and the mentor firm, or through a separately priced contract line item added to a DoD contract, may be credited as if it were a subcontract award for determining the performance of the mentor firm in attaining an SDB subcontracting goal established under any contract containing a subcontracting plan pursuant to the clause at FAR 52.219-9, Small Business Subcontracting Plan.
(b) For crediting purposes only, costs that have been reimbursed through inclusion in indirect expense pools may also be credited as subcontract awards for determining the performance of the mentor firm in attaining an SDB subcontracting goal established under any contract containing a subcontracting plan pursuant to the clause at FAR 52.219-9. However, costs that have not
(c) Other costs that are not eligible for reimbursement pursuant to I-108(a) may be recognized for credit only if requested, identified, and incorporated in an approved mentor-protege agreement.
(d) The amount of credit a mentor firm may receive for any such unreimbursed developmental assistance costs must be equal to—
(1) Four times the total amount of such costs attributable to assistance provided by small business development centers, historically Black colleges and universities, minority institutions, and procurement technical assistance centers.
(2) Three times the total amount of such costs attributable to assistance furnished by the mentor's employees.
(3) Two times the total amount of other such costs incurred by the mentor in carrying out the developmental assistance program.
(e) A mentor firm may receive credit toward the attainment of an SDB subcontracting goal for each subcontract awarded for a product or a service by the mentor firm to an entity that qualifies as a protege firm pursuant to I-104(a). With respect to a former SDB protege firm(s), a mentor may take credit for awards to such concern(s) that, except for its size would be a small business concern owned and controlled by socially and economically disadvantaged individuals, but only if—
(1) The size of such business concern is not more than two time the appropriate size standard;
(2) The business concern formerly had a mentor-protege agreement with such mentor firm that was not terminated for cause; and
(3) The credit is taken not later than October 1, 2005.
(f) Amounts credited toward the SDB goal(s) for unreimbursed costs under the Program must be separately identified from the amounts credited toward the goal resulting from the award of actual subcontracts to protege firms. The combination of the two must equal the mentor firm's overall accomplishment toward the SDB goal(s).
(g) Adjustments may be made to the amount of credit claimed under paragraphs (a) and (b) of this section if the Director, SADBU, OUSD(AT&L), determines that—
(1) A mentor firm's performance in the attainment of its SDB subcontracting goals through actual subcontract awards declined from the prior fiscal year without justifiable cause; and
(2) Imposition of such a limitation on credit appears to be warranted to prevent abuse of this incentive for the mentor firm's participation in the Program.
(h) The mentor firm must be afforded the opportunity to explain the decline in SDB participation before imposition of any such limitation on credit. In making the final decision to impose a limitation on credit, the Director, SADBU, OUSD (AT&L), must consider—
(1) The mentor firm's overall SDB participation rates (in terms of percentages of subcontract awards and dollars awarded) as compared to the participation rates existing during the 2 fiscal years prior to the firm's admission to the Program;
(2) The mentor firm's aggregate prime contract awards during the prior 2 fiscal years and the total amount of subcontract awards under such contracts; and
(3) Such other information the mentor firm may wish to submit.
(i) The decision of the Director, SADBU, OUSD (AT&L), regarding the imposition of a limitation on credit will be final.
(j) Any prospective limitation on credit imposed by the Director, SADBU, OUSD (AT&L), must be expressed as a percentage of otherwise eligible credit, will apply beginning on a specific date in the future, and will continue until a date certain during the current fiscal year.
(k) Any retroactive limitation on credit imposed by the Director, SADBU, OUSD (AT&L), must reflect the actual costs incurred for developmental assistance (not exceeding the maximum amount reimbursed).
(l) For purposes of calculating any incentives to be paid to be a mentor firm for exceeding an SDB subcontracting goal pursuant to the clause at FAR 52.219-26, Small Disadvantaged Business Participation Program—Incentive Subcontracting, incentives will be paid only if an SDB subcontracting goal has been exceeded as a result of actual subcontract awards to SDBs (i.e., excluding credit under paragraphs (a), (b), and (c) of this section).
(m) Developmental assistance costs that are incurred pursuant to an approved mentor-protege agreement, and have been charged to, but not reimbursed through, a separate contract, cooperative agreement, or other agreement entered into between DoD and the mentor firm, or through a separately priced contract line item added to a DoD contract, will not be otherwise reimbursed, as either a direct or indirect cost, under any other DoD contract, irrespective of whether the costs have been recognized for credit against SDB subcontracting goals.
(n) Developmental assistance provided under an approved mentor-protege agreement is distinct from, and must not duplicate, any effort that is the normal and expected product of the award and administration of the mentor firm's subcontracts. Costs associated with the latter must be accumulated and charged in accordance with the contractor's approved accounting practices; they are not considered developmental assistance costs eligible for either credit or reimbursement under the Program.
Pursuant to FAR 31.109, approved mentor firms seeking either reimbursement or credit are strongly encouraged to enter into an advance agreement with the contracting officer responsible for determining final indirect cost rates under FAR 42.705. The purpose of the advance agreement is to establish the accounting treatment of the costs of the developmental assistance pursuant to the mentor-protege agreement prior to the incurring of any costs by the mentor firm. An advance agreement is an attempt by both the Government and the mentor firm to avoid possible subsequent dispute based on questions related to reasonableness, allocability, or allowability of the costs of developmental assistance under the Program. Absent an advance agreement, mentor firms are advised to establish the accounting treatment of such costs and address the need for any changes to their cost accounting practices that may result from the implementation of a mentor-protege agreement, prior to incurring any costs, and irrespective of whether costs will be reimbursed or credited.
(a) Mentor firms must report on the progress made under active mentor-protege agreements semiannually for the periods ending March 31st and September 30th. The September 30th report must address the entire fiscal year. Reports are due 30 days after the close of each reporting period. The report must include—
(1) Data on performance under the mentor-protege agreement, including dollars obligated, expenditures, credit taken under the Program, SDB subcontract awards under DoD contracts, developmental assistance provided, impact of the agreement, and progress of the agreement (A recommended format and guidance for this submission are available via the Internet at http://www.acq.osd.mil/sadbu/mentor_protege); and
(2) A copy of the SF 294, Subcontracting Report for Individual Contracts, for each contract where developmental assistance was credited, with a statement in Block 15 identifying—
(i) The amount of dollars credited to the SDB subcontract goal as a result of developmental assistance provided to protege firms under the Program; and
(ii) The number and dollar value of subcontracts awarded to the protege firm(s), broken out per protege.
(3) In addition to the reporting requirements of paragraph (a)(1) of this section, for commercial companies and companies participating in the DoD Test Program for Negotiation of Comprehensive Small Business Subcontracting Plans, indicate in Block 15 of the SF 295—
(i) The total dollars credited to the SDB goal as a result of developmental assistances provided to a protege firm(s) under the Program; and
(ii) The total dollar amount of subcontracts awarded to the protege firm(s), broken out per protege.
(b) The protege firm must report on progress made under the mentor-protege agreement annually by October 31st. The protege firm must concur with or rebut its mentor's report that covers the period ending September 30th and must provide data on the firm's employment, annual revenue, and annual participation in DoD contracts. The report is required annually during the protege firm's Program participation term and for 2 fiscal years after the expiration of the Program participation term.
(c) Progress reports must be submitted as follows:
(1) For agreements that provide credit toward SDB subcontracting goals for costs incurred under the Program, to the Director, SADBU, OUSD (AT&L), and the Defense Contract Management Command (DCMC) administrative contracting officer.
(2) For agreements that provide for reimbursement of costs incurred under the Program, to the Director, SADBU, OUSD (AT&L), the contracting officer, the DCMC administrative contracting officer, the program office, and the cognizant Director, SADBU.
The Defense Contract Management Command will conduct annual performance reviews of the progress and accomplishments realized under approved mentor-protege agreements. These reviews must verify data provided on the semiannual reports and must provide information as to—
(a) Whether all costs reimbursed to the mentor firm under the agreement were reasonably incurred to furnish assistance to the protege firm in accordance with the mentor-protege agreement and applicable regulations and procedures;
(b) Whether the mentor firm and protege firm accurately reported progress made by the protege firm in employment, revenues, and participation in DoD contracts during the Program participation term and for 2 fiscal years following the expiration of the agreement; and
(c) The amount of reimbursement, if any, that the mentor firm is eligible to receive in the remaining Program participation term of the agreement.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Final rule; correction.
This document contains corrections to the emergency interim rule to implement reasonable and prudent alternatives to avoid the likelihood that the pollock fisheries off Alaska will jeopardize the continued existence of the western population of Steller sea lions or adversely modify their critical habitat that was published in the
Effective February 4, 2000.
Kent Lind, 907-586-7650.
An emergency interim rule was published in the
On page 3902, in Table 20 to 50 CFR part 679, titled Steller Sea Lion Protection Areas in the Aleutian Islands Subarea:
In the entry for “Seguam Island”, in the fifth column of the table, remove the Longitude “172 33.06 W”, and add in its place “172 33.60 W”.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Closure.
NMFS is prohibiting directed fishing for Pacific cod by vessels catching Pacific cod for processing by the offshore component in the Western Regulatory Area of the Gulf of Alaska (GOA). This action is necessary to prevent exceeding the interim amount of the Pacific cod total allowable catch (TAC) apportioned to vessels catching Pacific cod for processing by the offshore component of the Western Regulatory Area of the GOA.
Effective 1200 hrs, Alaska local time (A.l.t.), February 7, 2000, until 2400 hrs, A.l.t., December 31, 2000.
Andrew Smoker, 907-586-7228.
NMFS manages the groundfish fishery in the GOA exclusive economic zone according to the Fishery Management Plan for Groundfish of the Gulf of Alaska (FMP) prepared by the North Pacific Fishery Management Council under authority of the Magnuson-Stevens Fishery Conservation and Management Act. Regulations governing fishing by U.S. vessels in accordance with the FMP appear at subpart H of 50 CFR part 600 and 50 CFR part 679.
In accordance with § 679.20(c)(2)(i), the interim Pacific cod TAC apportioned to vessels catching Pacific cod for processing by the offshore component in the Western Regulatory Area was established as 473 metric tons (mt), by the Interim 2000 Harvest Specifications of Groundfish for the GOA (65 FR 65, January 3, 2000).
In accordance with § 679.20(d)(1)(i), the Administrator, Alaska Region, NMFS (Regional Administrator), has determined that the interim amount of the Pacific cod TAC apportioned to vessels catching Pacific cod for processing by the offshore component of the Western Regulatory Area of the GOA will be reached. Therefore, the Regional Administrator is establishing a directed fishing allowance of 450 mt, and is setting aside the remaining 23 mt as bycatch to support other anticipated groundfish fisheries. In accordance with § 679.20(d)(1)(iii), the Regional Administrator finds that this directed fishing allowance will soon be reached. Consequently, NMFS is prohibiting directed fishing for Pacific cod by vessels catching Pacific cod for processing by the offshore component in the Western Regulatory Area of the GOA.
Maximum retainable bycatch amounts may be found in the regulations at § 679.20(e) and (f).
This action responds to the interim TAC limitations and other restrictions on the fisheries established in the interim 2000 harvest specifications for groundfish in the GOA. It must be implemented immediately to prevent overharvesting the interim amount of the Pacific cod TAC apportioned to vessels catching Pacific cod for processing by the offshore component in the Western Regulatory Area of the
This action is required by § 679.20 and is exempt from review under E.O. 12866.
16 U.S.C. 1801
Federal Aviation Administration, DOT.
Notice of proposed rulemaking (NPRM).
This document proposes the supersedure of an existing airworthiness directive (AD), applicable to certain Airbus Model A300, A310, and A300-600 series airplanes, that currently requires a one-time operational test of the fire shut-off valves (FSOV) to determine if the FSOV's are functioning correctly, and replacement of failed parts with new or serviceable parts. This action would require repetitive performance of the operational test. This action would also limit the applicability to airplanes installed with certain FSOV's. This proposal is prompted by issuance of mandatory continuing airworthiness information by a foreign civil airworthiness authority. The actions specified by the proposed AD are intended to detect and correct failure of the FSOV's to close, which could result in failure of the engine fire shut-off system, and consequent inability to extinguish an engine fire.
Comments must be received by March 13, 2000.
Submit comments in triplicate to the Federal Aviation Administration (FAA), Transport Airplane Directorate, ANM-114, Attention: Rules Docket No. 99-NM-07-AD, 1601 Lind Avenue, SW., Renton, Washington 98055-4056. Comments may be inspected at this location between 9:00 a.m. and 3:00 p.m., Monday through Friday, except Federal holidays.
The service information referenced in this AD may be obtained from Airbus Industrie, 1 Rond Point Maurice Bellonte, 31707 Blagnac Cedex, France. This information may be examined at the FAA, Transport Airplane Directorate, 1601 Lind Avenue, SW., Renton, Washington.
Norman B. Martenson, Manager, International Branch, ANM-116, FAA, Transport Airplane Directorate, 1601 Lind Avenue, SW., Renton, Washington 98055-4056; telephone (425) 227-2110; fax (425) 227-1149.
Interested persons are invited to participate in the making of the proposed rule by submitting such written data, views, or arguments as they may desire. Communications shall identify the Rules Docket number and be submitted in triplicate to the address specified above. All communications received on or before the closing date for comments, specified above, will be considered before taking action on the proposed rule. The proposals contained in this notice may be changed in light of the comments received.
Comments are specifically invited on the overall regulatory, economic, environmental, and energy aspects of the proposed rule. All comments submitted will be available, both before and after the closing date for comments, in the Rules Docket for examination by interested persons. A report summarizing each FAA-public contact concerned with the substance of this proposal will be filed in the Rules Docket.
Commenters wishing the FAA to acknowledge receipt of their comments submitted in response to this notice must submit a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket Number 99-NM-07-AD.” The postcard will be date stamped and returned to the commenter.
Any person may obtain a copy of this NPRM by submitting a request to the FAA, Transport Airplane Directorate, ANM-114, Attention: Rules Docket No. 99-NM-07-AD, 1601 Lind Avenue, SW., Renton, Washington 98055-4056.
On July 24, 1998, the FAA issued AD 98-16-09, amendment 39-10685 (63 FR 40811, July 31, 1998), applicable to certain Airbus Model A300, A310, and A300-600 series airplanes, to require a one-time operational test of the fire shut-off valves (FSOV) to determine if the FSOV's are functioning correctly, and replacement of failed parts with new or serviceable parts. That action was prompted by issuance of mandatory continuing airworthiness information by a foreign civil airworthiness authority. The requirements of that AD are intended to detect and correct failure of the FSOV's to close, which could result in failure of the engine fire shut-off system, and consequent inability to extinguish an engine fire.
Since the issuance of AD 98-16-09, the Direction Ge
Airbus issued A300/A310/A300-600 All Operator Telex (AOT) 29-22, dated November 24, 1997, which was referenced and described in AD 98-16-09 as the appropriate source of service information for accomplishment of the actions of that AD. Accomplishment of the actions specified in the AOT is intended to adequately address the identified unsafe condition. The DGAC issued French airworthiness directive 98-356-259(B), dated September 9, 1998, to mandate repetitive performance of the operational test on airplanes incorporating certain FSOV's determined to have a high failure rate in order to ensure the continued
These airplane models are manufactured in France and are type certificated for operation in the United States under the provisions of section 21.29 of the Federal Aviation Regulations (14 CFR 21.29) and the applicable bilateral airworthiness agreement. Pursuant to this bilateral airworthiness agreement, the DGAC has kept the FAA informed of the situation described above. The FAA has examined the findings of the DGAC, reviewed all available information, and determined that AD action is necessary for products of this type design that are certificated for operation in the United States.
Since an unsafe condition has been identified that is likely to exist or develop on other airplanes of the same type design registered in the United States, the proposed AD would supersede AD 98-16-09 to require repetitive accomplishment of the actions specified in the AOT described previously. This proposed AD would also limit the applicability to airplanes installed with certain FSOV's identified to have a high failure rate.
There are approximately 103 airplanes of U.S. registry that would be affected by this proposed AD.
The operational test that is currently required by AD 98-16-09, and retained in this AD, takes approximately 1 work hour per airplane to accomplish, at an average labor rate of $60 per work hour. Based on these figures, the cost impact of the currently required test on U.S. operators is estimated to be $60 per airplane, per test cycle.
The cost impact figure discussed above is based on assumptions that no operator has yet accomplished any of the current or proposed requirements of this AD action, and that no operator would accomplish those actions in the future if this AD were not adopted.
The regulations proposed herein would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this proposal would not have federalism implications under Executive Order 13132.
For the reasons discussed above, I certify that this proposed regulation (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) if promulgated, will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A copy of the draft regulatory evaluation prepared for this action is contained in the Rules Docket. A copy of it may be obtained by contacting the Rules Docket at the location provided under the caption
Air transportation, Aircraft, Aviation safety, Safety.
Accordingly, pursuant to the authority delegated to me by the Administrator, the Federal Aviation Administration proposes to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) as follows:
49 U.S.C. 106(g), 40113, 44701.
This AD applies to each airplane identified in the preceding applicability provision, regardless of whether it has been modified, altered, or repaired in the area subject to the requirements of this AD. For airplanes that have been modified, altered, or repaired so that the performance of the requirements of this AD is affected, the owner/operator must request approval for an alternative method of compliance in accordance with paragraph (c) of this AD. The request should include an assessment of the effect of the modification, alteration, or repair on the unsafe condition addressed by this AD; and, if the unsafe condition has not been eliminated, the request should include specific proposed actions to address it.
To detect and correct failure of the FSOV's to close, which could result in failure of the engine fire shut-off system, and consequent inability to extinguish an engine fire, accomplish the following:
(a) Within 600 flight hours after the effective date of this AD, perform an operational test of the 4 FSOV's on the airplane, in accordance with Airbus All Operator Telex (AOT) 29-22, dated November 24, 1997. If any FSOV fails the test, prior to further flight, replace the FSOV with a new or serviceable FSOV, in accordance with the AOT. Repeat the operational test thereafter at intervals not to exceed 600 flight hours.
(b) As of the effective date of this AD, no person shall install an FSOV, part number (P/N) B38LC50XX (where XX is 05, 06, 07, 08, 09, or 10), on any airplane, unless a successful operational test has been performed in accordance with the requirements of this AD.
(c) An alternative method of compliance or adjustment of the compliance time that provides an acceptable level of safety may be used if approved by the Manager, International Branch, ANM-116, FAA, Transport Airplane Directorate. Operators shall submit their requests through an appropriate FAA Principal Maintenance Inspector, who may add comments and then send it to the Manager, International Branch, ANM-116.
Information concerning the existence of approved alternative methods of compliance with this AD, if any, may be obtained from the International Branch, ANM-116.
(d) Special flight permits may be issued in accordance with sections 21.197 and 21.199 of the Federal Aviation Regulations (14 CFR 21.197 and 21.199) to operate the airplane to a location where the requirements of this AD can be accomplished.
The subject of this AD is addressed in French airworthiness directive 98-356-259(B), dated September 9, 1998.
Federal Aviation Administration, DOT.
Notice of proposed rulemaking (NPRM).
This document proposes the adoption of a new airworthiness directive (AD) that is applicable to certain Bombardier Model DHC-8-100, -200, and -300 series airplanes. This proposal would require a one-time detailed visual inspection to detect damage of the ladder plates and access cover areas of the upper surface of the wings, repair, if necessary, and installation of new O-ring seals. This proposal is prompted by issuance of mandatory continuing airworthiness information by a foreign civil airworthiness authority. The actions specified by the proposed AD are intended to prevent damage of the upper wing ladder plates, which could result in displacement of the adjacent channel seals and consequent reduced lightning strike protection of the fuel tanks.
Comments must be received by March 13, 2000.
Submit comments in triplicate to the Federal Aviation Administration (FAA), Transport Airplane Directorate, ANM-114, Attention: Rules Docket No. 99-NM-371-AD, 1601 Lind Avenue, SW., Renton, Washington 98055-4056. Comments may be inspected at this location between 9:00 a.m. and 3:00 p.m., Monday through Friday, except Federal holidays.
The service information referenced in the proposed rule may be obtained from Bombardier, Inc., Bombardier Regional Aircraft Division, 123 Garrett Boulevard, Downsview, Ontario M3K 1Y5, Canada. This information may be examined at the FAA, Transport Airplane Directorate, 1601 Lind Avenue, SW., Renton, Washington; or at the FAA, Engine and Propeller Directorate, New York Aircraft Certification Office, 10 Fifth Street, Third Floor, Valley Stream, New York.
James E. Delisio, Aerospace Engineer, Airframe and Propulsion Branch, ANE-171, FAA, Engine and Propeller Directorate, New York Aircraft Certification Office, 10 Fifth Street, Third Floor, Valley Stream, New York 11581; telephone (516) 256-7521; fax (516) 568-2716.
Interested persons are invited to participate in the making of the proposed rule by submitting such written data, views, or arguments as they may desire. Communications shall identify the Rules Docket number and be submitted in triplicate to the address specified above. All communications received on or before the closing date for comments, specified above, will be considered before taking action on the proposed rule. The proposals contained in this notice may be changed in light of the comments received.
Comments are specifically invited on the overall regulatory, economic, environmental, and energy aspects of the proposed rule. All comments submitted will be available, both before and after the closing date for comments, in the Rules Docket for examination by interested persons. A report summarizing each FAA-public contact concerned with the substance of this proposal will be filed in the Rules Docket.
Commenters wishing the FAA to acknowledge receipt of their comments submitted in response to this notice must submit a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket Number 99-NM-371-AD.” The postcard will be date stamped and returned to the commenter.
Any person may obtain a copy of this NPRM by submitting a request to the FAA, Transport Airplane Directorate, ANM-114, Attention: Rules Docket No. 99-NM-371-AD, 1601 Lind Avenue, SW., Renton, Washington 98055-4056.
Transport Canada Civil Aviation (TCCA), which is the airworthiness authority for Canada, notified the FAA that an unsafe condition may exist on certain Bombardier Model DHC-8-100, -200, and -300 series airplanes. TCCA advises that, during maintenance, a sealing problem was detected in the access panels of the upper wing fuel tanks. Investigation revealed that the diameter of the O-ring seals installed during manufacture on certain airplanes may be too large for the grooves of the access panels of the upper wing fuel tanks. The large diameter O-ring seals can prevent the fuel tank access panels from fitting properly to the upper wing ladder plates. This improper fit could lead to fretting and corrosion damage of the upper wing ladder plates. Such damage, if not detected and corrected, could result in displacement of the adjacent channel seals and consequent reduced lightning strike protection of the fuel tanks.
The manufacturer has issued Bombardier Service Bulletin S.B. 8-57-41, Revision ‘A', dated July 28, 1999, which describes procedures for a one-time detailed visual inspection to detect damage (i.e., fretting and/or corrosion) of the ladder plates and access cover areas of the upper surface of the wings. The service bulletin also describes procedures for installing new 0.103 inch diameter O-ring seals. Accomplishment of the actions specified in the service bulletin is intended to adequately address the identified unsafe condition. TCCA classified this service bulletin as mandatory and issued Canadian airworthiness directive CF-99-20, dated July 20, 1999, in order to assure the continued airworthiness of these airplanes in Canada.
This airplane model is manufactured in Canada and is type certificated for operation in the United States under the provisions of section 21.29 of the Federal Aviation Regulations (14 CFR 21.29) and the applicable bilateral airworthiness agreement. Pursuant to this bilateral airworthiness agreement, TCCA has kept the FAA informed of the situation described above. The FAA has examined the findings of TCCA, reviewed all available information, and determined that AD action is necessary for products of this type design that are certificated for operation in the United States.
Since an unsafe condition has been identified that is likely to exist or develop on other airplanes of the same type design registered in the United States, the proposed AD would require accomplishment of the actions specified in the service bulletin described previously, except as discussed below.
Operators should note that, although the Bombardier service bulletin specifies that the manufacturer may be
Additionally, operators should note that, the Bombardier service bulletin does not provide procedures for repair of damage within certain limits. However, this proposed AD would require the repair of damage that is determined to be within certain limits; the repair would be required to be accomplished in accordance with the Structure Repair Manual (SRM).
The FAA estimates that 235 airplanes of U.S. registry would be affected by this proposed AD, that it would take approximately 6 work hours per airplane to accomplish the proposed inspection and installation and that the average labor rate is $60 per work hour. Based on these figures, the cost impact of the proposed AD on U.S. operators is estimated to be $84,600, or $360 per airplane.
The cost impact figure discussed above is based on assumptions that no operator has yet accomplished any of the proposed requirements of this AD action, and that no operator would accomplish those actions in the future if this AD were not adopted.
The regulations proposed herein would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this proposal would not have federalism implications under Executive Order 13132.
For the reasons discussed above, I certify that this proposed regulation (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) if promulgated, will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A copy of the draft regulatory evaluation prepared for this action is contained in the Rules Docket. A copy of it may be obtained by contacting the Rules Docket at the location provided under the caption
Air transportation, Aircraft, Aviation safety, Safety.
Accordingly, pursuant to the authority delegated to me by the Administrator, the Federal Aviation Administration proposes to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) as follows:
1. The authority citation for part 39 continues to read as follows:
49 U.S.C. 106(g), 40113, 44701.
2. Section 39.13 is amended by adding the following new airworthiness directive:
This AD applies to each airplane identified in the preceding applicability provision, regardless of whether it has been modified, altered, or repaired in the area subject to the requirements of this AD. For airplanes that have been modified, altered, or repaired so that the performance of the requirements of this AD is affected, the owner/operator must request approval for an alternative method of compliance in accordance with paragraph (b) of this AD. The request should include an assessment of the effect of the modification, alteration, or repair on the unsafe condition addressed by this AD; and, if the unsafe condition has not been eliminated, the request should include specific proposed actions to address it.
To prevent damage of the upper wing ladder plates, which could result in displacement of the adjacent channel seals and consequent reduced lightning strike protection of the fuel tanks, accomplish the following:
(a) Within 60 days after the effective date of this AD, perform a one-time detailed visual inspection to detect damage (i.e., fretting and/or corrosion) of the ladder plates and access cover areas of the upper surface of the wings in accordance with paragraph III.A., III.B., or III.C., as applicable, of the Accomplishment Instructions of Bombardier Service Bulletin S.B. 8-57-41, Revision ‘A', dated July 28, 1999.
For the purposes of this AD, a detailed visual inspection is defined as: “An intensive visual examination of a specific structural area, system, installation, or assembly to detect damage, failure, or irregularity. Available lighting is normally supplemented with a direct source of good lighting at intensity deemed appropriate by the inspector. Inspection aids such as mirror, magnifying lenses, etc. may be used. Surface cleaning and elaborate access procedures may be required.”
(1) If no damage is detected, prior to further flight, install new 0.103-inch diameter O-ring seals in accordance with paragraph III.A., III.B., or III.C., as applicable, of the Accomplishment Instructions of the service bulletin.
(2) If any damage is detected that is within the limits specified in the Structure Repair Manual (SRM), prior to further flight, repair the damage in accordance with the SRM, and install new 0.103-inch diameter O-ring seals in accordance with paragraph III.A., III.B., or III.C., as applicable, of the Accomplishment Instructions of the service bulletin.
(3) If any damage is detected that is outside the limits specified in the SRM, prior to further flight, repair in accordance with a method approved by the Manager, New York Aircraft Certification Office (ACO), FAA, Engine and Propeller Directorate, and install new 0.103-inch diameter O-ring seals.
(b) An alternative method of compliance or adjustment of the compliance time that provides an acceptable level of safety may be used if approved by the Manager, New York ACO. Operators shall submit their requests through an appropriate FAA Principal Maintenance Inspector, who may add comments and then send it to the Manager, New York ACO.
Information concerning the existence of approved alternative methods of compliance with this AD, if any, may be obtained from the New York ACO.
(c) Special flight permits may be issued in accordance with sections 21.197 and 21.199 of the Federal Aviation Regulations (14 CFR 21.197 and 21.199) to operate the airplane to a location where the requirements of this AD can be accomplished.
The subject of this AD is addressed in Canadian airworthiness directive CF-99-20, dated July 20, 1999.
Federal Aviation Administration, DOT.
Notice of proposed rulemaking (NPRM).
This document proposes the supersedure of two existing airworthiness directives (AD), applicable to certain Airbus Model A320 series airplanes, that currently require modification of the rear spar web of the wing and cold expansion of certain attachment holes for the forward pintle fitting and certain holes at the actuating cylinder anchorage of the main landing gear (MLG). This proposed action would add a requirement for repetitive inspections to detect fatigue cracking in certain areas of the rear spar of the wing, and corrective action, if necessary. This proposed action would also provide for optional terminating action for the requirements of this AD. This proposal is prompted by issuance of mandatory continuing airworthiness information by a foreign civil airworthiness authority. The actions specified by the proposed AD are intended to detect and correct fatigue cracking, which may lead to reduced structural integrity of the wing and the MLG.
Comments must be received by March 13, 2000.
Submit comments in triplicate to the Federal Aviation Administration (FAA), Transport Airplane Directorate, ANM-114, Attention: Rules Docket No. 98-NM-99-AD, 1601 Lind Avenue, SW., Renton, Washington 98055-4056. Comments may be inspected at this location between 9:00 a.m. and 3:00 p.m., Monday through Friday, except Federal holidays.
The service information referenced in the proposed rule may be obtained from Airbus Industrie, 1 Rond Point Maurice Bellonte, 31707 Blagnac Cedex, France. This information may be examined at the FAA, Transport Airplane Directorate, 1601 Lind Avenue, SW., Renton, Washington.
Norman B. Martenson, Manager, International Branch, ANM-116, FAA, Transport Airplane Directorate, 1601 Lind Avenue, SW., Renton, Washington 98055-4056; telephone (425) 227-2110; fax (425) 227-1149.
Interested persons are invited to participate in the making of the proposed rule by submitting such written data, views, or arguments as they may desire. Communications shall identify the Rules Docket number and be submitted in triplicate to the address specified above. All communications received on or before the closing date for comments, specified above, will be considered before taking action on the proposed rule. The proposals contained in this notice may be changed in light of the comments received.
Comments are specifically invited on the overall regulatory, economic, environmental, and energy aspects of the proposed rule. All comments submitted will be available, both before and after the closing date for comments, in the Rules Docket for examination by interested persons. A report summarizing each FAA-public contact concerned with the substance of this proposal will be filed in the Rules Docket.
Commenters wishing the FAA to acknowledge receipt of their comments submitted in response to this notice must submit a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket Number 98-NM-99-AD.” The postcard will be date stamped and returned to the commenter.
Any person may obtain a copy of this NPRM by submitting a request to the FAA, Transport Airplane Directorate, ANM-114, Attention: Rules Docket No. 98-NM-99-AD, 1601 Lind Avenue, SW., Renton, Washington 98055-4056.
On April 26, 1993, the FAA issued AD 93-08-15, amendment 39-8563 (58 FR 27923, May 12, 1993), applicable to certain Airbus Model A320 series airplanes, which requires modification of the rear spar web of the wing.
On December 21, 1993, the FAA issued AD 93-25-13, amendment 39-8777 (59 FR 1903, January 13, 1994), applicable to certain Airbus Model A320 series airplanes, which requires cold expansion of certain attachment holes for the forward pintle fitting and certain holes at the actuating cylinder anchorage of the main landing gear (MLG).
Those actions were prompted by the results of fatigue testing conducted by the manufacturer. The requirements of those ADs are intended to prevent fatigue cracking, which may lead to reduced structural integrity of the wing and MLG.
Since the issuance of AD 93-08-13 and AD 93-25-13, the Direction Ge
Subsequent analysis of the results of the ultrasonic inspections indicated that reducing the inspection threshold for selected holes would ensure the structural integrity of the area and prevent the need for extensive repairs of the wing inner rear spar.
Airbus issued Service Bulletin A320-57-1088, dated September 30, 1996; Revision 01, dated September 17, 1997; and Revision 02, dated July 29, 1999. This service bulletin describes procedures for repetitive ultrasonic inspections to detect cracking of the rear spar of the wing in the area of holes for the attachment of the gear rib, the forward pintle fitting, and the MLG actuating cylinder anchorage. Revision 02 specifies a reduced threshold for the initial inspection of certain holes [holes 52 through 55 (actuating cylinder anchorage) and holes 82, 83, 87, and 88 (gear support rib)]; the compliance time for the initial inspection of the remaining 32 holes is unchanged.
Accomplishment of the actions specified in the service bulletin described previously is intended to adequately address the identified unsafe condition. The DGAC classified Airbus Service Bulletin A320-57-1088 as mandatory and issued French airworthiness directive 1999-264-135(B), dated June 30, 1999, in order to ensure the continued airworthiness of these airplanes in France.
Airbus also issued Service Bulletin A320-57-1089, dated December 22, 1996, Revision 01, dated April 17, 1997; and Revision 02, dated November 6, 1998. This service bulletin describes a modification of all affected fastener holes in the rear spar of the wing. The modification involves a cold re-expansion of the holes in the rear spar of the wing for the attachment of gear rib 5, the forward pintle fitting, and the actuating cylinder anchorage; cold expansion of the pintle fitting and gear rib 5; and installation of interference fit fasteners into the rear spar and gear rib 5 while maintaining a clearance fit in the actuating cylinder anchorage and pintle fitting. This service bulletin specifies that the modification would
This airplane model is manufactured in France and is type certificated for operation in the United States under the provisions of section 21.29 of the Federal Aviation Regulations (14 CFR 21.29) and the applicable bilateral airworthiness agreement. Pursuant to this bilateral airworthiness agreement, the DGAC has kept the FAA informed of the situation described above. The FAA has examined the findings of the DGAC, reviewed all available information, and determined that AD action is necessary for products of this type design that are certificated for operation in the United States.
Since an unsafe condition has been identified that is likely to exist or develop on other airplanes of the same type design registered in the United States, the proposed AD would supersede AD 93-08-15 and AD 93-25-13 to continue to require modification of the wing rear spar web and cold expansion of certain attachment holes for the forward pintle fitting and certain holes at the actuating cylinder anchorage of the MLG. The proposed AD would add a requirement for repetitive ultrasonic inspections to detect fatigue cracking in certain areas of the wing rear spar, and repair of cracking. This proposed AD also would provide for optional terminating action for the inspections proposed by this AD.
Operators should note that, although Service Bulletin A320-57-1088 specifies that the manufacturer may be contacted for a repair if cracks are found, this proposal would require the repair of those cracks to be accomplished in accordance with a method approved by the FAA or the DGAC (or its delegated agent). In light of the type of repair that would be required to address the identified unsafe condition, and in consonance with existing bilateral airworthiness agreements, the FAA has determined that, for this proposed AD, a repair approved by the FAA or the DGAC would be acceptable for compliance with this proposed AD.
There are approximately 126 airplanes of U.S. registry that would be affected by this proposed AD.
Subsequent to the issuance of AD 93-08-15 and AD 93-25-13, the FAA reviewed the figure it used in calculating the labor rate relevant to the required AD activities. In order to account for various inflationary costs in the airline industry, the FAA has found it appropriate to increase the labor rate used in these calculations from $55 per work hour to $60 per work hour. The economic impact information, below, has been revised to reflect this increase in the specified hourly labor rate.
It takes approximately 60 work hours per airplane to accomplish the modification of the rear spar web of the wing, as required by AD 93-08-15 and retained in this AD, at an average labor rate of $60 per work hour. Based on these figures, the total cost impact of the modification on U.S. operators is estimated to be $3,600 per airplane.
It takes approximately 600 work hours per airplane to accomplish the cold expansion of certain holes associated with the MLG, as required by AD 93-25-13 and retained in this AD, at an average labor rate of $60 per work hour. Required parts are provided by the manufacturer at no cost to the operators. Based on these figures, the total cost impact of the cold expansion on U.S. operators is estimated to be $36,000 per airplane.
The inspection that is proposed in this AD action would take approximately 24 work hours per airplane to accomplish, at an average labor rate of $60 per work hour. Based on these figures, the cost impact of the inspection proposed by this AD on U.S. operators is estimated to be $181,440, or $1,440 per airplane, per inspection cycle.
The cost impact figures discussed above are based on assumptions that no operator has yet accomplished any of the current or proposed requirements of this AD action, and that no operator would accomplish those actions in the future if this AD were not adopted.
Should an operator elect to accomplish the optional terminating action specified in this proposed AD, it would take approximately 750 work hours, at an average labor rate of $60 per work hour. The required parts would cost $27,036; $30,595; or $32,727; depending on the airplane configuration. Based on these figures, the cost per airplane of the optional terminating action proposed by this AD is estimated to be $72,036; $75,595; or $77,727.
The regulations proposed herein would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this proposal would not have federalism implications under Executive Order 13132.
For the reasons discussed above, I certify that this proposed regulation (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) if promulgated, will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A copy of the draft regulatory evaluation prepared for this action is contained in the Rules Docket. A copy of it may be obtained by contacting the Rules Docket at the location provided under the caption
Air transportation, Aircraft, Aviation safety, Safety.
Accordingly, pursuant to the authority delegated to me by the Administrator, the Federal Aviation Administration proposes to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) as follows:
1. The authority citation for part 39 continues to read as follows:
49 U.S.C. 106(g), 40113, 44701.
2. Section 39.13 is amended by removing amendments 39-8563 (58 FR 27923, May 12, 1993) and 39-8777 (59 FR 1903, January 13, 1994) and by adding a new airworthiness directive (AD), to read as follows:
This AD applies to each airplane identified in the preceding applicability provision, regardless of whether it has been otherwise modified, altered, or repaired in the area subject to the requirements of this AD. For airplanes that have been modified, altered, or repaired so that the performance of the requirements of this AD is affected, the owner/operator must request approval for an alternative method of compliance in accordance with paragraph (f)(1) of this AD. The request should include an assessment of the effect of the modification, alteration, or repair on the unsafe condition addressed by this AD; and, if the unsafe condition has not been eliminated, the request should include specific proposed actions to address it.
To detect and correct fatigue cracking in certain areas of the rear spar of the wing, which may lead to reduced structural integrity of the wing and the main landing gear (MLG), accomplish the following:
(a) For airplanes having manufacturer's serial numbers (MSN) 003 through 008 inclusive, and 010 through 021 inclusive: Prior to the accumulation of 12,000 total flight cycles, or within 500 flight cycles after June 11, 1993 (the effective date of AD 93-08-15, amendment 39-8563), whichever occurs later, modify the inner rear spar web of the wing in accordance with Airbus Industrie Service Bulletin A320-57-1004, Revision 01, dated September 24, 1992, or Revision 02, dated June 14, 1993.
(b) For airplanes having MSN's 002 through 051 inclusive: Prior to the accumulation of 12,000 total flight cycles, or within 2,000 flight cycles after February 14, 1994 (the effective date of AD 93-25-13, amendment 39-8777), whichever occurs later, accomplish the requirements of paragraphs (b)(1) and (b)(2) of this AD in accordance with Airbus Industrie Service Bulletin A320-57-1060, dated December 8, 1992; or Revision 02, dated December 16, 1994.
(1) Perform a cold expansion of all the attachment holes for the forward pintle fitting of the MLG, except for the holes that are for taper-lok bolts.
(2) Perform a cold expansion of the holes at the actuating cylinder anchorage of the MLG.
Accomplishment of the cold expansion in accordance with Airbus Service Bulletin A320-57-1060, Revision 01, dated April 26, 1993, is also acceptable for compliance with the requirements of paragraph (b) of this AD.
(c) For all airplanes: Perform an ultrasonic inspection to detect cracking of the rear spar of the wing, in accordance with Airbus Service Bulletin A320-57-1088, Revision 02, dated July 29, 1999; at the applicable time specified by paragraph (c)(1) or (c)(2) of this AD. Repeat the inspection thereafter at intervals not to exceed 3,600 flight cycles.
(1) For airplanes on which the actions specified by Airbus Service Bulletin A320-57-1004, Revision 02, dated June 14, 1993, or earlier version; and Airbus Service Bulletin A320-57-1060, Revision 02, dated December 16, 1994, or earlier version; have been accomplished: Perform the inspection of all applicable fastener holes within 12,000 flight cycles after accomplishment of the service bulletins, or within 750 flight cycles after the effective date of this AD, whichever occurs later.
(2) For airplanes on which the actions specified by Airbus Modification 20740 and Airbus Service Bulletin A320-57-1060, Revision 02, dated December 16, 1994, or earlier version, have been accomplished; or on which Airbus Modifications 20740, 20741, and 20796 have been accomplished: Perform the inspections at the locations and applicable times specified by paragraphs (c)(2)(i) and (c)(2)(ii) of this AD.
(i) Perform the inspection of left and right fastener holes 52 to 55, 82, 83, 87, and 88; located in the rear spar of the wing; prior to the accumulation of 17,300 total flight cycles, or within 750 flight cycles after the effective date of this AD, whichever occurs later. If any cracking is found, prior to further flight, accomplish the requirements of paragraph (c)(2)(ii) of this AD.
(ii) Except as required by paragraph (c)(2)(i) of this AD: Perform the inspection of all fastener holes located in the rear spar of the wing that are not identified in paragraph (c)(2)(i) of this AD prior to the accumulation of 20,000 total flight cycles, or within 200 flight cycles after the effective date of this AD, whichever occurs later.
Accomplishment of the actions specified by Airbus Service Bulletin A320-57-1088, dated September 30, 1996, or Revision 01, dated September 17, 1997, prior to the effective date of this AD is acceptable for compliance with the requirements of the initial inspection required by paragraph (c) of this AD.
(d) If any crack is found during any inspection required by paragraph (c) of this AD: Prior to further flight, repair in accordance with a method approved by either the Manager, International Branch, ANM-116, FAA, Transport Airplane Directorate; or the DGAC (or its delegated agent). For a repair method to be approved by the Manager, International Branch, ANM-116, as required by this paragraph, the Manager's approval letter must specifically reference this AD.
(e) Modification of all specified fastener holes in the rear spar of the wing in accordance with Airbus Service Bulletin A320-57-1089, dated December 22, 1996; Revision 01, dated April 17, 1997; or Revision 02, dated November 6, 1998; constitutes terminating action for the ultrasonic inspections required by this AD. Such modification, if accomplished prior to the accumulation of 12,000 total flight cycles, constitutes terminating action for the actions required by paragraphs (a) and (b) of this AD.
(f)(1) An alternative method of compliance or adjustment of the compliance time that provides an acceptable level of safety may be used if approved by the Manager, International Branch, ANM-116. Operators shall submit their requests through an appropriate FAA Principal Maintenance Inspector, who may add comments and then send it to the Manager, International Branch, ANM-116.
(2) Alternative methods of compliance, approved previously in accordance with AD 93-25-13; amendment 39-8777, are approved as alternative methods of compliance with this AD.
Information concerning the existence of approved alternative methods of compliance with this AD, if any, may be obtained from the International Branch, ANM-116.
(g) Special flight permits may be issued in accordance with sections 21.197 and 21.199 of the Federal Aviation Regulations (14 CFR 21.197 and 21.199) to operate the airplane to a location where the requirements of this AD can be accomplished.
The subject of this AD is addressed in French airworthiness directive 1999-264-135(B), dated June 30, 1999.
Commodity Futures Trading Commission.
Proposed rules.
The Commodity Futures Trading Commission (“Commission” or “CFTC”) is proposing to amend several provisions of its Regulation 1.17, which governs the minimum financial requirements imposed upon futures commission merchants (“FCMs”) and introducing brokers (“IBs”). The proposal would: ease the restrictions
The Commission believes that the current restriction on the withdrawal of equity capital that is based on a percentage of the amount of funds an FCM is required to segregate or set aside for customers may be unnecessary in light of other early warning capital standards and the degree of surveillance carried out by SROs over their member FCMs. The proposed amendment increasing the haircut applied to equity securities pledged as collateral for secured demand notes would provide greater conformity between the Commission's capital rules and the capital rules of the SEC.
Comments must be received on or before March 13, 2000.
Comments should be mailed to Jean A. Webb, Secretary, Commodity Futures Trading Commission, Three Lafayette Centre, 1155 21st Street, N.W., Washington, D.C. 20581. In addition, comments may be sent by facsimile to (202) 418-5521, or by electronic mail to
Henry J. Matecki, Financial Audit and Review Branch, Commodity Futures Trading Commission, 300 S. Riverside Plaza, Room 1600-N, Chicago, IL 60606; telephone (312) 886-3217; electronic mail
Commission Regulation 1.17(e)
(1) $300,000 (120 percent of the $250,000 minimum adjusted net capital requirement);
(2) Seven percent of the customer funds required to be segregated or set aside pursuant to the Commodity Exchange Act (“Act”) and Commission regulations,
(3) 120 percent of the amount of adjusted net capital required by a registered futures association of which the FCM is a member; or
(4) For an FCM that is also a securities broker or dealer registered with the Securities and Exchange Commission (“SEC”), the amount of net capital specified in SEC Rule 15c3-1(e) (17 CFR 240.15c3-1(e)).
The Joint Audit Committee (“JAC”) has petitioned the Commission to amend the restriction in (2) above to permit the withdrawal of equity capital from an FCM provided that, after giving effect to the withdrawal, the FCM's adjusted net capital is in excess of six percent of the customer segregated and secured amount.
In its petition, the JAC stated that prohibiting capital withdrawals that result in an FCM having adjusted net capital that is less than seven percent of the customer segregated and secured amount is an unnecessary regulatory burden. In support of its position, the JAC claimed that other provisions of the Commission's regulations also impose effective restraints on the excessive withdrawal of capital from an FCM by an equity holder. Specifically, the JAC noted that: (1) FCMs are required to maintain minimum adjusted net capital of at least four percent of the customer segregated and secured amount funds requirements in order to operate and to handle customer positions and funds; (2) the Commission's “early warning” notice and financial reporting requirements provide the Commission and the FCMs' designated self-regulatory organizations (“DSRO”) with the ability to monitor the financial condition and operations, including capital withdrawals, of an FCM that fails to maintain adjusted net capital at a level that exceeds six percent of the customer segregated and secured amount; and (3) the Commission's debt-equity ratio requirement imposes an effective restraint on the excessive withdrawal of equity capital.
Furthermore, the JAC stated that the changes it requested would provide greater harmony between the Commission's capital rules and the capital rules of the SEC. In this regard, the JAC noted that the SEC's capital rules permit withdrawals of capital from a broker or dealer provided that, after giving effect to the withdrawal, the broker's or dealer's net capital equals or exceeds the SEC's early warning level. Each of the reasons set forth by the JAC is discussed below.
After careful consideration of the JAC's petition and the issues that the petition presents, the Commission is proposing to amend Regulation 1.17(e) to permit equity capital withdrawals provided that, after giving effect to the withdrawals, the FCM's adjusted net capital is in excess of six percent of the customer segregated and secured amount. The Commission is not proposing to amend any of the other capital withdrawal restrictions set forth in the regulation.
An FCM is required to maintain minimum adjusted net capital of the greatest of: (A) $250,000; (B) four percent of the customer segregated and secured amount; (C) the amount of adjusted net capital required by a registered futures association of which it is a member; or (D) for securities brokers and dealers, the amount of net capital required by SEC Rule 15c3-1(a) (17 CFR
An FCM that is not in compliance with the minimum net capital requirement must transfer all customer accounts and immediately cease doing business as an FCM.
In addition, the Commission's “early warning” notice and financial reporting requirements deter excessive equity withdrawals. Commission Regulation 1.12(b)(2) requires an FCM to notify its DSRO and the Commission in writing if its adjusted net capital does not equal or exceed six percent of the customer segregated and secured amount. These early warning notices must be filed within five business days of the FCM's adjusted net capital falling below the early warning level. Moreover, Commission Regulation 1.12(g)(2) requires an FCM to give the Commission written notice at least two business days prior to a planned withdrawal of equity capital if the withdrawal would reduce excess net capital by 30 percent or more from that most recently reported in a financial report filed with the Commission.
An FCM that hits the early warning trigger is also required to file a financial report on Form 1-FR-FCM with the Commission and its DSRO as of the close of the month during which its adjusted net capital does not exceed the early warning level and for each month thereafter until three successive months have elapsed during which its adjusted net capital is at all times equal to or in excess of the early warning level.
Furthermore, the Commission's “debt-equity ratio” requirement also limits the amount of capital that may be withdrawn from an FCM. Commission Regulation 1.17(d) prohibits the withdrawal of capital from an FCM if, after giving effect to the withdrawal, the FCM's equity capital would be less than 30 percent of its debt-equity total.
(1) In the case of a corporation, the sum of its par or stated value of capital stock, paid in capital in excess of par, retained earnings, unrealized profit and loss, and other capital accounts;
(2) In the case of a partnership, the sum of its capital accounts of partners (inclusive of such partners' commodity interest and securities accounts subject to the provisions of Rule 1.17(e) concerning restrictions on withdrawals of equity capital), and unrealized profit and loss; and
(3) In the case of a sole proprietorship, the sum of its capital accounts and unrealized profit and loss.
“Debt-equity total” is defined by Regulation 1.17(d)(2) and encompasses equity capital as defined above plus loans subject to satisfactory subordination agreements that do not qualify as equity capital under Regulation 1.17(d)(1).
Finally, setting the capital withdrawal limit at the Commission's early warning level is supported by the capital withdrawal rules adopted by the SEC for securities brokers or dealers that compute their minimum net capital requirement in accordance with the SEC's “alternative” method.
Commission Regulation 1.17(h) sets forth the minimum requirements for satisfactory subordination agreements. An FCM or IB may enhance its regulatory capital by borrowing cash pursuant to subordinated loan agreements or by accepting secured demand notes. A secured demand note must be collateralized by cash or readily marketable securities.
When the Commission adopted its current capital rules in September 1978, the haircut for an equity security under SEC Rule 15c3-1(c)(2)(vi) was 30 percent. Therefore, an FCM or IB was required to apply a 30 percent haircut to an equity security collateralizing a secured demand note.
In December 1992, the SEC amended its capital rules. As part of these amendments, the SEC amended Rule 15c3-1(c)(2)(vi) by reducing the haircut on equity securities from 30 percent to 15 percent.
The Commission attempts to maintain, to the extent practicable, uniformity between its capital rules and those of the SEC. Uniform capital rules more readily permit dually-registered FCMs (
Commission Regulation 1.17(c)(5)(v) requires an FCM or IB, in computing its adjusted net capital, to apply haircuts to securities positions carried in the FCM's or IB's proprietary accounts and to securities purchased with customer funds that are required to be segregated or set aside in separate accounts. The regulation directs the FCM or IB to apply the specific haircut percentages that are set forth in SEC Rule 15c3-1(c)(2)(vi) for equity securities and Rule 15c3-1(c)(2)(vii) (17 CFR 240.15c3-1(c)(2)(vii)) for non-marketable securities, or Rule 15c3-1(f) (17 CFR 240. 15c3-1(f)) for dually registered securities brokers or dealers and FCMs that compute their minimum net capital requirements in accordance with the SEC's “alternative, or aggregate debit items,” method.
In December 1992, the SEC amended its capital rules by, among other things, revising the securities haircuts that a broker or dealer subject to the alternative capital method had to apply to securities positions in the broker's or dealer's proprietary accounts. Specifically, the amendments made the haircuts consistent regardless of the method that a broker or dealer used in computing its minimum net capital. The SEC effected the revisions by consolidating the haircuts in Rule 15c3-1(f) into Rules 15c3-1(c)(2)(vi) and 15c3-1(c)(2)(vii) and repealing15c3-1(f). Accordingly, the Commission proposes deleting the reference to Rule 15c3-1(f) in its Rule 1.17(c)(5)(v).
The Regulatory Flexibility Act (“RFA”), 5 U.S.C. 601-611, requires that agencies, in proposing rules, consider the impact of those rules on small businesses. The proposed rule amendments discussed herein would affect FCMs and IBs. The Commission has previously determined that, based upon the fiduciary nature of FCM/customer relationships, as well as the requirement that FCMs meet minimum financial requirements, FCMs should be excluded from the definition of small entity.
With respect to IBs, the Commission stated that it is appropriate to evaluate within the context of a particular rule whether some or all IBs should be considered to be small entities and, if so, to analyze the economic impact on such entities at that time.
The Paperwork Reduction Act of 1995 (PRA), 44 U.S.C. 3501
Brokers, Commodity futures.
In consideration of the foregoing and pursuant to the authority contained in the Commodity Exchange Act and, in particular, Sections 4f, 4g and 8a(5) thereof, 7 U.S.C. 6d, 6g and 12a(5), the Commission hereby proposes to amend Chapter I of Title 17 of the Code of Federal Regulations as follows:
7 U.S.C. 1a, 2, 2a, 4, 4a, 6, 6a, 6b, 6c, 6d, 6e, 6f, 6g, 6h, 6i, 6j, 6k, 6l, 6m, 6n, 6o, 6p, 7, 7a, 7b, 8, 9, 12, 12a, 12c, 13a, 13a-1, 16, 16a, 19, 21, 23, and 24.
(c) * * *
(5) * * *
(v) In the case of securities and obligations used by the applicant or registrant in computing net capital, and in the case of a futures commission merchant with securities in segregation pursuant to Section 4d(2) of the Act and these regulations which were not deposited by customers, the percentages specified in Rule 240.15c3-1(c)(2)(vi) of the Securities and Exchange Commission (17 CFR 240.15c3-1(c)(2)(vi)) (“securities haircuts”) and 100 percent of the value of “nonmarketable securities” as specified in Rule 240.15c3-1(c)(2)(vii) of the Securities and Exchange Commission (17 CFR 240.15c3-1(c)(2)(vii));
(e) * * *
(1) * * *
(ii) For a futures commission merchant or applicant therefor, 6 percent of the following amount: The customer funds required to be segregated pursuant to the Act and the regulations in this part and the foreign futures or foreign options secured amount, less the market value of commodity options purchased by customers on or subject to the rules of a contract market or a foreign board of trade for which the full premiums have been paid: Provided, however, That the deduction for each customer shall be limited to the amount of customer funds in such customer's account(s) and foreign futures and foreign options secured amounts;
(h) * * *
(1) * * *
(iii) The term “collateral value” of any securities pledged to secure a secured demand note means the market value of such securities after giving effect to the percentage deductions specified in Rule 240.15c3-1d(a)(2)(iii) of the Securities
Copyright Office, Library of Congress.
Extension of initial comment period and reply comment period. Expansion of file formats acceptable for electronic submission of comments.
The Copyright Office is extending the comment period and the reply comment period in the rulemaking on possible exemptions to the prohibition against circumvention of technological measures that control access to copyrighted works. The Office is also expanding the list of formats in which acceptable comments may be submitted electronically.
Written comments are due February 17, 2000. Reply comments are due March 20, 2000.
Submissions by electronic mail should be made to “1201@loc.gov”.
David O. Carson, General Counsel, Charlotte Douglass, Principal Legal Advisor, or Robert Kasunic, Senior Attorney Advisor, Copyright GC/I&R, P.O. Box 70400, Southwest Station, Washington, DC 20024. Telephone (202) 707-8380; telefax (202) 707-8366.
On November 24, 1999, the Copyright Office published a Notice of Inquiry seeking comment in connection with a rulemaking pursuant to section 1201(a)(1) of the Copyright Act, 17 U.S.C. 1201(a)(1), which provides that the Librarian of Congress may exempt certain classes of works from the prohibition against circumventing a technological measure that controls access to a copyrighted work. 64 FR 66139 (November 24, 1999). Comments were due on February 10, 2000; reply comments were due on March 13, 2000.
The Office has, however, received a request for a one-week extension of the filing deadline for initial comments. Moreover, the Office has already received a number of comments submitted in electronic form, and a number of those comments have not met the format requirements for electronic submissions. The Office has, therefore, decided to extend the deadlines for filing of initial and reply comments by one week in order to accommodate the request for additional time and in order to provide those persons who have submitted comments in unacceptable formats an opportunity to correct their submissions.
The new deadlines are: February 17, 2000 for initial comments and March 20, 2000 for reply comments.
As stated in the Notice of Inquiry, the Office will be placing all comments and reply comments that are submitted in electronic form on its website (http://lcweb.loc.gov/copyright/1201). Because of this, the Office prefers that comments and reply comments be submitted in electronic form. The Office has already received a large number of comments in this form, and many have not been in acceptable formats. The Notice of Inquiry required that comments sent by e-mail must be sent in the form of a MIME attachment to an e-mail message, and the attachment must be in a single file in either (1) Adobe Portable Document File (PDF) format (preferred); (2) Microsoft Word Version 7.0 or earlier; or (3) WordPerfect 7 or earlier. It also stated that comments may be submitted in electronic form on 3.5-inch write-protected diskettes or in traditional written (hard copy print) form.
The Office has received some complaints that restricting electronic comments to these three proprietary formats (Adobe PDF, Microsoft Word and WordPerfect) has created difficulties for some persons who wish to submit comments electronically. The Office is, therefore, expanding the list of acceptable formats for comments in electronic form. If submitted by e-mail, such comments must still be submitted as MIME file attachments to e-mail messages. Whether submitted by e-mail or on diskettes, comments may also be submitted in ASCII text file format or RTF (Rich Text File) format.
Concern has also been expressed about the requirement that comments include not only the name of the person making the submission, but also the submitter's mailing address, telephone number, telefax number and e-mail address. All comments submitted in electronic form will be posted on the Office's website, and some persons making comments may prefer that such personal information not be made available on the Internet. The Office is, therefore, amending the requirements relating to identifying information that must be included in a comment. At the same time it is affirming that the filer's name must be on a comment. Persons submitting electronic comments in electronic form must also include, in the e-mail message to which the comment is attached or in a cover letter accompanying the diskette, all such identifying information. Persons submitting comments in traditional written form should note that the Office may post some or all of those comments on its website; therefore, such persons who do not wish to have such identifying information made available on the website should include that information in a separate cover letter accompanying the comments.
The Office is amending its instructions concerning formats for comments as follows:
Comments and reply comments may be submitted in electronic form, in one of the following formats:
1.
2.
3.
All written comments (in electronic or nonelectronic form) should contain the name of the person making the submission, his or her title and organization (if the submission is on behalf of an organization), mailing address, telephone number, telefax number (if any) and e-mail address (if any). All written comments must at a minimum contain the name of the person making the submission.
The Office has already received some comments designated as “reply comments.” Persons submitting comments should note that a comment should not be designated as a “reply comment” unless submitted in response to one or more initial comments made by other persons. Moreover, reply comments, which are now due on March 20, 2000, should not be submitted until after the February 17, 2000 deadline for submission of initial comments.
Department of Defense (DoD).
Advance notice of proposed rulemaking and notice of public meeting.
The Acting Director of Defense Procurement is soliciting comments from both government and industry personnel regarding potential changes to the profit policy specified in the Defense Federal Acquisition Regulation Supplement (DFARS). The changes would increase the emphasis placed on technical risk as a factor in developing objective profit amounts. DoD will conduct a public meeting to discuss the potential changes as well as the comments received in response to this notice.
Mr. Robert Bemben, by telephone at (703) 695-9764; by FAX at (703) 693-9616; or by e-mail at bembenrj&acq.osd.mil.
The potential changes to the DFARS are available in draft form electronically in Microsoft Word 6.0 text format at the Cost, Pricing, and Finance Office Internet Home Page: http://www.acq.osd.mil/dp/cpf.
The draft changes do not reflect a proposed rule; they are provided for information and discussion purposes only.
Paper copies may be obtained from the point of contact specified herein.
Section 813 of the National Defense Authorization Act for Fiscal Year 2000 (Public Law 106-65) directed the Secretary of Defense to review the DoD profit guidelines to consider whether appropriate modifications, such as placing increased emphasis on technical risk as a factor for determining appropriate profit margins, would provide an increased profit incentive for contractors to develop and produce complex and innovative new technologies.
Section 813 further required the Secretary of Defense to make any changes to the profit guidelines that the Secretary determines to be necessary and to report to Congress on the results of the review.
A review of the DoD profit policy has identified potential changes to the DFARS that would increase the emphasis placed on technical risk as a factor in developing objective profit amounts. The purpose of this notice is to provide the public with a preliminary indication of changes under consideration, and to solicit comments and suggestions on those changes. After consideration of the comments submitted in writing and those offered at the public meeting, the Director of Defense Procurement may submit a draft proposed rule to the Defense Acquisition Regulations (DAR) Council for consideration. The DAR Council will publish any resulting proposed rule for additional public comments.
Department of Defense (DoD).
Proposed rule with request for comments.
The Acting Director of Defense Procurement is proposing to
Comments on the proposed rule should be submitted in writing to the address shown below on or before April 10, 2000, to be considered in the formation of the final rule.
Interested parties should submit written comments on the proposed rule to: Defense Acquisition Regulations Council, Attn: Ms. Amy Williams, PDUSD (AT&L)DP(DAR), IMD 3D139, 3062 Defense Pentagon, Washington, DC 20301-3062. Telefax (703) 602-0350.
E-mail comments submitted via the Internet should be addressed to: dfars@acq.osd.mil
Please cite DFARS Case 99-D025 in all correspondence related to this proposed rule. E-mail correspondence should cite DFARS Case 99-D025 in the subject line.
Ms. Amy Williams, (703) 602-0288.
DoD uses the clause at DFARS 252.236-7001, Contract Drawings, Maps, and Specifications, in fixed-price construction contracts. The clause presently states that the Government will provide five sets (unless another quantity is specified) of large-scale drawings and specifications to the contractor without charge; or, at the Government's option, may furnish the contractor with one set of reproducibles, or half-size drawings. This rule proposes to revise the clause to specify that the Government will provide one set of large-scale drawings and specifications to the contractor in electronic or paper media, as chosen by the contracting officer, and that the contractor will reproduce and print contract drawings and specifications as needed.
This rule was not subject to Office of Management and Budget review under Executive Order 12866, dated September 30, 1993.
The proposed rule is not expected to have a significant economic impact on a substantial number of small entities within the meaning of the Regulatory Flexibility Act, 5 U.S.C. 601,
The Paperwork Reduction Act does not apply because the rule does not impose any information collection requirements that require the approval of the Office of Management and Budget under 44 U.S.C. 3501,
Government procurement.
Therefore, DoD proposes to amend 48 CFR Part 252 as follows:
41 U.S.C. 421 and 48 CFR Chapter 1.
As prescribed in 236.570(a), use the following clause:
(a) The Government—
(1) Will provide to the Contractor, without charge, one set of large-scale contract drawings and specifications, except publications incorporated into the technical provisions by reference; and
(2) Will provide the drawings and specifications in electronic or paper media, as chosen by the Contracting Officer.
(b) The Contractor shall—
(1) Check all drawings furnished immediately upon receipt;
(2) Compare all drawings and verify the figures before laying out the work;
(3) Promptly notify the Contracting Officer of any discrepancies;
(4) Be responsible for any errors that might have been avoided by complying with this paragraph (b); and
(5) Reproduce and print contract drawings and specifications as needed.
(c) In general—
(1) Large-scale drawings shall govern small-scale drawings; and
(2) The Contractor shall follow figures marked on drawings in preference to scale measurements.
(d) Omissions from the drawings or specifications or the misdescription of details of work that are manifestly necessary to carry out the intent of the drawings and specifications, or that are customarily performed, shall not relieve the Contractor from performing such omitted or misdescribed details of the work. The Contractor shall perform such details as if fully and correctly set forth and described in the drawings and specifications.
(e) The work shall conform to the specifications and the contract drawings identified on the following index of drawings:
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of intent to prepare a supplemental environmental impact statement (SEIS) and notice of scoping process; request for comments.
The New England Fishery Management Council (Council) announces its intent to prepare an amendment to the Fishery Management Plan (FMP) for Atlantic Herring (
The Council and the Commission will discuss and take scoping comments at public meetings in February 2000. For specific dates and times, see
The Council and the Commission will take scoping comments at public meetings in Maine, Massachusetts, Rhode Island, and New Jersey. For specific locations, see
Paul J. Howard, Executive Director, New England Fishery Management Council (978) 465-0492.
The U.S. Atlantic herring fishery is managed as one stock complex along the east coast from Maine to Cape Hatteras, North Carolina, although evidence suggests that at least two separate biological stocks exist. Generally, the resource has been divided into an inshore Gulf of Maine and an offshore Georges Bank/Nantucket Shoals component. Individual spawning aggregations have been identified, such as the Jeffreys Ledge component of the Gulf of Maine stock, but quantitative data on the relative size of the aggregations are lacking. A peer-reviewed assessment of the Atlantic herring coastal stock complex was last conducted in 1998. This assessment indicated that the stock complex was at a high biomass level but was underexploited in 1997. An update of the assessment based on 1998 landings suggests that these conditions still exist in the fishery.
The Council and the Commission adopted management measures for the herring fishery in state and Federal waters in 1999 and NMFS approved most of the management measures contained in the Federal FMP on October 27, 1999. While the Commission's measures have been adopted by the states, the proposed rule to implement the Federal Atlantic Herring FMP will be published in the
While the overall TAC level for herring is more than twice the recent landing levels, the proposed TAC for the inshore Gulf of Maine component is about 60 percent of the landings from this area in 1996 and 1997. Some fishermen believe that harvesting capacity in this area should be restricted to avoid problems that result from excess fishing capacity. One of these problems could be an inefficient “race to fish” as increasing numbers of vessels try to catch herring before the TAC is reached. Additionally, the available TAC in this area will likely be taken before the 2000 fishing year is over. This could disrupt the supply of herring for various markets. As more vessels enter the fishery, more fishermen would likely fish for shorter periods of time in this area. In other management areas, recent catches have not approached the proposed TACs. One objective of the management plan is to distribute fishing effort to all management areas. Catches in Management Area 2 (Cape Cod and south) have been relatively stable over recent years. Catches in Management Area 3 (Georges Bank) increased rapidly to 40 percent of the proposed TAC from 1997 to 1998. These areas could absorb more fishing effort.
Management of many fisheries in the Northeast is complicated by excess fishing capacity, which makes it difficult to reduce fishing mortality to levels necessary for stock rebuilding. The development of a controlled access system for the Atlantic herring fishery that would allow new harvesting capacity to target the offshore areas but would prevent (and for one area slow) the development of excess capacity might solve the problems experienced in these fisheries.
The Council and the Commission are considering a wide range of options for the fishery, from—
(1) Continuing open access in each of the four areas in which the fishery takes place and continuing with the area- specific TACs as the primary control on fishing mortality (the No Action Alternative); to
(2) Introducing one of a variety of controlled access systems in one or more of these areas, coupled with related controls on fishing mortality.
The capacity controls under consideration may work in the following ways: The number of vessels permitted to fish in one or more or all of the Atlantic herring fishery zones could be limited. This may occur gradually as the number of vessels fishing in each area and their catches in that area approach its TAC. Other options that will be examined include closing one or more or all areas to new participants before fishing harvest capacity develops that exceeds the TAC for a given area.
The elements that make up a controlled access system will also be open for comment. One or more kinds of permits may be issued to one or more of the management areas. Qualification criteria will be established to determine who gets a permit to fish in one or more areas. The criteria can take many different forms. For example, it could be based on catches over a period of time, on possession of another permit, or on future performance.
A controlled access system may also contain other means of managing fishing mortality, for example, implementing such limits on fishing effort as the number of days vessels can fish, catch limits, or gear restrictions, each with or without the TACs now in place. Another alternative is to establish an individual quota system. Under this system, a specific share of the TAC is assigned to a vessel, person, or community; in some systems, these shares can be purchased or traded. Because of possible different objectives for each management area, some elements of a controlled access system
The Council and the Commission are particularly interested in answers to the following questions:
(1) Should there be a limited entry or controlled access system in the Atlantic herring fishery?
(2) If there is a limited entry or controlled access system, should it be adopted for the entire fishery or only for certain management areas?
(3) When should the limited entry or controlled access system become effective? Should it become effective on different dates in different areas?
(4) In a limited entry or controlled access system, what type of qualification criteria should be used to determine who receives a limited entry permit? For example, should permits be issued based on past landings or on a vessel holding another permit?
(5) If past landings are used to determine who qualifies for a permit, what should the level of landings be to qualify? What is the appropriate time period to be examined?
(6) What types of permit categories should be considered? For example, should there be directed fishery permits and incidental catch permits, or different permits for different gear types?
(7) Should permits be freely transferable, or should they be subject to limits?
(8) Should there be upgrading restrictions on permits?
(9) What other management measures, if any, should be included in the limited entry or controlled access system? For example, should days-at-sea limits, trip limits, or gear restrictions be used to further control effort?
(10) Should an individual quota system be part of the controlled access program? (Under current law, an individual quota system may not be submitted to the Secretary for approval and implementation before October 1, 2000.) If an individual quota system is considered,—
(a) How should individual fishing quotas be allocated?
(b) Should they be allocated to vessels, individuals, or communities?
(c) Should there be limits on the transferability of individual fishing quotas?
(d) Should there be limits on how much quota can be obtained by one permit holder?
(e) How should present and historical participation in the fishery be considered?
(f) If an individual fishing quota program is developed, how should effective enforcement, management, and observer coverage be provided, and how should fees to recover actual enforcement and management costs be structured?
(g) If an individual fishing quota is developed, how should a portion of the annual harvest be allocated to entry level fishermen, small vessel owners, and crew members who do not qualify for individual quotas?
(11) What communities do you think would be most affected by a limited entry program for Atlantic herring? How would they be affected?
(12) What social and/or cultural factors within these communities should the Council consider when developing a limited access program for Atlantic herring?
(13) What do you think are the potential social impacts (negative and/or positive) of a limited access program for Atlantic herring?
All persons affected by or otherwise interested in herring fisheries management are invited to participate in determining the scope and significance of issues to be analyzed by submitting written comments (see
The Council and the Commission will discuss and take scoping comments at public meetings as follows:
The meetings are physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aids should be directed to Paul J. Howard (see
16 U.S.C. 1801
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Advance notice of proposed rulemaking; request for comments.
The Pacific Fishery Management Council (Council) is considering management measures to reduce harvest capacity in the open access portion of the Pacific Coast groundfish fishery in Federal waters off Washington, Oregon, and California. NMFS has previously made a similar announcement relating to the limited entry and recreational portions of the fishery. This document announces a control date for the open access portion of November 5, 1999, and is intended to promote awareness of potential eligibility criteria for future access to the
Vessels entering the fisheries after November 5, 1999, may be subject to restrictions different from those that apply to vessels in the fishery prior to November 5, 1999. If catch history is used as a basis for future participation or allocation, it is likely that participation in the fishery after November 5, 1999, would not count toward future allocations or participation in a limited access scheme. Because potential eligibility criteria for future management measures may be based on historical participation, fishery participants may need to preserve records that substantiate and verify their participation in the groundfish fishery in Federal waters.
Comments may be submitted in writing by March 13, 2000.
Comments may be mailed to Jim Lone, Chairman, Pacific Fishery Management Council, 2130 SW Fifth Avenue, Suite 224, Portland OR 97201.
The Pacific Fishery Management Council at 503-326-6352; or Bill Robinson at 206-526-6140; or Svein Fougner at 562-980-4000.
The Pacific Coast Groundfish Fishery Management Plan (FMP) was approved on January 4, 1982 (47 FR 43964, October 5 1982), and has been amended 11 times. Implementing regulations for the FMP and its amendments are codified at 50 CFR Part 660. On November 16, 1992, NMFS published final regulations implementing Amendment 6 to the FMP. Amendment 6 and its implementing regulations established a license limitation program and divided the Pacific Coast commercial groundfish fishery into limited entry and open access segments. The limited entry fishery is comprised of permitted vessels using trawl, longline and/or trap (pot) gear. The open access fishery is comprised of unpermitted vessels that use all other gear, as well as vessels that do not have limited entry permits endorsed for use of longline or trap gear but make small landings with longline or trap gear.
NMFS had previously made an announcement that the Council is considering additional management measures to further limit harvest capacity or to allocate between or within the limited entry commercial and the recreational groundfish fisheries. In order to discourage fishers from intensifying their fishing efforts for the purpose of amassing catch history for any allocation or additional limited access program developed by the Council, the Council announced on April 9, 1998, that any program would not include consideration of catch landed after that date. NMFS announced that the Council was planning to consider catch history through the 1997 season (63 FR 53637, October 6, 1998).
At its April 1999 meeting, the Council reviewed a proposal to create a limited entry program to limit new entrants into the open access fishery. At this same meeting, the Council's Groundfish Advisory Subpanel (GAP) encouraged the Council to move toward the development of an individual quota (IQ) program for the limited entry and open access fisheries as a means of managing harvest capacity. Under Section 303(d)(1)(A) of the Magnuson-Stevens Fishery Conservation and Management Act, the Council cannot submit recommendations for an IQ program to the Secretary of Commerce before October 1, 2000, however, the Council is not prohibited from developing such a program.
At its June 1999 meeting, the Council further examined the proposal to create a limited entry program to limit new entrants into the open access fishery. Members of the Council expressed concerns that restricting new entrants into the fishery would not adequately address harvest capacity concerns. Even though the need to limit new entrants into the open access fleet was recognized, this measure did not go forward for further development. Limited access and participation in the open access fisheries were further discussed at the November 1999 Council meeting, resulting in this document.
Because the document published on October 6, 1998, refers specifically to management measures to restrain harvest capacity in the limited entry fishery, the Council saw a need to establish a control date for the open access fishery while management measures to restrain harvest capacity throughout the entire groundfish fishery are being considered. At its November meeting, the Council unanimously recommended that a control date of November 5, 1999, be established and the public be notified that the Council is considering the need to impose additional management measures to restrain harvest capacity in the open access fishery. The Council announced this control date for the open access portion of the Pacific Coast groundfish fishery in its November 1999 newsletter. The newsletter was distributed to the public in the middle of November.
Vessels entering the fishery after November 5, 1999, may be subject to restrictions different from those that apply to vessels in the fishery prior to November 5, 1999. If catch history is used as a basis for participation or allocation, it is likely that participation in the fishery after the control date would not count toward future allocations in a limited access scheme. Fishers are not guaranteed future participation in the groundfish fishery, regardless of their date of entry or level of participation in the fishery.
This action does not commit the Council to develop any particular management regime or to use any specific criteria for determining entry to the fishery. The Council may choose a different control date, or may choose a management program that does not make use of such a date.
Implementation of any management measures for the fishery will require amendment of the regulations implementing the FMP, and may require amending the FMP. Any action will require Council development of a regulatory proposal with public input and a supporting analysis, NMFS approval, and publication of implementing regulations in the
16 U.S.C. 1801
Forest Service, USDA.
Notice.
In accordance with the Paperwork Reduction Act of 1995, the Forest Service announces its intention to reinstate a previously approved information collection. The collected information will help the Forest Service evaluate the employment eligibility of youth 15 to 18 years old through the Youth Conservation Corps Program. Under this Program, the Forest Service cooperates with other Federal agencies to provide seasonal employment for youth.
Comments must be received in writing on or before April 10, 2000.
All comments should be addressed to Director, Youth Conservation Corps, Senior, Youth and Volunteer Programs, (Mail Stop 1136), Forest Service, USDA, P.O. Box 96090, Washington, DC 20090-6090.
Comments also may be submitted via facsimile to (703) 605-5115 or by e-mail to syvp/wo@fs.fed.us.
The public may inspect comments at the Office of the Director, Senior, Youth and Volunteer Programs, Forest Service, USDA, Room 1010, 1621 North Kent Street, Arlington, Virginia 22209. Visitors are asked to call ahead to facilitate entrance into the office.
Ransom Hughes, Youth Conservation Corps, Senior, Youth and Volunteer Programs at (703) 605-4854.
Under the Youth Conservation Corps Act of August 13, 1970, as amended (U.S.C. 18701-1706), the Forest Service, U.S. Department of Agriculture and the Fish and Wildlife Service and National Park Service, U.S. Department of Interior cooperate to provide seasonal employment for eligible youth 15 to 18 years old.
These youth, who seek training and employment with the Forest Service through the Youth Conservation Corps, must complete the following forms: FS-1800-18, Youth Conservation Corps Application, and FS-1800-3, Youth Conservation Corps Medical History. Forest Service employees use the information to evaluate the eligibility of each applicant.
The Youth Conservation Corps stresses three important objectives:
• Accomplish needed conservation work on public lands;
• Provide gainful employment for 15 to 18 year old males and females from all social, economic, ethnic, and racial backgrounds; and
• Foster, on the part of the 15 to 18 year old youth, an understanding and appreciation of the Nation's natural resources and heritage.
The following describes the information collection to be reinstated:
Data gathered in this information collection are not available from other sources.
The following describes the information collection to be reinstated:
Data gathered in this information collection are not available from other sources.
The agency invites comments on the following: (a) Whether the proposed collection of information is necessary for the stated purposes and the proper performance of the functions of the agency, including whether the information will have practical or scientific utility; (b) the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used; (c) ways to enhance the quality, utility, and
All comments received in response to this notice, including names and addresses when provided, will become a matter of public record. Comments will be summarized and included in the request for Office of Management and Budget.
Forest Service, USDA.
Notice of intent to prepare an environmental impact statement.
The USDA Forest Service will prepare an environmental impact statement (EIS) to disclose the environmental effects of management activities proposed in the Meadow-Tolan area on the Sula Ranger District of the Bitterroot National Forest. Proposed management activities include management ignited prescribed fire, timber harvest, reforestation, pre-commercial thinning, aspen restoration, and road reconstruction. The Meadow-Tolan area is located in Ravalli County, Montana, approximately 40 miles southeast of Hamilton. The Meadow-Tolan area includes the Meadow and Tolan Creek drainages and several other tributary drainages between them.
A variety of management activities proposed in the project are being considered together because they represent either connected or cumulative actions as defined by the Council on Environmental Quality (40 CFR 1508.25). The purposes of the project are (1) To restore fire and its associated ecological benefits, (2) to harvest merchantable timber, (3) to reduce fuel accumulations, especially in an area adjacent to a rural subdivision, (4) to modify forest stand structure and species composition in order to maintain or restore ecosystem diversity, (5) to reduce motorized travel to comply with Forest Plan standard, (6) to amend the Forest Plan motorized access standards in an area where other resource benefits outweigh the benefits of restricting travel, (7) to thin young stands that are overstocked, and (8) to restore aspen clones that show signs of deterioration. This project level EIS will tier to the Bitterroot National Forest Land and Resource Management Plan (Forest Plan) and Final EIS (September 1987), which provides overall guidance for all land management activities on the Bitterroot National Forest.
Written comments and suggestions should be received by March 24, 2000.
The Responsible Official is Rodd Richardson, Forest Supervisor, Bitterroot National Forest, 1801 North First, Hamilton MT 59840.
Written comments and suggestions concerning the scope of the analysis or a request to be included on the project mailing list should be sent to John Ormiston, Acting Resource Team Leader, Sula Ranger District, Bitterroot National Forest, Phone (406) 821-3201.
The project area encompasses approximately 45,000 acres of land in west-central Montana on the Bitterroot National Forest. The Meadow-Tolan area includes the Meadow and Tolan Creek drainages and several other tributary drainages of the East Fort Bitterroot River, including Vapor Creek, Swift Creek, Bugle Creek, Kerlee Creek, Springer Creek, Mink Creek, and Bruce Creek. A map and legal descriptions are available on request.
An analysis of the Meadow-Tolan area reveals changes in how the forest vegetation currently looks and functions compared to the past. Natural patterns and stand structures have changed, largely due to the absence of fire during the 1900's in this fire dependent ecosystem. The result is notable changes in plant species composition and density, stand structures, fuels, seral species regeneration, and the health and vigor of forest stands. The primary purposes of prescribed fire and timber harvest in the Meadow-Tolan area is to maintain or restore ecosystem diversity, function, and health. There is also an opportunity to address ecological trends and at the same time utilize surplus biomass for forest products. Maintaining plant community diversity will promote the range of habitats that native plants and animals evolved in. Management prescriptions to promote diversity include low to moderate intensity management ignited prescribed fire; and on some sites prescribed fire in combination with silvicultural treatments. Silvicultural treatments proposed include pre-commercial thinning, timber harvest, and reforestation.
Managing fuels using fire and silvicultural practices would decrease the risk of uncharacteristically intense fires and associated undesirable effects. These activities could also increase the ability of the Forest Service to allow more naturally occurring fires to burn in the adjoining Anaconda-Pintler Wilderness Area by reducing fuels near private property at lower elevations. This would to some degree reduce the risks to private property from natural fires allowed to burn in the wilderness.
Vegetation treatments with commercial timber harvest and management ignited prescribed fire are proposed on approximately 2530 acres and 1430 acres, respectively. Proposed management ignited fire and harvest activities focus primarily on low- to mid-elevations and dry aspects; those considered at ecological risk due to fire absence.
The prescribed fire would focus on the ponderosa pine/Douglas-fir community, which have been most altered due to fire absence. Most of these treated acres will also include slashing of undesired and unmerchantable trees.
Big game forage, including some winter range areas, would be improved in the areas to be understory burned. Intermediate harvests will also be prescribed on about 1100 acres in the ponderosa pine/Douglas-fir communities to open forest canopies, reduce Douglas-fir encroachment, improve overall productivity and health. Following harvest, all areas would be treated with understory burning in order to reduce fuels, prepare sites for regeneration, rejuvenate the shrub component, and maintain fire as an ecosystem process.
Pre-commercial thinning is also needed on about 320 acres of densely stocked submerchantable trees in order to enhance tree growth and vigor. One area of approximately 20 acres will be treated with hand thinning and piling for the purpose of fuel reduction.
Approximately 1210 acres in the moist Douglas-fir forest community would be treated using intermediate harvests to reduce stand densities, increase health and vigor of the residual stand, salvage dead and dying trees from Douglas-fir bark beetle caused mortality or root rot, and increase resilience to other insects and diseases. Approximately 160 acres would be
Due to the current level of beetle caused mortality and the expected future mortality, there are two units needing regeneration that will exceed 40 acres.
Eleven aspen stands on about 60 acres have matured and are showing signs of deterioration in the absence of fire. We propose to remove encroaching conifers by girdling or harvest and apply prescribed fire to restore aspen vigor and presence on the landscape.
We propose to establish a defensible perimeter around a cluster of private dwellings in the Echo Gulch area; thinning, pruning and prescribing fire to reduce fuels and therefore the risk of fire moving rapidly through the perimeter.
The Bitterroot Forest Plan provides guidance for management activities through its goals, objectives, standards, and management area direction. The areas of proposed management activities occur in Management Areas 1, 2, and 3a. Prescribed burning is proposed on lands within Forest Plan Management Areas 1, 2, 3a, and 3b. The management direction for these areas are briefly described, as follows. Management Area 1 emphasizes timber management, livestock and big game forage production, and roaded dispersed recreation activities. Management Area 2 emphasizes elk winter range habitat, allows for timber management and provides roaded dispersed recreation opportunities. Management Area 3a emphasizes visual quality, allows timber management, and provides roaded dispersed recreation opportunities. Management Area 3b emphasizes protection of riparian habitat and water quality and provides for water-related recreation.
Public scoping meetings and opportunities for interested parties to review and comment on the proposals for management were provided in Fall, 1998. Comments received have been retained and will be considered during the preparation of the Meadow Tolan EIS. Public participation is an important part of this analysis, continuing with additional scoping (40 CFR 1501.7), in February and March, 2000. In addition, the public is encouraged to visit with Forest Service officials at any time during the analysis and prior to the decision. The Forest Service will be seeking information, comments, and assistance from Federal, State, and local agencies and other individuals or organizations who may be interested in or affected by the proposed action.
Comments from the public and other agencies will be used in preparation of the Draft EIS. The scoping process will be used to identify issues and alternatives to the proposed action. Some public comments have already been received in conjunction with scoping documented in the Meadow-Tolan Project File. The following issues have already been identified: 1. What effects would the proposed timber harvest, road construction, and prescribed fire have on the water and fishery resources in the area? 2. What effects would the proposed actions have on ecosystem health, productivity and forest products. 3. How would road construction, timber harvesting, and prescribed burning affect wildlife species in the area? 4. How would the proposed actions affect the Tolan roadless area and adjacent undeveloped lands? 5. How would the proposed actions affect recreation and motorized access opportunities? 6. How would visual quality be affected? This list may be verified; expanded, or modified based on continued public scoping.
The Forest Service will consider a range of alternatives in the EIS. One of these will be the “no action” alternative, in which none of the proposed activities would be implemented. Additional alternatives will examine varying levels and locations for the proposed activities to achieve the proposal's purposes, as well as to respond to the issues and other resource values. The EIS will analyze the direct, indirect, and cumulative environmental effects of the alternatives. Past, present, and scheduled activities on both private and National Forest lands will be considered. The EIS will disclose the analysis of site specific mitigation measures and their effectiveness.
The Draft EIS is expected to be filed with the Environmental Protection Agency (EPA) and available for public review in July, 2000. At that time, the EPA will publish a Notice of Availability of the Draft EIS in the
The Forest Service believes, at this early stage, it is important to give reviewers notice of several court rulings related to public participation in the environmental review process. First, reviewers of draft environmental impact statements must structure their participation in the Environmental review of the proposal so that it is meaningful and alerts an agency to the reviewer's position and contentions.
To assist the Forest Service in identifying and considering issues on the proposed action, comments should be as specific as possible. Reviewers may wish to refer to the Council on Environmental Quality Regulations for implementing the procedural provisions of the National Environmental Policy Act at 40 CFR 1503.3 in addressing these points.
The responsible official for this environmental impact statement is Rodd Richardson, Forest Supervisor, Bitterroot National Forest, 1801 North First, Hamilton, MT 59840. He will decide which, if any, of the proposed actions will be implemented and will document the decision and reasons for the decision in a Record of Decision. That decision will be subject to Forest Service Appeal Regulations.
Forest Service, USDA.
Notice of intent to prepare an environmental impact statement.
The USDA Forest Service will prepare an environmental impact statement (EIS) on a proposed action to implement vegetative recovery projects, designed to restore forest stand structure and composition, within the subwatersheds of the Desolation Creek Watershed and adjacent subwatersheds of surrounding watersheds which were affected by the Bull and Summit Fires of 1996. The project area is located on the North Fork John Day Ranger District, approximately 25 air miles southeast of Ukiah, Oregon.
Proposed project activities consist of planting forest and riparian vegetation; fuels treatments to establish a more natural mosaic of fuel types across the landscape; hydrologic stability projects (road obliteration and road reconstruction); reduction of hazards along open roads; and restoration of forest stand structure and composition through precommercial thinning, commercial thinning, and salvage of timber damaged or killed in the fires. The proposed action is designed to prevent additional degradation of watershed and forest health, accelerate movement toward achieving Forest Plan goals and an ecologically sustainable and resilient system, and provide some economic return to local economies. The proposed projects will be in compliance with the 1990 Land and Resource Management Plan FEIS for the Umatilla National Forest, as amended, which provides overall guidance for management of this area.
Written comments concerning the scope of the analysis should be received on or before March 13, 2000.
Send written comments and suggestions to the Responsible Official, Craig Smith-Dixon, North Fork John Day District Ranger, P.O. Box 158, Ukiah, OR 97880.
Tim Davis, Project Team Leader, North Fork John Day Ranger District, Phone: (541) 427-3231.
The decision area contains approximately 59,700 acres with the Umatilla National Forest in Grant County, Oregon. It includes subwatersheds that were affected by the Bull and Summit Fires of 1996. The Bull Fire burned approximately 8,300 acres, and the Summit Fire burned approximately 8,000 acres on the Umatilla National Forest. Affected subwatersheds include those in the upper part of the Desolation Creek Watershed, and those in the adjacent North Fork John Day River and Granite Creek Watersheds. The legal description of the decision area is as follows: T.7S. R.33 and 34E., T.8S. R.33 and 34E., T.9S. R.33 and 34E., and T.10S. R.34E., W.M. surveyed. All proposed activities are outside the boundaries of any roadless of wilderness areas.
Originally, two separate analyses were proposed for salvage and restoration projects within the Bull and Summit Fire areas. These were: Bull Fire Restoration Project EA and the Olive Salvage CE. In January 1998, the Big Tower Fire Recovery Projects Decision Notice and Environmental Assessment was challenged in court. This analysis was concerned with the salvage and restoration of the 1996 Tower Fire. The outcome of this litigation was that the U.S. 9th Circuit Court of Appeals instructed the Forest Service to conduct an Environmental Impact Statement (EIS) for any further projects within the Tower Fire area. Based on this ruling, the North Fork John Day Ranger District determined that an EIS would be the most appropriate environmental analysis to conduct for restoration efforts on the Bull and Summit Fires.
Planting projects include reforestation in areas proposed for salvage harvest of fire damaged and killed timber, some areas proposed for fuels treatments, previously planted areas burned in the fires, and riparian areas affected by the fires. Fuels treatments could included broadcasting burning, piling and burning, jackpot burning, or mechanical slash treatments on harvested and precommercially thinned areas; as well as cutting, slashing, and burning stands of non-merchantable lodgepole pine killed in the fires. Proposed hydrologic stability projects include 1.5 miles of road obliteration and 7.0 miles of road reconstruction. Roadside hazards would be removed from along approximately 3.0 miles of Forest Road 1010. Stand structure and composition treatments include approximately 1050 acres of salvage harvest, 490 acres of commercial thinning, and 330 acres of precommercial thinning. Approximately 1.1 miles of temporary road construction is proposed to access timber harvest areas (all temporary roads would be obliterated following completion of sale activities).
An estimated 7.3 million board feet of timber would be commercially harvested, using ground based harvesting systems (tractor and harvested/forwarder). Proposed silvicultural treatments are as follows:
Activities which would occur concurrently or in association with timber harvest include subsoiling to mitigate soil compaction, waterbarring, erosion control seeding of skid trails and landings to restore soil productivity, burning of some slash, and treatment of noxious weeds.
Preliminary issues include: effects of proposed activities on water quality; effects of proposed activities on fish and habitat and aquatic Threatened, Endangered, and Sensitive (TES) species; effects of proposed activities on lynx; and ability of proposed activities to restore historic vegetation composition, structure, and pattern.
The Forest Service will consider a full range of alternatives, including a “no-action” alternative in which none of the activities proposed above would be implemented. Based on the issues gathered through scooping, the action alternatives will vary in (1) the number, type and location of projects, (2) the silvicultural and post-harvest treatments prescribed, and (3) the amount and location of harvest and thinning. Tentative action alternatives are: the proposed action, a modified proposed action which only treats fire affected stands, and an alternative which excludes any commercial harvest.
Public participation will be especially important at several points during the analysis, beginning with the scooping process (40 CFR 1501.7). Initial scoping began with the project listing in the 2000 Winter Edition of the Umatilla National Forest's Schedule of Proposed Activities. This environmental analysis and decision making process will enable additional interested and affected people to participate and contribute to
1. Identifying potential issues.
2. Identifying major issues to be analyzed in depth.
3. Identifying issues which have been covered by a relevant previous environmental analysis.
4. Considering additional alternatives based on themes which will be derived from issues recognized during scoping activities.
5. Identifying potential environmental effects of this project and alternatives (i.e. direct, indirect, and cumulative effects and connected actions).
The Draft EIS is expected to be filed with the Environmental Protection Agency (EPA) and to be available to the public for review by April, 2000. At that time, the EPA will publish a Notice of Availability of the Draft EIS in the
The Final EIS is scheduled to be completed by June, 2000. In the Final EIS, the Forest Service is required to respond to comments and responses received during the comment period that pertain to the environmental consequences discussed in the Draft EIS and applicable laws, regulations, and policies considered in making a decision regarding the proposal.
The Forest Service believes it is important to give reviewers notice, at this early stage, of several court rulings related to public participation in the environmental review process. First, reviewers of Draft EIS's must structure their participation in the environmental review of the proposal so that it is meaningful and alerts the agency to the reviewer's position and contentions.
To assist the Forest Service in identifying and considering issues and concerns on the proposed action, comments on the draft environmental impact statement should be as specific as possible. It is also helpful if comments refer to specific pages or chapters of the draft statement. Comments may also address the adequacy of the draft environmental impact statement or merits of the alternatives formulated and discussed in the statement. (Reviewers may wish to refer to the Council on Environmental Quality Regulations for implementing the procedural provisions of the National Environmental Policy Act at 40 CFR 1503.3 in addressing these points).
The Forest Service is the lead agency. Craig Smith-Dixon, District Ranger, is the Responsible Official. As the Responsible Official, he will decide which, if any, of the proposed projects will be implemented. He will document the decision and reasons for the decision in the Record of Decision. That decision will be subject to Forest Service Appeal Regulations (36 CFR part 215).
Forest Service, USDA.
Notice of Intent to prepare an Environmental Impact Statement (EIS).
The Logan Ranger District, of the Wasatch-Cache National Forest, will prepare an EIS on a proposal to authorize grazing on the North Rich Allotment at a level and in a manner consistent with direction set forth in the Forest Plan, the Rangeland Health EIS, and other applicable laws.
Comments concerning the scope of the analysis should be received in writing by March 10, 2000.
Send written comments to Brian Ferebee, District Ranger, 1500 East Highway 89, Logan, Utah 84321.
Evelyn Sibbernsen, Environmental Coordinator, Logan Ranger District, (435) 755-3620.
The Logan Ranger District proposes to authorize grazing on the North Rich Allotment at a level and in a manner consistent with direction set forth in the Forest Plan, the Wasatch-Cache Rangeland Health EIS, and other applicable laws and guidelines. In conjunction, the District proposes to revise the Allotment Management Plan (AMP) and adjust the resource management of lands within the North Rich Allotment to reflect information developed since the Forest Plan (approved in 1985) and to improve resource conditions as needed in several areas.
In an effort to continue moving present rangeland conditions toward desired conditions, select improvement and restoration projects are being proposed. Livestock grazing would be managed under a rotation system, to provide for the longterm health and sustainability of rangeland and riparian ecosystems.
Environmental analysis on the proposal began in the fall of 1998. Preliminary analysis indicated an Environmental Impact Statement would not be required. A scoping letter was mailed to more than 70 individuals, organizations, and local and state government agencies in January, 1999. An open house was held in January and a field trip was held in July, 1999. Data collection and analysis continued through the fall of 1999. In January of 2000, the responsible official and the Forest Service interdisciplinary team decided that an Environmental Impact Statement should be prepared because there may be significant environmental effects associated with the proposal.
Preliminary issues identified by the interdisciplinary team include the effects of grazing on riparian conditions, watershed health, threatened, endangered, and sensitive species, and the effects on dispersed recreation in the area.
A range of alternatives for the allotment will be considered. One of these, no action from the current situation, will be to authorize grazing under the current regime (number and type of livestock, grazing system, and maintenance of improvements). Another alternative will consider no grazing on
A decision will be made on whether or not to continue authorizing grazing on the North Rich Allotment, and if so, under what management system and with what improvements. If the decision is made to continue authorizing grazing, term grazing permits, issued by the Logan Ranger District, would authorize this use.
The public is invited to submit comments or suggestions at the address above. Comments from the January 1999 scoping will be incorporated into the analysis and need not be resubmitted. The responsible official is Brian Ferebee, District Ranger. A Draft EIS is expected to be filed in April of 2000 and the final EIS is scheduled to be filed in September of 2000.
The comment period on the draft EIS will be 45 days from the date the Environmental Protection Agency's notice of availability appears in the
In addition, Federal court decisions have established that the reviewers of the draft EIS must structure their participation in the environmental review of the proposal so that it is meaningful and alerts an agency to the reviewer's position and contentions.
Forest Service, USDA.
Notice of meeting.
The Lake Tahoe Basin Federal Advisory Committee will hold a meeting on March 7, 2000, at the Convention Center, Harrah's Lake Tahoe, Highway 50, Stateline, NV. This Committee, established by the Secretary of Agriculture on December 15, 1998, (64 FR 2876) is chartered to provide advice to the Secretary of Agriculture on December 15, 1998, (64 FR 2876) is chartered to provide advice to the Secretary on implementing the terms of the Federal Interagency Partnership on the Lake Tahoe Region and other matters raised by the Secretary.
The meeting will be held March 7, 2000, beginning at 9:00 a.m. and ending at 4:30 p.m.
The meeting will be held at the Convention Center, Harrah's Lake Tahoe, Highway 50, Stateline, NV.
Ed Gee or Jeannie Stafford, Lake Tahoe Basin Management Unit, Forest Service, 870 Emerald Bay Road Suite 1, South Lake Tahoe, CA 96150, (530) 573-2642.
The committee will meet jointly with the Lake Tahoe Basin Executives Committees. Items to be covered on the agenda include: (1) Budget Subcommittee, Communications Subcommittee & Watershed Assessment Subcommittee Reports; (2) California, Nevada and Federal Land Acquisition Processes; (3) Status of Renewing the Charter; (4) Washoe Lake Access; (5) Updating the Environmental Improvement Program (EIP); (6) Open Public Comment; (7) Vehicle Miles Traveled, US Postal Service Master Plan; (8) Status Report on the Lake Tahoe Science Advisory Team; (9) Lake Tahoe Watershed Assessment, Adaptive Management. All Lake Tahoe Basin Federal Advisory Committee meetings are open to the public. Interested citizens are encouraged to attend. Issues may be brought to the attention of the Committee during the open public comment period at the meeting or by filing written statements with the secretary for the Committee before or after the meeting. Please refer any written comments to the Lake Tahoe Basin Management Unit at the contact address stated above.
Natural Resources Conservation Service (NRCS), U.S. Department of Agriculture.
Notice of availability of proposed changes in the Iowa NRCS State Technical Guide for review and comment.
It has been determined by the NRCS State Conservationist for Iowa that changes must be made in the NRCS State Technical Guide specifically in Section 4, Practice Standards and Specifications #600, Terrace and #620, Underground Outlet to account for improved technology. These practices can be used in systems that treat highly erodible land.
Comments will be received on or before March 13, 2000.
Leroy Brown, State Conservationist, Natural Resources Conservation Service, Federal Building, 210 Walnut Street, Suite 693, Des Moines, Iowa 50309; at 515/284-4260; fax 515/284-4394.
Section 343 of the Federal Agriculture Improvement and Reform Act of 1996 states that revisions made after enactment of the law to NRCS State technical guides used to carry out highly erodible land and wetland provisions of the law shall be made available for public review and comment. For the next 30 days the NRCS will receive comments relative to the proposed changes. Following that period a determination will be made by the NRCS regarding disposition of those comments and a final determination of change will be made.
Rural Housing Service, USDA.
Correction.
The Rural Housing Service (RHS) corrects a notice published December 21, 1999 (64 FR 71601). This action is taken to correct the closing date of the “early selection pool” of $40 million from 4:00 Eastern Standard Time on February 21, 2000 to 4:00 Eastern Standard Time on February 22, 2000. This action is being taken because there will be no mail delivery on February 21, 2000 due to the Federal Holiday.
Accordingly, the notice published December 21, 1999 (64 FR 71601), is corrected as follows:
On page 71601 in the second column, in the first sentence under the heading “DATES,” the text “4:00 PM Eastern Time on February 21, 2000” should read “4:00 PM Eastern Standard Time on February 22, 2000.”
On page 71602 in the second column, Item III., in the first paragraph, the text “4 p.m. Eastern Standard Time, February 21, 2000” should read “4:00 PM Eastern Standard Time on February 22, 2000.”
On page 71602 in the second column, Item III., in the second paragraph, the text “4:00 PM, Eastern Standard Time on February 21, 2000” should read “4:00 PM Eastern Standard Time on February 22, 2000.”
U.S. Commission on Civil Rights
Friday, February 18, 2000, 9:30 a.m.
U.S. Commission on Civil Rights, 624 Ninth Street, N.W., Room 540, Washington, DC 20425.
David Aronson, Press and Communications (202) 376-8312.
Import Administration, International Trade Administration, Department of Commerce.
February 10, 2000.
Howard Smith or Brian C. Smith, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue, NW, Washington, DC 20230; telephone: (202) 482-1766 or (202) 482-5193, respectively.
Unless otherwise indicated, all citations to the Tariff Act of 1930, as amended (“the Act”), are references to the provisions effective January 1, 1995, the effective date of the amendments made to the Act by the Uruguay Round Agreements Act (“URAA”). In addition, unless otherwise indicated, all citations to the Department of Commerce's (“the Department's”) regulations are to the regulations at 19 CFR Part 351 (1999).
On December 13, 1999, the Department made its final determinations that certain cut-to-length carbon-quality steel plate products from France, India, Indonesia, Italy, Japan and the Republic of Korea are being, or are likely to be, sold in the United States at less than fair value.
In calculating the final margin for the respondent Usinor S.A., the Department improperly calculated the constructed export price (“CEP”) offset where U.S. sales were compared to constructed value. Specifically, the Department failed to include home market inventory carrying costs in the indirect selling expenses used to calculate the CEP offset. For a detailed discussion of the ministerial error allegations for France and the Department's analysis thereof,
In calculating the final margin for the respondent PT Gunawan Dianjaya Steel (“Gunawan”)/ PT Jaya Pari Steel Corporation (“Jaya Pari”), the Department (1) incorrectly calculated the indexed, weighted-average costs; (2) failed to incorporate certain adjustments to Gunawan's and Jaya Pari's U.S. sales in the margin calculation; (3) failed to include all of Jaya Pari's U.S. sales in the margin calculation; (4) incorrectly calculated December 1998 current costs by using the incorrect wholesale price
In calculating the final margin for the respondent Palini and Bertoli S.p.A., the Department incorrectly revised home market credit expense. For a detailed discussion of the ministerial error allegation for Italy and the Department's analysis thereof,
The petitioners alleged that the Department made certain ministerial errors in calculating costs for Dongkuk Steel Mill, Ltd., in the final determination We do not agree that the items identified by the petitioners constitute clerical errors. Thus, we are not amending the final determination of the antidumping duty investigation of certain cut-to-length carbon-quality steel plate products from the Republic of Korea. For a detailed discussion of the ministerial error allegations for the Republic of Korea and the Department's analysis thereof,
The products covered by these antidumping duty orders are certain hot-rolled carbon-quality steel: (1) Universal mill plates (
The merchandise subject to these orders is classified in the HTSUS under subheadings: 7208.40.3030, 7208.40.3060, 7208.51.0030, 7208.51.0045, 7208.51.0060, 7208.52.0000, 7208.53.0000, 7208.90.0000, 7210.70.3000, 7210.90.9000, 7211.13.0000, 7211.14.0030, 7211.14.0045, 7211.90.0000, 7212.40.1000, 7212.40.5000, 7212.50.0000, 7225.40.3050, 7225.40.7000, 7225.50.6000, 7225.99.0090, 7226.91.5000, 7226.91.7000, 7226.91.8000, 7226.99.0000.
Although the HTSUS subheadings are provided for convenience and Customs purposes, the written description of the merchandise covered by these orders is dispositive.
On February 2, 2000, in accordance with section 735(d) of the Act, the ITC notified the Department that a U.S. industry is materially injured by reason of imports of certain cut-to-length carbon-quality steel plate products from France, India, Indonesia, Italy, Japan, and the Republic of Korea, pursuant to section 735(b)(1)(A) of the Act. In addition, with respect to imports of subject merchandise from Japan, the ITC found that critical circumstances do not exist.
Therefore, in accordance with section 736(a)(1) of the Act, the Department will direct the United States Customs Service (“U.S. Customs”) to assess, upon further advice by the Department, antidumping duties equal to the amount by which the normal value of the merchandise exceeds the export price or constructed export price of the merchandise for all relevant entries of certain cut-to-length carbon-quality steel plate products from each of the countries named in the above-referenced antidumping duty investigations. These antidumping duties will be assessed on all unliquidated entries of imports of the subject merchandise that are entered, or
On or after the date of publication of this notice in the
This notice constitutes the antidumping duty orders with respect to certain cut-to-length carbon-quality steel plate products from France, India, Indonesia, Italy, Japan, and the Republic of Korea, pursuant to section 736(a) of the Act. Interested parties may contact the Central Records Unit, Room B-099 of the Main Commerce Building, for copies of an updated list of antidumping duty orders currently in effect.
These orders are published in accordance with section 736(a) of the Act and 19 CFR 351.211.
Import Administration, International Trade Administration, Department of Commerce.
February 10, 2000.
Cynthia Thirumalai at (202) 482-4087 (France), Robert Copyak at (202) 482-2209 (India), Eva Temkin at (202) 482-1167 (Indonesia), Kristen Johnson at (202) 482-4406 (Italy), and Stephanie Moore at (202) 482-3692 (Korea), Office of AD/CVD Enforcement, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue, NW, Washington, DC 20230.
Unless otherwise indicated, all citations to the statute are references to the provisions of the Tariff Act of 1930, as amended by the Uruguay Round Agreements Act effective January 1, 1995 (“the Act”). In addition, unless otherwise indicated, all citations to the Department's regulations are to the current regulations codified at 19 CFR Part 351 (1999).
The products covered by these antidumping duty orders are certain hot-rolled carbon-quality steel: (1) Universal mill plates (
The merchandise subject to these orders is classified in the HTSUS under subheadings: 7208.40.3030, 7208.40.3060, 7208.51.0030, 7208.51.0045, 7208.51.0060, 7208.52.0000, 7208.53.0000, 7208.90.0000, 7210.70.3000, 7210.90.9000, 7211.13.0000, 7211.14.0030, 7211.14.0045, 7211.90.0000, 7212.40.1000, 7212.40.5000, 7212.50.0000, 7225.40.3050, 7225.40.7000, 7225.50.6000, 7225.99.0090, 7226.91.5000, 7226.91.7000, 7226.91.8000, 7226.99.0000.
Although the HTSUS subheadings are provided for convenience and Customs purposes, the written description of the merchandise covered by these orders is dispositive.
On December 29, 1999, the final determination in the countervailing duty investigation of certain cut-to-length carbon-quality steel plate from India was published in the
On December 29, 1999, the final determination in the countervailing duty investigation of certain cut-to-length carbon-quality steel plate from South Korea was published in the
In accordance with section 705(d) of the Act, on December 29, 1999, the Department published its final determinations in the countervailing duty investigations of certain cut-to-length carbon-quality steel plate from France (64 FR 73277), India (64 FR 73131), Indonesia (64 FR 73155), Italy (64 FR 73244), and Korea (64 FR 73176). On February 2, 2000, the International Trade Commission (“ITC”) notified the Department of its final determination, pursuant to section 705(b)(1)(A)(i) of the Act, that an industry in the United States suffered material injury as a result of subsidized imports of certain cut-to-length carbon-quality steel plate from France, India, Indonesia, Italy, and Korea.
Therefore, countervailing duties will be assessed on all unliquidated entries of certain cut-to-length carbon-quality steel plate from France, India, Indonesia, Italy, and Korea entered, or withdrawn from warehouse, for consumption on or after July 26, 1999, the date on which the Department published its preliminary affirmative countervailing duty determinations in the
In accordance with section 706 of the Act, the Department will direct U.S. Customs officers to reinstitute the suspension of liquidation effective the date of publication of this notice in the
On or after the date of publication of this notice in the
The Indonesian steel producers P.T. Gunawan Steel and P.T. Jaya Pari are excluded from the Indonesian order because they received a
This notice constitutes the countervailing duty orders with respect to certain cut-to-length carbon-quality steel plate from France, India, Indonesia, Italy, and Korea, pursuant to section 706(a) of the Act. Interested parties may contact the CRU, for copies of an updated list of countervailing duty orders currently in effect.
These countervailing duty orders and amended final determinations are published in accordance with section 706(a) and 705 of the Act and 19 CFR 351.211 and 351.224.
Notice of Issuance of an Export Trade Certificate of Review, Application No. 99-00007.
The Department of Commerce has issued an Export Trade Certificate of Review to John L. Koenig. This notice summarizes the conduct for which certification has been granted.
Morton Schnabel, Director, Office of Export Trading Company Affairs, International Trade Administration, 202-482-5131. This is not a toll-free number.
Title III of the Export Trading Company Act of 1982 (15 U.S.C. 4001-21) authorizes the Secretary of Commerce to issue Export Trade Certificates of Review. The regulations implementing Title III are found at 15 CFR Part 325 (1999).
The Office of Export Trading Company Affairs (“OETCA”) is issuing this notice pursuant to 15 CFR 325.6(b), which requires the Department of Commerce to publish a summary of a Certificate in the
All goods and services.
All intellectual property rights associated with Products, including, but not limited to: Patents, trademarks, service marks, copyrights, trade secrets and know-how.
Export Trade Facilitation Services, including, but not limited to: consulting; international market research; marketing and trade promotion; trade show participation; insurance; legal assistance; transportation, trade documentation and freight forwarding; communication and processing of export orders; warehousing; foreign exchange; financing; taking title to goods; professional services in areas of government relations and assistance with state and federal programs and foreign trade and business protocol.
The Export Markets include all parts of the world except the United States (the fifty states of the United States, the District of Columbia, the Commonwealth of Puerto Rico, the Virgin Islands, American Samoa, Guam, the Commonwealth of the Northern Mariana Islands, and the Trust Territory of the Pacific Islands).
John L. Koenig may engage in the following activities with respect to the Export Markets:
1. Provide and/or arrange for the provision of Export Trade Facilitation Services;
2. Engage in promotion and marketing activities as they relate to exporting Products to the Export Markets;
3. Enter into exclusive and non-exclusive export sales agreements with Suppliers regarding sales of Products in the Export Markets; such agreements may prohibit Suppliers from exporting independently of John L. Koenig;
4. Enter into exclusive and non-exclusive sales and/or territorial agreements with distributors in the Export Markets;
5. Establish the price of Products for sale in the Export Markets;
6. Allocate export orders among Suppliers;
7. Obtain information from individual Suppliers regarding their inventories and near-term production schedules for the purpose of determining the availability of Products for export and coordinating exports with distributors; and
8. Enter into exclusive or non-exclusive agreements with Suppliers, Export Intermediaries, or other persons for licensing Technology Rights in Export Markets.
1. In engaging in Export Trade Activities and Methods of Operation, John L. Koenig will not intentionally disclose, directly or indirectly, to any Supplier any information about any other Supplier's costs, production, capacity, inventories, domestic prices, domestic sales, or U.S. business plans, strategies, or methods that is not already generally available to the trade or public.
2. John L. Koenig will comply with requests made by the Secretary of Commerce on behalf of the Secretary of Commerce or the Attorney General for information or documents relevant to conduct under the Certificate. The Secretary of Commerce will request such information or documents when either the Attorney General or the Secretary of Commerce believes that the information or documents are required to determine that John L. Koenig's Export Trade, Export Trade Activities, and Methods of Operation continue to comply with the standards of Section 303(a) of the Act.
1. “Export Intermediary” means a person who acts as a distributor, sales representative, sales or marketing agent, or broker, or who performs similar functions, including providing or arranging for the provision of Export Trade Facilitation Services.
2. “Supplier” means a person who produces, provides, or sells a Product.
This Certificate protects John L. Koenig and any employee acting on his behalf from private treble damage actions and government criminal and civil suits under U.S. federal and state antitrust laws for the export conduct specified in the Certificate and carried out during its effective period in compliance with its terms and conditions.
A copy of this certificate will be kept in the International Trade Administration's Freedom of Information Records Inspection Facility Room 4102, U.S. Department of Commerce, l4th Street and Constitution Avenue, NW, Washington, DC 20230.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration, Commerce; Fish and Wildlife Service (FWS), Interior.
Notice of decision.
This notice advises the public that NMFS and FWS (the Services) have decided to approve a request by Plum Creek Timber Company (Plum Creek) to modify the Plum Creek Cascades Habitat Conservation Plan (HCP) incidental take permit (PRT-808398), issued pursuant to section 10(a)(1)(B) of the Endangered Species Act of 1973, as amended, by incorporating the results of the Interstate-90 Land Exchange Act (I-90LXA). The public is also notified that the Record of Decision for this action is available upon request.
Individuals wishing copies of the Record of Decision, or other supporting documents regarding this action, should contact William Vogel; U.S. Fish and Wildlife Service; 510 Desmond Drive; Suite 102; Lacey, Washington 98503; telephone (360) 753-9440.
Plum Creek has requested modification of the HCP to accommodate the new land-base resulting from enactment of the I-90LXA. The Services' decision is to adopt the Preferred Alternative, as described in the Final Supplemental Environmental Impact Statement (FSEIS). This decision is based on a thorough review of the alternatives and their environmental consequences. By adopting the Preferred Alternative with its assurances that the mitigation program and enforcement measures be implemented, all practicable means to avoid or minimize harm have been adopted.
The Proposed HCP Modification, as described in the proposed Modification Document and analyzed in the FSEIS, provides the most comprehensive package of conservation prescriptions and activities of all of the alternatives. None of the other alternatives provide as integrated and comprehensive a package of habitat conservation as the Proposed HCP Modification. The Proposed HCP Modification accommodates the new land-base and applies the prescriptive conservation measures to the newly acquired lands within the HCP Planning Area.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of public meeting.
The Advisory Committee to the U.S. Section to ICCAT announces its spring meeting with its Species Working Groups on March 6 and 7, 2000.
The open sessions of the Committee meeting will be held on March 6, 2000, from 9:15 a.m. to 2:30 p.m., and on March 7, 2000, from 9:00 a.m. to 10 a.m. and from 11:30 a.m. to 5 p.m. Closed sessions will be held on March 6, 2000, from 2:30 p.m. to approximately 6:00 p.m., and on March 7, 2000, from 10 a.m. to 11:30 a.m.
The meeting will be held at the Holiday Inn Silver Spring, 8777 Georgia Avenue, Silver Spring, Maryland 20910.
Kim Blankenbeker at (301) 713-2276.
The Advisory Committee to the U.S. Section to ICCAT will meet in open session to receive and to discuss information on (1) 1999 ICCAT meeting results and U.S. implementation of ICCAT decisions, (2) NMFS and ICCAT research and monitoring activities, (3) the Food and Agriculture Organization's work related to illegal, unregulated, and unreported fishing, (4) the second meeting of ICCAT's Working Group on Allocation Criteria, (5) Advisory Committee operational issues, (6) consultation regarding the identification of countries that are diminishing the effectiveness of ICCAT, (7) the results of the meetings of the Committee's Species Working Groups, and (8) other matters relating to the international management of ICCAT species. The public will have access to the open sessions of the meeting, but there will be no opportunity for public comment.
Sessions of the Advisory Committee's Species Working Groups will not be open to the public, but, as noted earlier, the results of the working group discussions will be reported to the full Advisory Committee during the Committee's afternoon open session on March 7.
The meeting locations are physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aids should be directed to Kim Blankenbeker at (301) 713-2276 at least 5 days prior to the meeting date.
Commodity Futures Trading Commission.
Notice of availability of proposed amendments to contract terms and conditions.
The Minneapolis Grain Exchange (MGE or Exchange) has proposed amendments to the Exchange's durum wheat futures contract. The proposed amendments would revise the futures contract's quality specifications. The proposed amendments were submitted under the Commission's 45-day Fast Track procedures which provides that, absent any contrary action by the Commission, the proposed amendments may be deemed approved on February 24, 2000—45 days after the Commission's receipt of the proposals. The Acting Director of the Division of Economic Analysis (Division) of the Commission, acting pursuant to the authority delegated by Commission Regulation 140.96, has determined that publication of the proposed amendments is in the public interest, will assist the Commission in considering the views of interested persons, and is consistent with the purposes of the Commodity Exchange Act.
Comments must be received on or before February 25, 2000.
Interested persons should submit their views and comments to Jean A. Webb, Secretary, Commodity Futures Trading Commission, Three Lafayette Centre, 21st Street, NW Washington, DC 20581. In addition, comments may be sent by facsimile transmission to facsimile number (202) 418-5521, or by electronic mail to secretary@cftc.gov. Reference should be made to the proposed amendments to the MGE durum wheat futures contract.
Please contact John Bird of the Division of Economic Analysis, Commodity Futures Trading Commission, Three Lafayette Centre, 21st Street NW, Washington, DC 20581, telephone (202) 418-5274. Facsimile number: (202) 418-5527. Electronic mail: jbird@cftc.gov
The futures contract currently calls for the delivery of durum wheat meeting specified quality requirements. These existing requirements, with one exception, meet or exceed the standards for U.S. grade No. 2 hard amber durum wheat. In addition, the contract sets forth standards for protein content, falling number, moisture content, dockage, and hard vitreous amber kernels which are not specified in the official U.S. standards for grain. The proposed amendments would make the contract's standards conform to the requirements for U.S. No. 2 hard amber durum wheat and would reduce the contract's standards for protein content, falling number, and hard vitreous kernels. The proposed and current quality specifications are shown in the table below.
The MGE intends to apply the proposed amendments to existing contract months, commencing with the July 2000 contract month and to all newly listed contract months.
In support of the proposed amendments, the Exchange stated that:
[t]the purpose for amending the rule is to modify the deliverable Durum Wheat contract grade to more closely correspond to the standards for U.S. number 2 Hard Amber Durum Wheat. The Exchange believes the change in par commodity specifications is necessary to enhance participation and trade activity in the contract as well as to expand the available supply for delivery.
The Commission is requesting comments on the proposed amendments.
Copies of the proposed amendments will be available for inspection at the Office of the Secretariat, Commodity Futures Trading Commission, Three Lafayette Centre, 21st Street NW, Washington, DC 20581. Copies of the proposed amendments can be obtained through the Office of the Secretariat by mail at the above address, by phone at (202) 418-5100, or via the Internet at secretary@cftc.gov.
Other materials submitted by the Exchange in support of the proposal may be available upon request pursuant to the Freedom of Information Act (5 U.S.C. 552) and the Commission's regulations thereunder (17 CFR Part 145 (1987)), except to the extent they are entitled to confidential treatment as set forth in 17 CFR 145.5 and 145.9. Requests for copies of such materials should be made to the FOI, Privacy and Sunshine Act Compliance Staff of the Office of Secretariat at the Commission's headquarters in accordance with 17 CFR 145.7 and 145.8.
Any person interested in submitting written data, views, or arguments on the proposed amendments, or with respect to other materials submitted by the Exchange, should send such comments to Jean A. Webb, Secretary, Commodity Futures Trading Commission, Three Lafayette Centre, 21st Street NW, Washington, DC 20581 by the specified date.
The Defense Science Board (DSB) Task Force on Impact of DoD Acquisition Policies and Practices on the Health and Competitiveness of U.S. Defense Companies will meet in closed session on February 22, 2000; March 7, 2000; and tentatively on March 21-22, 2000; April 5-7, 2000; and April 20-21, 2000. All meetings will be held at TRW Inc., 1001 19th Street North, Suite 800, Arlington, VA 22209.
The mission of the Defense Science Board is to advise the Secretary of Defense and the Under Secretary of Defense for Acquisition. Technology & Logistics on scientific and technical matters as they affect the perceived needs of the Department of Defense. At these meetings, the Task Force will review the Department of Defense's acquisition policies and regulations governing the primary vendors of military equipment; determine whether these acquisition policies, processes and regulations have supported or weakened rational and economical business practices within the primary vendors of military equipment; and assess the impact of those policies, practices and regulations on the health and competitiveness of U.S. defense companies. The Task Force plans to hold sensitive programmatic discussions with the primary vendors during the course of this effort.
In accordance with Section 10(d) of the Federal Advisory Committee Act, P.L. No. 92-463, as amended (5 U.S.C. App. II, (1994)), it has been determined that these Defense Science Board meetings, concern matters listed in 5 U.S.C. § 552b(c) (1) and (4) (1994), and that accordingly these meetings will be closed to the public.
Department of the Navy, DoD.
Notice.
This Notice provides information on withdrawal of surplus property at the Naval Air Station, Key West, Florida.
For further information, contact Richard A. Engel, Head, BRAC Real Estate Section, Department of the Navy, Real Estate Operations, Naval Facilities Engineering Command, Washington Navy Yard, 1322 Patterson Avenue, SE, Suite 1000, Washington, DC 20374-5065, telephone (202) 685-9203, or E. R. Nelson, Jr., Director, Real Estate Division, Southern Division, Naval Facilities Engineering Command, P.O. Box 190010, 2155 Eagle Drive, North Charleston, SC 29419-9010, telephone (803) 820-7494.
In 1995, the Naval Air Station, Key West, Florida was designated for realignment pursuant to the Defense Base Closure and Realignment Act of 1990, Public Law 101-510, as amended. Pursuant to this designation, in April of 1996, approximately 168.14 acres of land and related facilities at this installation were declared surplus to the federal government and available for use by (a) non-federal public agencies pursuant to various statutes which authorize
Pursuant to paragraph (7)(B) of Section 2905(b) of the Defense Base Closure and Realignment Act of 1990, as amended by the Base Closure Community Redevelopment and Homeless Assistance Act of 1994, the following information regarding the withdrawal of previously reported surplus property at the Naval Air Station, Key West, FL is published in the
Department of the Navy, DOD.
Notice of meeting.
The Board of Advisors to the Superintendent, Naval Postgraduate School, Monterey, California, will meet to elicit the advice of the board on the Navy's Postgraduate Education Program. All sessions will be open to the public.
The meeting will be held on Wednesday, February 16, and Thursday, February 17, 2000, from 8:30 a.m. to 5 p.m.
The meeting will be held at the Sheraton Crystal City Hotel, Arlington, VA.
Ms. Jaye Panza, Naval Postgraduate School, Monterey, CA 93943-5000, telephone number (831) 656-2514.
The board examines the effectiveness with which the Navy's Postgraduate Education School is accomplishing its mission. To this end, the board will inquire into the curricula; instruction; physical equipment; administration; state of morale of the student body, faculty, and staff; fiscal affairs; and any other matters relating to the operation of the Naval Postgraduate School as the board considers pertinent.
Department of Education.
The Leader, Information Management Group, Office of the Chief Information Officer, invites comments on the proposed information collection requests as required by the Paperwork Reduction Act of 1995.
Interested persons are invited to submit comments on or before April 10, 2000.
Section 3506 of the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35) requires that the Office of Management and Budget (OMB) provide interested Federal agencies and the public an early opportunity to comment on information collection requests. OMB may amend or waive the requirement for public consultation to the extent that public participation in the approval process would defeat the purpose of the information collection, violate State or Federal law, or substantially interfere with any agency's ability to perform its statutory obligations. The Leader, Information Management Group, Office of the Chief Information Officer, publishes that notice containing proposed information collection requests prior to submission of these requests to OMB. Each proposed information collection, grouped by office, contains the following: (1) Type of review requested,
The Department of Education is especially interested in public comment addressing the following issues: (1) Is this collection necessary to the proper functions of the Department; (2) will this information be processed and used in a timely manner; (3) is the estimate of burden accurate; (4) how might the Department enhance the quality, utility, and clarity of the information to be collected; and (5) how might the Department minimize the burden of this collection on the respondents, including through the use of information technology.
Officer.
Requests for copies of the proposed information collection request may be accessed from
Written comments or questions regarding burden and/or the collection activity requirements should be directed to Joseph Schubart at (202) 708-9266 or via his internet address Joe_Schubart@ed.gov. Individuals who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339.
Federal Interagency Coordinating Council, Education.
Notice of a public meeting.
This notice describes the schedule and agenda of a forthcoming meeting of the Federal Interagency Coordinating Council (FICC), and invites people to participate. Notice of this meeting is required under section 644(c) of the Individuals with Disabilities Education Act (IDEA) and is intended to notify the general public of their opportunity to attend the meeting. The meeting will be accessible to individuals with disabilities. The FICC will attend to ongoing work including reports from committees and task forces. A Policy Forum on Assessment of Children with Special Needs sponsored by the Maternal and Child Health Bureau (MCH), will be held on Thursday morning from 9 a.m.-12 noon in the Rm 1E110 of US Department of Education, 400 Maryland Ave., SW; Washington, DC 20202. The meeting is open to the Public.
FICC Meeting: Thursday, March 2, 2000 from 2 to 5 p.m.
U.S. Dept. of Education; Barnard Auditorium; 400 Maryland Avenue, SW; Washington, DC 20202 (near the Federal Center Southwest and L'Enfant metro stops).
Bobbi Stettner-Eaton or Obral Vance—U.S. Department of Education, 330 C Street, SW—Room 3080; Switzer Building; Washington, DC 20202-2644. Telephone: (202) 205-5507. Individuals who use a telecommunications device for the deaf (TDD) may call (202) 205-9754.
The Federal Interagency Coordinating Council (FICC) is established under section 644(c) of the Individuals with Disabilities Education Act (20 U.S.C. 1484a). The Council is established to: (1) Minimize duplication across Federal, State and local agencies of programs and activities relating to early intervention services for infants and toddlers with disabilities and their families and preschool services for children with disabilities; (2) ensure effective coordination of Federal early intervention and preschool programs, including Federal technical assistance and support activities; and (3) identify gaps in Federal agency programs and services and barriers to Federal interagency cooperation. To meet these purposes, the FICC seeks to: (1) Identify areas of conflict, overlap, and omissions in interagency policies related to the provision of services to infants, toddlers, and preschoolers with disabilities; (2) develop and implement joint policy interpretations on issues related to infants, toddlers, and preschoolers that cut across Federal agencies, including modifications of regulations to eliminate barriers to interagency programs and activities; and (3) coordinate the provision of technical assistance and dissemination of best practice information. The FICC is chaired by the Assistant Secretary for Special Education and Rehabilitative Services.
The meeting of the FICC is open to the public and will be physically accessible. Anyone requiring accommodations such as an interpreter, materials in Braille, large print, or cassette please call Obral Vance at (202) 205-5507 (voice) or (202) 205-9754 (TDD) ten days in advance of the meeting.
Summary minutes of the FICC meetings will be maintained and available for public inspection at the U.S. Department of Education, 330 C Street, SW, Room 3080, Switzer Building, Washington, DC 20202-2644, from the hours of 9 a.m. to 5 p.m., weekdays, except Federal Holidays.
This notice provides the proposed agenda of a forthcoming meeting of the National Board of the Fund for the Improvement of Postsecondary Education. This notice also describes the functions of the Board. Notice of this meeting is required under Section 10(a)(2) of the Federal Advisory Committee Act.
February 24, 2000, 9:30 a.m. to 4:00 p.m.
Marriott at Metro Center, 775 12th Street N.W., Washington, D.C.
Sandra Newkirk, U.S. department of Education, 1990 K Street N.W., Washington, D.C. 20006-8544. Telephone: (202) 502-7500. Individuals who use a telecommunication device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 between 8:00 a.m. and 8:00 p.m., Eastern time, Monday through Friday.
Individuals with disabilities may obtain this document in an alternate format (
The National Board of the Fund for the Improvement of Postsecondary Education is established under title VII, Part B, Section 742 of the Higher Education Amendments of 1998 (20 U.S.C. 1138a). The National Board of the Fund is authorized to recommend to the Director of the Fund and the Assistant Secretary for Postsecondary Education priorities for funding and procedures for grant awards.
The meeting of the National Board is open to the public. The National Board will meet on Friday, February 24 from 9:30 a.m. to 4:00 p.m. to provide an overview of the Fund's program status and special initiatives.
The meeting site is accessible to individuals with disabilities. An individual with a disability who will need an auxiliary aid or service to participate in the meeting (
Records are kept of all Board proceedings, and are available for public inspection at the office of the Fund for the Improvement of Postsecondary Education, 8th Floor, 1990 K Street N.W., Washington, D.C. 20006-8544 from the hours of 8:00 a.m. to 4:30 p.m.
Take notice that on January 31, 2000, ANR Pipeline Company (ANR) tendered for filing this reconciliation report as required by Section 28.1 (a)(3) of the General Terms and Conditions (GT&C) of its Second Revised Volume No. 1 FERC Gas Tariff.
ANR states that the reconciliation report is regarding the recovery of transition costs ANR incurred pursuant to Order NO. 636. ANR reports that it has experienced a slight underrecovery of transition costs ($22,520), which it does not propose to collect from its customers.
Any person desiring to be heard or to protest said filing should file a motion to intervene or a protest with the Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, D.C. 20426, in accordance with Sections 385.214 or 385.211 of the Commission's Rules and Regulations. All such motions or protests must be filed on or before February 11, 2000. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. Any person wishing to become a party must file a motion to intervene. Copies of this filing are on file with the Commission and are available for public inspection in the Public Reference Room. This filing may be viewed on the web at http://www.ferc.fed.us/online/rims.htm (call 202-208-2222 for assistance).
Take notice that on February 1, 2000, Maritimes & Northeast Pipeline, L.L.C. (Maritimes) tendered for filing as part of its FERC Gas Tariff, First Revised Volume No. 1, following tariff sheet, to become effective on February 1, 2000:
Maritimes states that it is filing the above tariff sheet to implement four negotiated rate agreements pursuant to Rate Schedule MN365 and Section 24 of the General Terms and Conditions of Maritimes' FERC Gas Tariff.
Any person desiring to be heard or to protest said filing should file a motion to intervene or a protest with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with Sections 385.214 or 385.211 of the Commission's Rules and Regulations. All such motions or protests must be filed in accordance with Section 154.210 of the Commission's Regulations. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. Any person wishing to become a party must file a motion to intervene. Copies of this filing are on file with the Commission and are available for public inspection in the Public Reference Room. This filing may be viewed on the web at http://www.ferc.fed.us/online/rims.htm (call 202-208-2222 for assistance).
Take notice that on January 31, 2000, Midwestern Gas Transmission Company (Midwestern) tendered for filing its sixth annual cashout report for the September 1998 through August 1999 period.
Midwestern states that the cashout report reflects a cashout gain during this period of $5,742. Midwestern's cumulative losses from its cashout mechanism are thereby reduced to $191,532. Midwestern states that it will roll forward this loss into its next annual cashout report.
Any person desiring to be heard or to protest said filing should file a motion to intervene or a protest with the Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, D.C. 20426, in accordance with Sections 385.214 or 385.211 of the Commission's Rules and Regulations. All such motions or protests must be filed on or before February 11, 2000. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. Any person wishing to become a party must file a motion to intervene. Copies of this filing are on file with the Commission and are available for public inspection in the Public Reference Room. This filing may be viewed on the web at http://www.ferc.fed.us/online/rims.htm (call 202-208-2222 for assistance).
Take notice the Ecological Resources subgroup of the Mokelumne Relicensing Collaborative will meet on Thursday, February 10, 2000, from 9 a.m. to 6 p.m.; February 23-25, March 1-2, and March 22-23, 2000, from 9 a.m. to 4 p.m.
Take notice the Recreation subgroup will meet on Monday, February 14, and March 21-23, 2000, from 9 a.m. to 4 p.m. The meetings of the Ecological Resources and Recreation subgroups will be held at the PG&E offices, 2740 Gateway Oaks Drive, in Sacramento, California. Expected participants need to give their names to David Moller (PG&E) at (415) 973-4696.
For further information, please contact Diana Shannon at (202) 208-7774.
On February 10, 2000, the Commission staff will meet with Petal Gas Storage Company (Petal). This meeting is in response to Petal's February 2, 2000 letter requesting a meeting with Commission staff to discuss a proposed amendment to Petal's pending application in the above referenced proceeding. In its letter Petal states that the proposed amendment would reduce the amount of facilities to be constructed. The meeting will commence at 2:00 PM, in room 72-76 at the Commission's headquarters, 888 First Street NE, Washington, DC.
Take notice that on January 27, 2000, Williston Basin Interstate Pipeline Company (Williston Basin), P.O. Box 5601, Bismarck, North Dakota 58506-5601, filed in Docket No. CP00-73-000, an application pursuant to Section 7(b) of the Natural Gas Act (NGA), and Part 157 of the Commission's Regulations thereunder (18 CFR 157.7 and 157.18), for an order permitting and approving the abandonment of a delivery tap, located in Carbon County, Montana, all as more fully set forth in the request which is on file with the Commission and open to public inspection. The application may be viewed on the web at
Williston Basin states that on December 29, 1999, a fire destroyed the Carbon County Machine Shop (Shop), near Bridger, Montana. Williston Basin owned a delivery tap and riser located approximately eight inches from the outside wall of the shop. this delivery tap had not been used in several years and the shop was served by the local distribution company. Carbon County authorities requested Williston Basin to remove its tap and riser immediately in order to ensure the safety of the Carbon County demolition crew when the building was being demolished and removed. On January 4, 2000, Williston Basin removed the tap, riser and approximately 20 feet of 1-inch diameter pipeline.
Any questions regarding this application should be directed to Keith A. Tiggelaar, Manager, Regulatory Affairs for Williston Basin, P.O. Box 5601, Bismarck, North Dakota 58506-5601, at (701) 530-1560.
Any person desiring to be heard or to make any protest with reference to said application should, on or before February 25, 2000, file with the Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, D.C. 20426, a protest or a motion to intervene in accordance with the requirements of the Commission's Rules of Practice and Procedure (18 CFR 385.211 or 385.214) and the Regulations under the Natural Gas Act (18 CFR 157.10). All protests filed with the Commission will be considered by it in determining the appropriate action to be taken but will not serve to make the protestants parties to the proceeding. Any person wishing to become a party to a proceeding or to participate as a party in any hearing therein must file a motion to intervene in accordance with the Commission's Rules.
Take further notice that, pursuant to the authority contained in and subject to the jurisdiction conferred upon the Federal Energy Regulatory Commission by Sections 7 and 15 of the Natural Gas Act and the Commission's Rules of Practice and Procedures, a hearing will be held without further notice before the Commission on this application if no protest or motion to intervene is filed with the time required herein. At that time, the Commission, on its own review of the matter, will determine whether granting the abandonment is required by the public convenience and necessity. If a protest or motion for leave to intervene is timely field, or if the Commission on its own motion believes that a formal hearing is required, further notice of such hearing will be duly given.
Under the procedure herein provided for, unless otherwise advised, it will be unnecessary for Williston Basin to appear or to be represented at the hearing.
Take notice that the following filings have been made with the Commission:
Take notice that on January 28, 2000, Cook Inlet Energy Supply Limited Partnership (Cook Inlet) tendered for filing an application pursuant to Section 203 of the Federal Power Act for authorization of a transfer of interests in Cook Inlet and the conversion of Cook Inlet into a limited liability company.
Take notice that on January 28, 2000, Panda Leesburg Power Partners, L.P. (Panda), with its principal offices at 4100 Spring Valley Road, Suite 1001, Dallas, Texas 75244, filed with the Federal Energy Regulatory Commission, an application for determination of exempt wholesale generator status pursuant to Section 32 of the Public Utility Holding Company Act of 1935, as amended, and Part 365 of the Commission's regulations.
Panda is a Delaware limited partnership, which will construct, own and operate a nominal 1,000 MW natural gas-fired generating facility within the region governed by the Florida Reliability Coordinating Council (FRCC) and sell electricity at wholesale.
Take notice that on January 28, 2000, Panda Midway Power Partners, L.P. (Panda), with its principal offices at 4100 Spring Valley Road, Suite 1001, Dallas, Texas 75244, filed with the Federal Energy Regulatory Commission, an application for determination of exempt wholesale generator status pursuant to Section 32 of the Public Utility Holding Company Act of 1935, as amended, and Part 365 of the Commission's regulations.
Panda is a Delaware limited partnership, which will construct, own and operate a nominal 1,000 MW natural gas-fired generating facility within the region governed by the Florida Reliability Coordinating Council and sell electricity at wholesale.
Take notice that on January 24, 2000, CNG Power Services Corporation filed their quarterly report for the quarter ending December 31, 1999, for information only.
Take notice that on January 20, 2000, Phibro Power LLC filed their quarterly report for the quarter ending December 31, 1999, for information only.
Take notice that on January 27, 2000, Potomac Electric Power Company (Pepco) tendered for filing a service agreement pursuant to Pepco FERC Electric Tariff, Original Volume No. 4, entered into between Pepco and Cinergy Capital & Trading, Inc.
An effective date of May 27, 1999 for this service agreement, with waiver of notice, is requested.
Take notice that on January 27, 2000, Potomac Electric Power Company (Pepco) tendered for filing a service agreement pursuant to Pepco FERC Electric Tariff, Original Volume No. 4, entered into between Pepco and Allegheny Power.
An effective date of May 27, 1999 is requested for this service agreement.
Take notice that on January 27, 2000, First Electric Cooperative Corporation (First Electric) tendered for filing its Initial Rate Filing for jurisdictional wheeling services that it provides within the State of Arkansas.
Take notice that on January 27, 2000, Louisiana Generating LLC (Seller), a limited liability company organized under the laws of the State of Delaware, petitioned the Commission for an order: (1) Accepting Seller's proposed Rate Schedule FERC No. 1 (Market-Based Rate Schedule); (2) granting waiver of certain requirements under Subparts B and C of Part 35 of the regulations, and (3) granting the blanket approvals normally accorded sellers permitted to sell at market-based rates. Seller also requests waiver of Order Nos. 888 and 889 as to certain interconnection facilities Seller intends to acquire. Seller, an indirect subsidiary of Northern States Power Company, is acquiring the non-nuclear generating assets and other miscellaneous assets of Cajun Electric Power Cooperative, Inc.
Take notice that on January 27, 2000, Kentucky Utilities Company (KU) tendered for filing addenda to existing contracts between KU and its wholesale requirements customers.
KU requests an effective date of January 1, 2000 for these contracts.
Take notice that on January 27, 2000, New Century Services, Inc. on behalf of Cheyenne Light, Fuel and Power Company, Public Service Company of Colorado, and Southwestern Public Service Company (collectively Companies) tendered for filing a Service Agreement under their Joint Open Access Transmission Service Tariff for Long Term Firm Point-to-Point Transmission Service between the Companies and Southwestern Public Service Company—Wholesale Merchant Function.
The Companies request that the Agreement be made effective on January 1, 2000.
Take notice that on January 24, 2000, the above-mentioned affiliated power producers and/or public utilities filed their quarterly reports for the quarter ending December 31, 1999.
Take notice that on January 27, 2000, the above-mentioned affiliated power producers and/or public utilities filed their quarterly reports for the quarter ending December 31, 1999.
Take notice that on January 27, 2000. the above-mentioned affiliated power producers and/or public utilities filed their quarterly reports for the quarter ending December 31, 1999.
Take notice that on January 27, 2000, the above-mentioned affiliated power producers and/or public utilities filed their quarterly reports for the quarter ending December 31, 1999.
E. Any person desiring to be heard or to protest such filing should file a motion to intervene or protest with the Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, D.C. 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). All such motions or protests should be filed on or before the comment date. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a motion to intervene. Copies of these filings are on file with the Commission and are available for public inspection. This filing may also be viewed on the Internet at http://www.ferc.fed.us/online/rims.htm (call 202-208-2222 for assistance).
The staff of the Federal Energy Regulatory Commission (FERC or Commission) will prepare an environmental assessment (EA) that will discuss the environmental impacts of the Trans-Union Interstate Pipeline Project involving construction and operation of facilities by Trans-Union Interstate Pipeline, L.P. (Trans-Union) in Claiborne and Union Parishes, Louisiana and Union County, Arkansas.
If you are a landowner on Trans-Union's proposed route and receive this notice, you may be contacted by a pipeline company representative about the acquisition of an easement to construct, operate, and maintain the proposed facilities. The pipeline company would seek to negotiate a mutually acceptable agreement. However, if the project is approved by the Commission, that approval conveys with it the right of eminent domain. Therefore, if easement negotiations fail to produce an agreement, the pipeline company could initiate condemnation proceedings in accordance with state law.
A fact sheet prepared by FERC entitled “An Interstate Natural Gas Facility on My Land? What Do I Need To Know?” was attached to the project notice Trans-Union provided to landowners. This fact sheet addresses a number of typically asked questions, including the use of eminent domain. It is available for viewing on the FERC Internet website (www.ferc.fed.us).
This Notice of Intent (NOI) is being sent to landowners along Trans-Union's proposed route; Federal, state, and local government agencies; elected officials; regional environmental, and public interest groups; Indian tribes that might attach religious and cultural significance to historic properties in the area of potential effects; local libraries and newspapers; and Commission's service list and parties to the proceeding. Government representatives are encouraged to notify their constituents of this proposed action and encourage them to comment on their areas of concern. Additionally, with this NOI we are asking Federal, state, local, and tribal agencies with jurisdiction and/or special expertise with respect to environmental issues to cooperate with us in the preparation of the EA. These agencies may choose to participate once they have evaluated Trans-Union's proposal relative to their agencies' responsibilities. Agencies who would like to request cooperating status should follow the instructions for filing comments described below.
Trans-Union proposes to construct 41.7 miles of 30-inch-diameter pipeline to transport natural gas from the Sharon Hub in Claiborne Parish, Louisiana to the proposed nonjurisdictional electric power generation facility being developed by Union Power Partners (UPP) in Union County Arkansas. The pipeline would supply 430,000 decatherms per day of natural gas to UPP.
The general location of Trans-Union's proposed facilities is shown on the map attached as appendix 1.
Construction Of the Trans-Union's proposed facilities would affect about 538 acres of land. Following construction, about 186 acres would be retained as permanent right-of-way. The remaining 352 acres of temporary work space would be restored and allowed to revert to its former use.
Trans-Union proposes to use a pipeline construction right-of-way of 95 feet, including 50 feet which would become permanent right-or-way and 45
The National Environmental Policy Act (NEPA) requires the Commission to take into account the environmental impacts that could result from an action whenever it considers the issuance of a Certificate of Public Convenience and Necessity. NEPA also requires us
Our independent analysis of the issues will be in the EA. Depending on the comments received during the scoping process, the EA may be published and mailed to Federal, state, and local agencies, elected officials, affected landowners, regional public interest groups, Indian tribes, local newspapers and libraries, and the Commission's official service list for this proceeding. A comment period will be allotted for review if the EA is published. We will consider all comments on the EA before we make our recommendations to the Commission.
The EA will discuss impacts that could occur as a result of construction and operation of the proposed project. We have already indentified a number of issues that we think deserve attention based on a preliminary review of the proposed facilities and the environmental information provided by Trans-Union. This preliminary list of issues may be changed based on your comments and our analysis.
You can make a difference by providing us with your specific comments or concerns about the project. By becoming a commentor, your concerns will be addressed in the EA and considered by the Commission. You should focus on the potential environmental effects of the proposal, alternatives to the proposal (including alternative locations or routes), and measures to avoid or lessen environmental impact. The more specific your comments, the more useful they will be. Please carefully follow these instructions to ensure that your comments are received in time and properly recorded:
• Send two copies of your letter to: David P. Boergers, Secretary, Federal Energy Regulatory Commission, 888 First St., N.E., Room 1A, Washington, DC 20426;
• Label one copy of the comments for the attention of the Environmental Review and Compliance Branch, PR-11.1;
• Reference Docket No. CP00-47-000; and
• Mail your comments so that they will be received in Washington, DC on or before March 6, 2000.
[If you do not want to send comments at this time but still want to remain on our mailing list, please return the Information Request (appendix 3). If you do not return the Information Request, you may be removed from the environmental mailing list.]
On March 9, 2000, the Office of Energy Projects staff will conduct a precertification site visit of the project route and possible reroutes. All parties may attend. Those planning to attend must provide their own transportation.
For further information on attending the site visit, please contact Paul McKee at (202) 208-1088.
In addition to involvement in the EA scoping process, you may want to become an official party to the proceeding known as an “intervenor.” Intervenors play a more formal role in the process. Among other things, intervenors have the right to receive copies of case-related Commission documents and filings by other intervenors. Likewise, each intervenor must provide 14 copies of its filings to the Secretary of the Commission and must send a copy of its filings to all other parties on the Commission's service list for this proceeding. If you want to become an intervenor you must file a motion to intervene according to Rule 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.214) (see appendix 2). Only intervenors have the right to seek rehearing of the Commission's decision.
Affected landowners and parties with environmental concerns may be granted intervenor status upon showing good cause by stating that they have a clear and direct interest in this proceeding which would not be adequately represented by any other parties. You do not need intervenor status to have your environmental comments considered.
Additional information about the proposed project is available from Mr. Paul McKee of the Commission's Office of External Affairs at (202) 208-1088 or on the FERC website (www.ferc.fed.us) using the “RIMS” link to information in this docket number. Click on the “RIMS” link, select “Docket # from the RIMS Menu, and follow the instructions. For assistance with access to RIMS, the RIMS helpline can be reached at (202) 208-2222.
Similarly, the “CIPS” link on the FERC Internet website provides access to the texts of formal documents issued by the Commission, such as orders, notices, and rulemakings. From the FERC Internet website, click on the “CIPS” link, select “Docket #” from the CIPS menu, and follow the instructions. For assistance with access to CIPS, the CIPS helpline can be reached at (202) 208-2474.
The Federal Communications Commission, as part of its continuing effort to reduce paperwork burden invites the general public and other Federal agencies to take this opportunity to comment on the following information collection(s), as required by the Paperwork Reduction Act of 1995, Public Law 104-13. An agency may not conduct or sponsor a collection of information unless it displays a currently valid control number. No person shall be subject to any penalty for failing to comply with a collection of information subject to the Paperwork Reduction Act (PRA) that does not display a valid control number. Comments are requested concerning (a) whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; (b) the accuracy of the Commission's burden estimate; (c) ways to enhance the quality, utility, and clarity of the information collected; and (d) ways to minimize the burden of the collection of information on the respondents, including the use of automated collection techniques or other forms of information technology.
Written comments should be submitted on or before March 13, 2000. If you anticipate that you will be submitting comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the contact listed below as soon as possible.
Direct all comments to Judy Boley, Federal Communications Commission, Room 1-C804, 445 12th Street, SW, DC 20554 or via the Internet to jboley@fcc.gov.
For additional information or copies of the information collection(s), contact Judy Boley at 202-418-0214 or via the Internet at jboley@fcc.gov.
The Federal Communications Commissions, as part of its continuing effort to reduce paperwork burden invites the general public and other Federal agencies to take this opportunity to comment on the following information collection, as required by the Paperwork Reduction Act of 1995, Public Law 104-13. An agency may not conduct or sponsor a collection of information unless it displays a currently valid control number. No person shall be subject to any penalty for failing to comply with a collection of information subject to the Paperwork Reduction Act (PRA) that does not display a valid control number. Comments are requested concerning (a) whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; (b) the accuracy of the Commission's burden estimate; (c) ways to enhance the quality, utility, and clarity of the information collected; and (d) ways to minimize the burden of the collection of information on the respondents, including the use of automated collection techniques or other forms of information technology.
Written comments should be submitted on or before March 13, 2000. If you anticipate that you will be submitting comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the contact listed below as soon as possible.
Direct all comments to Les Smith, Federal Communications Commission, Room 1-A804, 445 12th Street, SW, Washington, DC 20554 or via the Internet to lesmith@fcc.gov.
For additional information or copies of the information collections contact Les Smith at (202) 418-0217 or via the Internet at lesmith@fcc.gov.
The notificants listed below have applied under the Change in Bank Control Act (12 U.S.C. 1817(j)) and § 225.41 of the Board's Regulation Y (12 CFR 225.41) to acquire a bank or bank holding company. The factors that are considered in acting on the notices are set forth in paragraph 7 of the Act (12 U.S.C. 1817(j)(7)).
The notices are available for immediate inspection at the Federal Reserve Bank indicated. The notices also will be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing to the Reserve Bank indicated for that notice or to the offices of the Board of Governors. Comments must be received not later than February 24, 2000.
A. Federal Reserve Bank of Kansas City (D. Michael Manies, Assistant Vice President) 925 Grand Avenue, Kansas City, Missouri 64198-0001:
1. Hinton W. and Virginia S. Swearingen, Sedalia, Missouri; to acquire additional voting shares of 1889 Bancshares, Inc., Nevada, Missouri, and thereby indirectly acquire additional voting shares of First National Bank of Nevada, Nevada, Missouri.
The companies listed in this notice have applied to the Board for approval, pursuant to the Bank Holding Company Act of 1956 (12 U.S.C. 1841
The applications listed below, as well as other related filings required by the Board, are available for immediate inspection at the Federal Reserve Bank indicated. The application also will be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing on the standards enumerated in the BHC Act (12 U.S.C. 1842(c)). If the proposal also involves the acquisition of a nonbanking company, the review also includes whether the acquisition of the nonbanking company complies with the standards in section 4 of the BHC Act (12 U.S.C. 1843). Unless otherwise noted, nonbanking activities will be conducted throughout the United States. Additional information on all bank holding companies may be obtained from the National Information website at www.ffiec.gov/nic/.
Unless otherwise noted, comments regarding each of these applications must be received at the Reserve Bank indicated or the offices of the Board of Governors not later than March 6, 2000.
A. Federal Reserve Bank of Cleveland (Paul Kaboth, Banking Supervision) 1455 East Sixth Street, Cleveland, Ohio 44101-2566:
1. Park National Corporation, Newark, Ohio; to acquire 100 percent of the voting shares of SNB Corp., Greenville, Ohio, and thereby indirectly acquire Second National Bank, Greenville, Ohio.
2. Park National Corporation, Newark, Ohio; to acquire 100 percent of the voting shares of UB Bancshares, Inc., Greenville, Ohio, and thereby indirectly acquire United Bank, National Association, Greenville, Ohio.
The companies listed in this notice have given notice under section 4 of the Bank Holding Company Act (12 U.S.C. 1843) (BHC Act) and Regulation Y, (12 CFR Part 225) to engage
Each notice is available for inspection at the Federal Reserve Bank indicated. The notice also will be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing on the question whether the proposal complies with the standards of section 4 of the BHC Act. Additional information on all bank holding companies may be obtained from the National Information website at www.ffiec.gov/nic/.
Unless otherwise noted, comments regarding the applications must be received at the Reserve Bank indicated or the offices of the Board of Governors not later than February 24, 2000.
A. Federal Reserve Bank of Atlanta (Lois Berthaume, Vice President) 104 Marietta Street, N.W., Atlanta, Georgia 30303-2713:
1. Summit Bank Corporation, Atlanta, Georgia; to engage
Federal Trade Commission.
Notice of meeting on February 25, 2000.
Pursuant to section 10(a)(2) of the Federal Advisory Committee Act, 5 U.S.C. App. § 10(a)(2), and 16 CFR 16.9(a), notice is hereby given that the Federal Trade Commission Advisory Committee on Online Access and Security will hold a meeting on Friday, February 25, 2000, from 9 a.m. to 5 p.m. in Room 432, Federal Trade Commission, 600 Pennsylvania Avenue, NW., Washington, DC 20580. The meeting is open to the public and will include a period for public comment. The purpose of the Advisory Committee is to provide advice and recommendations to the Commission regarding implementation of certain fair information practices by domestic commercial Web sites—specifically, providing online consumers reasonable access to personal information collected from and about them, and maintaining adequate security for that information. Interested parties may submit comments concerning any matter to be considered at the meeting by following the procedures described below.
The Advisory Committee will meet on Friday, February 25, 2000, from 9 a.m. to 5 p.m.
The meeting will take place in Room 432, Federal Trade Commission, 600 Pennsylvania Avenue, NW., Washington, DC 20580.
Laura Mazzarella, Division of Financial Practices, Federal Trade Commission, 600 Pennsylvania Avenue, NW., Mail Stop 4429, Washington, DC 20580, telephone (202) 326-3424, email lmazzarella@ftc.gov; or Hannah Stires, Division of Financial Practices, Federal Trade Commission, 600 Pennsylvania Avenue, NW., Mail Stop 4429, Washington, DC 20580, telephone (202) 326-3178, email hstires@ftc.gov.
15 U.S.C. 41
The second meeting of the Federal Trade Commission Advisory Committee on Online Access and Security will be held on Friday, February 25, 2000, in Room 432, Federal Trade Commission, 600 Pennsylvania Avenue, NW., Washington, DC from 9 a.m. to 5 p.m.
The Advisory Committee will consider the costs and benefits, to both consumers and businesses, of implementing the fair information practices of access and security with respect to personal information collected for and about consumers online. The Advisory Committee will further consider the parameters of reasonable access to personal information and adequate security and will present options for implementation of these information practices in a report to the Commission.
The tentative agenda for the second meeting is as follows:
1. Administrative matters.
2. Discussion of preliminary draft outlines submitted by subgroups on issues relating to “reasonable access”.
3. Discussion of preliminary draft outlines submitted by subgroups on issues relating to “adequate security”.
4. Public Comment.
5. Discussion of tasks and assignments.
The meeting is open to the public.
Interested parties who wish to submit comments on the meeting agenda or questions for consideration by the Advisory Committee should send an original and two copies in advance of the meeting to the Secretary, Federal Trade Commission, Room H-159, 600 Pennsylvania Avenue, NW., Washington, DC 20580. All comments and questions should be captioned “Advisory Committee on Online Access and Security—Comment, P004807.” To enable prompt review and public access, paper submissions should be accompanied by a version on diskette in ASCII, WordPerfect (please specify version) or Microsoft Word (please specify version) format. Diskettes should be labeled with the name of the submitter, the Advisory Committee caption, and the name and version of the word processing program used to create the document.
Alternatively, comments or questions may be submitted to the following email address: advisorycommittee@ftc.gov; if submitted by email, only one copy of the comment or question is required. The email should contain the name of the submitter, the Advisory Committee caption, and, if a document is attached, the name and version of the word processing program used to create the document.
To ensure that comments are processed properly, individuals submitting comments should be sure to use the above addresses. All comments will be posted on the Advisory Committee's Web page at www.ftc.gov/acoas as soon as reasonably possible, and likely within 5 business days of receipt.
By direction of the Commission.
In compliance with the requirement of Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995 for opportunity for public comment on proposed data collection projects, the Centers for Disease Control and Prevention (CDC) will publish periodic summaries of proposed projects. To request more information on the proposed projects or to obtain a copy of the data collection plans and instruments, call the CDC Reports Clearance Officer on (404) 639-7090.
Comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques for other forms of information technology. Send comments to Seleda Perryman, CDC Assistant Reports Clearance Officer, 1600 Clifton Road, MS-D24, Atlanta, GA 30333. Written comments should be received within 60 days of this notice.
Allergy to natural rubber latex (NRL) has become a significant health risk among healthcare workers and other persons using latex gloves in the course of their work [NIOSH 1997; Turjanmaa
In 1997, NIOSH published an ALERT concerning the risk of latex allergy in the workplace [NIOSH 1997]. This Alert provided specific recommendations to workers for the prevention of latex allergy and was distributed to workplaces most likely to contain latex exposure (
To accomplish this task, we propose to conduct a systematic, communication theory-based set of studies with a brochure adapted from the NIOSH Alert on latex allergy as the primary attitude concept. These experiments will be targeted at five non-healthcare worker occupational groups (hair dressers, daycare workers, police officers, food handlers, and housekeeping personnel). The framing postulate of the Prospect Theory and the Elaboration Likelihood Model will serve as the basis of the study [Tversky and Kahneman 1981; Petty and Cacioppo 1986] in which the combined effect of message framing and message expectancy on elaboration likelihood will be assessed. Specifically, participants will be randomly assigned to the conditions of a 2 (message framing: positive vs. negative) ′ 2 (message expectancy: positive vs. negative) ′ 2 (argument quality: strong vs. stronger) factorial design and given a pretest, brochure with the appropriate test variables, and post test. In addition, the participants will be surveyed for a history of latex glove usage, allergy, latex allergy, or dermatitis in either themselves or their family members to determine if a history of allergy or glove usage predisposes them to be highly involved with the subject of latex allergy. Finally, the effect of the intervention on receiver attitude toward latex allergy and corresponding use of NIOSH recommendations one month following the intervention will be determined. The study will include several phases. First, effective communication variables will be identified in the pretesting phase and incorporated into test brochures. In addition, pre-test and post-test surveys will be pretested. A total of 160 participants will be recruited for the pretesting phase. In the second phase, the pilot test, the effect of message framing and message expectancy on elaboration likelihood will be assessed in a small scale, laboratory study. This pilot test will be conducted with a sample of university students (N = 300) who occasionally to intermittently wear latex gloves. Conducting the first study in the laboratory setting allows for consistent control over external variables during message pretesting, implementation, and testing. The knowledge obtained from this study will be used to improve the versions of the brochure to be used in the last phase, one study for each of the five occupational groups (a total of five studies). The goal of each study will be to determine the effect of message framing and message expectancy manipulations in increasing the receiver's elaboration about latex allergy prevention among five different occupational groups (N = 300 per group or 1,500 total participants). In addition, change in attitude and behavior will be assessed one month after exposure to the brochure. These combined studies will test the use of message framing and contrasts in message expectancy in applied health communication research. Specifically, the studies will assess the effectiveness of these communication variables in influencing attitude, intentions, and behavior concerning the prevention of latex allergy. The results and conclusions drawn from this project will be used to develop a health communication template based on message framing and increased systematic message processing.
Overall, this study will contribute significantly to the knowledge concerning application of the message framing theory, provide NIOSH with specific recommendations for effective health communication, and provide a template for future health interventions. In addition, this study will identify effective methods of communicating health and safety messages to those populations not normally reached by NIOSH.
Based on an average hourly wage of $10.00 among all occupational groups combined, the total cost to respondents is $17,450.
In compliance with the requirement of Section 3506 (c) (2) (A) of the Paperwork Reduction Act of 1995, the Centers for Disease Control and Prevention is providing opportunity for public comment on proposed data collection projects. To request more information on the proposed projects or to obtain a copy of the data collection plans and instruments, call the CDC Reports Clearance Officer on (404) 639-7090.
Comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques for other forms of information technology. Send comments to Seleda Perryman, CDC Assistant Reports Clearance Officer, 1600 Clifton Road, MS-D24, Atlanta, GA 30333. Written comments should be received within 60 days of this notice.
One of the most widespread, but often overlooked, occupational hazards is noise. As a result, hearing loss is the most common occupational disease in the United States today. More than 30 million workers are exposed to hazardous noise levels.
The risk of hearing loss is particularly high in certain occupations. Research shows that more than 90 percent of coal miners will experience moderate to significant hearing loss by the time they reach retirement. This level of hearing loss has a number of negative implications for both the affected individual and others: (1) Impaired communication with family members, friends, and coworkers can result in social isolation; (2) unrelenting tinnitus (ringing in the ears) can significantly lower one's quality of life; (3) a diminished ability to monitor the work environment (including warning signals, etc.) increases the risk of accidents and further injury at the workplace; and, finally, (4) there are economic costs that result from workers' compensation and lower productivity.
New noise standards for the mining environment have recently been issued by the Department of Labor and will go into effect in September 2000. The new rules require that mine operators take necessary action to protect miners' hearing when noise levels reach 85 dBA or more over an eight-hour period with additional actions required at 90 dBA. While the new standard establishes mandatory behaviors, such as the wearing of both ear plug and earmuff-type hearing protectors at noise levels of 105 dBA or more over an eight-hour period, there are also voluntary behaviors associated with the new rules. The wearing of hearing protectors at levels below 90 dBA and getting hearing tests as part of a hearing conservation program are both voluntary on the part of the individual miner.
This study is designed to ascertain factors that can be used to encourage adoption of voluntary behaviors among coal miners. The choice of this subset of miners is based upon research that indicates they experience significantly more hearing loss than metal and nonmetal miners. NIOSH proposes working with the United Mine Workers of America and experts in health communication to test the effectiveness of several innovative approaches to communicating hearing loss risk and promoting self-protective behaviors. Different messages will be sent to four different groups of coal miners, and there will be one control group that receives no message. The researchers will follow up with these groups at two different points in time to assess the relative effectiveness of the messages.
The central purpose of this study is to promote hearing conservation among coal miners and encourage the adoption of the voluntary components of the new noise standard. However, NIOSH believes that the results of this study will help in similar efforts with other worker populations. There is no cost to respondents.
In compliance with the requirement of Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995 for opportunity for public comment on proposed data collection projects, the Centers for Disease Control and Prevention (CDC) will publish periodic summaries of proposed projects. To request more information on the proposed projects or to obtain a copy of the data collection plans and instruments, call the CDC Reports Clearance Officer on (404) 639-7090.
Comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques for other forms of information technology. Send comments to Seleda Perryman, CDC Assistant Reports Clearance Officer, 1600 Clifton Road, MS-D24, Atlanta, GA 30333. Written comments should be received within 60 days of this notice.
Workplace violence is a significant cause of injury and death in the workplace. It was the second leading cause of death in 1997, accounting for approximately 18% of worker fatalities during that year (BLS, 1998). Approximately 85% of occupational homicides involved robberies, and approximately four-fifths of the homicides were the result of shootings. An increased risk of workplace homicide was clustered within certain occupational areas including sales occupations, protective service occupations, and taxicab drivers. Furthermore, 60% of occupational fatalities within taxicab drivers were due to homicide (BLS, 1998). Although these statistics are significant, a limited amount of information is known concerning the level of worker awareness about the risk of workplace violence. In addition, little is known about the level of worker self-efficacy in regard to recommended preventive measures or the current status of the prevention strategies utilized by both the worker and employer. Therefore, the goal of this study is to identify those communication variables that are most effective in increasing the following in regard to workplace violence prevention: worker awareness, comprehension, and use of recommendations in the workplace.
To achieve this goal, this project will assess the combined effect of message framing (gain or loss) and highly involving messages on the elaboration likelihood of the receiver, and the subsequent attention, intention, and behavior change that result (Maheswaran & Levy, 1990; Smith & Petty, 1996). A study will be conducted in which message framing (gain, loss), issue involvement (high, low), and argument quality (strong, stronger) are varied. First, three phases of Message Pretesting will be done (N = 175) to determine the appropriate version of these communication variables to be used in the studies: (1) Selecting appropriate written versions of communication variables; (2) test several formats of the brochure to determine the most effective graphics, design, and presentation; and (3) pretest the combination of the print and visual variables for clarity and manipulation accuracy. Second, a Pilot Study will be conducted with a sample of taxicab drivers (N > > 300). The Pilot Study will be a small scale study in which participants are randomly assigned to the conditions of a 2 (message framing: gain, loss) ′ 2 (issue involvement: high, low) ′ 2 (argument quality: strong, stronger) factorial design. The effect of each variable on elaboration, attitude, and intentions will be determined through pre- and post-surveys. The knowledge obtained in this Pilot Test will be used to improve the version of the brochure to be used in the main Study. The Study will be conducted with taxicab drivers (N > > 1,500 total) in a major US city. The goal of the Study will be to determine the effect of message framing, issue involvement, and argument quality on the participant's level of elaboration, attitude, and intentions. In addition, a follow-up survey at 1, 3, and 6 months will assess any corresponding behavior change over time.
These combined studies will assess the use of message framing and issue involvement in applied health communication research. Specifically, the studies will assess the effectiveness
The Centers for Disease Control and Prevention (CDC) publishes a list of information collection requests under review by the Office of Management and Budget (OMB) in compliance with the Paperwork Reduction Act (44 U.S.C. Chapter 35). To request a copy of these requests, call the CDC Reports Clearance Officer at (404) 639-7090. Send written comments to CDC, Desk Officer; Human Resources and Housing Branch, New Executive Office Building, Room 10235; Washington, DC 20503. Written comments should be received within 30 days of this notice.
1.
Respondents for the Monthly Vital Statistics Report Form are registration officials in each State and Territiory, the District of Columbia, and New York City; in addition, 60 local (county) officials in New Mexico who record marriages occurring and divorces and annulments granted in each county of New Mexico will use this Form. There are no direct costs to respondents; the data are routinely available in each reporting office as a by-product of ongoing activities. Earlier OMB approvals of this data collection involved four separate forms, all of which are combined into a single multi-purpose form for this current approval request. The total annual burden hours are 418.
The Centers for Disease Control and Prevention (CDC) publishes a list of information collection requests under review by the Office of Management and Budget (OMB) in compliance with the Paperwork Reduction Act (44 U.S.C. Chapter 35). To request a copy of these requests, call the CDC Reports Clearance Officer at (404) 639-7090. Send written comments to CDC, Desk Officer; Human Resources and Housing Branch, New Executive Office Building, Room 10235; Washington, DC 20503. Written comments should be received within 30 days of this notice.
1. National Coal Workers' Autopsy Study Consent Release and History Form—(0920-0021)—Extension—National Institute for Occupational Safety and Health (NIOSH)—Under the Federal Coal Mine Health & Safety Act of 1977, PL91-173 (amended the
It is estimated that only 5 minutes is required for the pathologist to put a statement on the invoice affirming that no other compensation is received for the autopsy. From past experience, it is estimated that 15 minutes is required for the next-of-kin to complete form CDC/NIOSH 2.6. In as much as an autopsy report is routinely completed by a pathologist, the only additional burden is the specific request of abstract of terminal illness and final diagnosis relating to pneumoconiosis. Therefore, only 5 minutes of additional burden is estimated for the autopsy report. The total annual burden hours are 62.5.
The Centers for Disease Control and Prevention (CDC) announces the availability of fiscal year (FY) 2000 funds for a cooperative agreement program for new State and competing continuation State and local programs to develop and improve Childhood Lead Poisoning Prevention activities which include building Statewide capacity to conduct surveillance of blood lead levels in children. This program addresses the “Healthy People 2000” priority area of Environmental Health.
The purpose of this program is to provide the impetus for the development, implementation, expansion, and evaluation of State and local childhood lead poisoning prevention program activities which include Statewide surveillance capacity to determine areas at high risk for lead exposure. Also, this cooperative agreement is to carry out the core public health functions of Assessment, Policy Development, and Assurance in childhood lead poisoning prevention programs.
Funding for this program will be to:
1. Develop and/or enhance a surveillance system that monitors all blood lead levels.
2. Assure screening of children who are potentially exposed to lead and follow-up care for children who are identified with elevated blood lead levels (BLLs).
3. Assure awareness and action among the general public and affected professionals in relation to preventing childhood lead poisoning.
4. Expand primary prevention of childhood lead poisoning in high-risk areas in collaboration with other government and community-based organizations.
As programs shift emphasis from providing direct screening and follow-up services to the core public health functions, cooperative agreement funds may be used to support and emphasize health department responsibilities to screen high risk children and provide appropriate follow-up services. This includes improving coalitions and partnerships; conducting better and more sophisticated assessments; developing and evaluating policies, program performance, and effectiveness based on established goals and objectives.
Applicant eligibility is divided into Part A (New Applicants), Part B (Competing Continuation), and Part C (Supplemental Funding for Alternative Surveillance Assessment/Screening Recommendation Evaluation) defined in the following section. In the future, CDC plans to shift its program emphasis toward State funding for childhood lead poisoning prevention activities. However, the top five metropolitan statistical areas (SMSAs)/largest cities will be eligible for direct funding for childhood lead poisoning prevention activities indefinitely. They are New York City, Los Angeles, Chicago, Philadelphia, and Houston.
Applicants encouraged to apply under Part A are: Alaska; Arkansas; Georgia; Hawaii; Idaho; Kansas; Kentucky; Mississippi; Nevada; North Dakota; Oklahoma; South Dakota; Tennessee; Texas and Wyoming.
Additional information for all State applicants. If a State agency applying for grant funds is other than the official State health department, written concurrence by the State health department must be provided (for example, the State environmental health agency).
Up to $2,500,000 will be available in FY 2000 to fund up to 8 new applicants. CDC anticipates that awards for the first budget year will range from $75,000 to $800,000.
Up to $8,000,000 will be available in FY 2000 to fund up to 17 competing continuation applicants. CDC anticipates that awards for the first budget year will range from $75,000 to $1,500,000.
Up to $400,000 will be awarded in FY 2000 to fund up to 4 assessment/evaluation studies with a three-year project period. These funds will be awarded to support the development of alternative surveillance assessments and/or to conduct evaluation of the impact of lead screening recommendations. Awards are expected to range from $70,000 to $100,000, with the average award being approximately $85,000. Funds will be awarded for assessment/evaluation studies that address one of the following:
1. Alternative Surveillance Assessment—Assessment of lead exposure in a jurisdictional population or sub-population using an approach to surveillance that differs from the Statewide CBLS system described in this announcement.
2. Screening Recommendation Evaluation—Evaluation of the impact of lead screening recommendations on screening for high-risk children.
Funding for State applicants: To determine the type of program activities and the associated level of funding for an individual State applicant for Part A or Part B, please refer to the table below. These are suggested funding guidelines and should not be regarded as absolute funding limits. Addendum 2 in the application package provides an explanation of the factors used to develop categorical funding recommendations. Addendum 3 provides an explanation of the program activities required for each funding category.
*Projected level of effort adjusted to account for currently funded locales.
Funding State Applicants—Part A or Part B: Determine your funding category (Category 1, 2, or 3) according to the table below. The range and average of awards for each funding category follows:
Awards for Local Applicants (under Part B only): The suggested range of awards for local applicants is $250,000 to $450,000.
Additional Information on Funding for all Applicants for Part A, Part B, and Part C New awards are expected to begin on or about July 1, 2000, and are made for 12-month budget periods within project periods not to exceed 2-years for local programs or 3-years for State programs. Estimates outlined above are subject to change based on the actual availability of funds and the scope and quality of applications received. Continuation awards within the project period will be made on the basis of satisfactory progress and availability of funds. Awards cannot supplant existing funding for CLPP or Supplemental Funding Initiatives. Funds should be used to enhance the level of expenditures from State, local, and other funding sources.
Funds may not be expended for medical care and treatment or for environmental remediation of sources of lead exposure. However, the applicant must provide a plan to ensure that these program activities are carried out.
Not more than 10 percent (exclusive of Direct Assistance) of any cooperative agreement or contract through the cooperative agreement may be obligated for administrative costs. This 10 percent limitation is in lieu of, and replaces, the indirect cost rate.
Special Requirement regarding Medicaid provider status of applicants: Pursuant to section 317A of the Public Health Service Act (42 U.S.C. 247b-1), as amended by Sec. 303 of the “Preventive Health Amendments of 1992” (Public Law 102-531), applicants AND current grantees must meet the
Applicants who directly provide these services must be enrolled with their State Medicaid agency as Medicaid providers.
Providers who enter into agreements with the applicant to provide such services must be enrolled with their State Medicaid agency as providers. An exception to this requirement will be made for providers whose services are provided free of charge and who accept no reimbursement from any third-party payer. Such providers who accept voluntary donations may still be exempted from this requirement.
In order to satisfy this program requirement, please provide a copy of a Medicaid provider certificate or Statement as proof that you meet this requirement. Failure to include this information would result in your application being returned. Please place this information immediately behind the budget and budget justification pages.
To achieve the purpose of this cooperative agreement program, the recipient will be responsible for the activities listed under 1. Recipient Activities and CDC will be responsible for the activities listed under 2. CDC Activities.
a. Establish, maintain, or enhance a Statewide surveillance system in accordance with CDC guidance. For local applicants (under Part B), enhance a data management system that links with the State's surveillance system or develop an automated data management system to collect and maintain laboratory data on the results of blood lead analyses and data on follow-up care for children with elevated BLLs. State recipients should ensure receipt of data from local programs. Local recipients should transfer relevant data to the appropriate State entity in a timely manner for annual submission to CDC.
b. Manage, analyze and interpret individual State surveillance data, and present and disseminate trends and other important public health findings.
c. Develop, implement and evaluate a Statewide/jurisdiction-wide childhood blood lead screening plan consistent with CDC guidance provided in “Screening Young Children for Lead Poisoning: Guidance for State and Local Public Health Officials”. For local applicants, participate in the Statewide planning process. Make screening recommendations and appropriate local screening strategies available and known to health care providers.
d. Assure appropriate follow-up care is provided for children identified with elevated blood lead levels.
e. Establish effective, well-defined working relationships within public health agencies and with other agencies and organizations at national, State, and community levels (
f. For State Programs, provide managerial, technical, analytical, and program evaluation assistance to local agencies and organizations in developing or strengthening their CLPP programs activities.
a. Provide technical, and scientific assistance and consultation on program development, implementation and operational issues.
b. Provide technical assistance and scientific consultation regarding the development and implementation of all surveillance activities including data collection methods and analysis of data.
c. Assist with data analysis and interpretation of individual State surveillance data and release of national reports. Reports will include analysis of national aggregate data as well as State-specific data.
d. Assist cooperative agreement recipients with communication and coordination among Federal agencies, and other public and private agencies and organizations.
e. Conduct ongoing assessment of program activities to ensure the use of effective and efficient implementation strategies.
To achieve the purpose of this program, the recipient will be responsible for the activities listed under 1. Recipient Activities and CDC will be responsible for the activities listed under 2. CDC Activities.
a. Develop and implement a study protocol to include the following: methodology, sample selection, field operation, and statistical analysis. Applicants must provide a means of assuring that the results of the study will be published.
b. Revise, refine, and carry out the proposed methodology for conducting Supplemental Funding Studies.
c. Monitor and evaluate all aspects of the assessment activities.
d. Conduct and evaluate public health programs and/or have access to professionals who are knowledgeable in conducting such activities.
a. Provide technical and scientific consultation on activities related to overall program requirements of supplemental funding activities.
b. Provide technical assistance to program manager and/or principal investigator regarding revision, refinement, and implementation of study design and proposed methodology for conducting supplemental funding activities.
c. Assist program manager and/or principal investigator with data interpretation and analysis issues.
Use the information in the Program Requirements, Other Requirements, and Evaluation Criteria sections to develop the application content. Your application will be evaluated on the criteria listed, so it is important to follow them in laying out your program plan:
Applications must be developed in accordance with PHS Form 5161-1.
Part B applicants also competing for Part C funds must submit separate applications.
Application pages must be clearly numbered, and a complete index to the application and its appendices must be included. The original and two copies of the application set must be submitted UNSTAPLED and UNBOUND. All material must be typewritten, double spaced, printed on one side only, with unreduced font (10 or 12 point font only) on 8
A one-page, single-spaced, typed abstract must be submitted with the application. The heading should include the title of the program, project title, organization, name and address, project director, telephone number, facsimile number, and e-mail address.
The main body of the CLPP program application (Parts A or B) must include the following: budget/budget justification; Medicaid certification; progress report (Part B applicants only); understanding the problem; surveillance/data-management activities; Statewide/jurisdiction-wide planning and collaboration; core public health functions; goals and objectives; program management and staffing; and program evaluation.
The main body of the supplemental funding project application (Part C) must include the following: study protocol, project personnel, and project management.
Each application should not exceed 75 pages. The abstract, budget narrative, and budget justification pages are not included in the 75 page limit. Supplemental information should be placed in appendices and is not to exceed 25 pages.
Part B applicants must submit a progress report no longer than 10 pages in their competing continuation application. This report should be placed immediately after the budget and budget justification.
Provide qualified staff, other resources, and knowledge to implement the provisions of the program. Applicants requesting cooperative agreement supported positions must provide assurances that such positions will be authorized to be filled by the applicant's personnel system.
Submit the original and two copies of the PHS 5161-1 (OMB Number 0937-0189) on or before April 12, 1999. Forms are in the application kit.
Submit the application to: Mattie B. Jackson, Grants Management Specialist, Grants Management Branch, Procurement and Grants Office, Program Announcement 00033, Centers for Disease Control and Prevention (CDC), 2920 Brandywine Road, Room 3000, Atlanta, GA 30341-4146.
Applications shall be considered as meeting the deadline if they are either: (1) Received on or before the deadline date, or (2) sent on or before the deadline date and received in time for submission for the review process. Applicants must request a legibly dated receipt from a commercial carrier or U.S. Postal Service. Private metered postmarks shall not be acceptable as proof of timely mailing.
Applications which do not meet the criteria above are considered late applications. Late applications will not be considered in the current competition and will be returned to the applicant.
The review of applications will be conducted by an objective review panel as they relate to the applicant's response to either Part A, Part B, or Part C. The applications will be evaluated according to the following criteria:
The extent to which the applicant's description and understanding of the burden and distribution of childhood lead exposure or elevated BLLs in their jurisdiction, using evidence (as available) of incidence and/or prevalence and demographic indicators, including a description of the Medicaid population.
The applicant's ability to develop a childhood blood lead surveillance system that includes; (a) a flow chart that describes data transfer, (b) a mechanism for tracking lead screening services to children, especially Medicaid children, and (c) a mechanism for reporting data annually to the CDC's national surveillance database. The clarity, feasibility, and scientific soundness of the surveillance approach. Also, the extent to which the proposed time table for accomplishing each activity and methods for evaluating each activity are appropriate and clearly defined. The following elements will be specifically evaluated:
a. How laboratories report Blood Lead Levels (BLLs), including ability to identify and assure reporting from private laboratories which perform lead testing.
b. How data will be collected and managed.
c. How quality of data and completeness of reporting will be assured.
d. How and when data will be analyzed.
e. How summary data will be reported and disseminated on a regular basis (
f. Protocols for follow-up of individuals with elevated BLLs.
g. Provisions to obtain denominator data (results of all laboratory blood lead tests, regardless of level).
h. Time line and methods for evaluating the Childhood Blood Lead Surveillance (CBLS) approach.
i. Plans to convert paper-based components of the system to electronic data manipulation.
j. Use of data including evaluation of prevention activities, especially to target screening and prevention efforts.
The applicant's ability to develop Statewide screening recommendations with appropriate local strategies. The following elements will be specifically evaluated:
a. The proposed approach to developing and carrying out an inclusive Statewide screening plan as outlined in “Screening Young Children for Lead Poisoning: Guidance for State and Local Health Officials”.
b. The extent to which the applicant plans to utilize surveillance and program data to produce a Statewide screening recommendation, with specific attention given to the Medicaid population.
c. The ability of the applicant to involve collaborators in the development of a screening plan and implementation of strategies to strengthen childhood lead poisoning prevention activities.
d. The applicant's demonstrated ability to collaborate with principal partners, including managed-care organizations, State Medicaid agency, child health-care providers and provider groups, insurers, community-based organizations, housing agencies, and banking, real estate, and property-owner interests, must be demonstrated by letters of support, memoranda of understanding, contracts, or other documented evidence of relationships.
The applicant's ability to describe the approach and activities necessary to achieve a balance among health department roles in CLPP, including assessment, program and policy development, and monitoring, evaluating, and ensuring the provision of all necessary components of a comprehensive CLPP activities within their respective categories.
The extent to which the applicant's goals and objectives relate to the CLPP activities in their respective categories. Objectives must be relevant, specific, measurable, achievable, and time-framed. There must be a formal work plan with a description of methods, a timetable and program staff responsible for accomplishment of each objective, and the evaluation of each proposed objective.
The extent to which the applicant has documented the skills and ability to develop and carry out a comprehensive
a. Describe the proposed health department staff roles in CLPP, their specific responsibilities, and their level of effort and time. Include a plan to expedite filling of all positions and assure that requested positions have been or will be approved by applicant's personnel system.
b. Describe the plan to provide training and technical assistance to health department personnel and consultation to collaborators outside the health department, including proposed design of information-sharing systems.
The extent to which the applicant proposes to measure the overall impact of health department CLPP activities. Specific criteria should include:
a. The plan for evaluating the impact or outcome of CLPP activities, including evaluation design, methods, and activities.
b. Description of how the project will assess changes in public policy and measure the effectiveness of collaborative activities.
c. Progress made in childhood lead poisoning prevention which resulted from planned health department strategies.
The extent to which the budget is reasonable, clearly justified, and consistent with the intended use of funds.
The extent to which the applicant's description and understanding of the burden and distribution of childhood lead exposure or elevated BLLs in their jurisdiction, using evidence (as available) of incidence and/or prevalence and demographic indicators, including a description of the Medicaid population.
For State Applicants: The applicant's ability to expand its childhood blood lead surveillance system that includes tracking lead screening for Medicaid children, evaluating the existing system, and reporting data to the CDC's national surveillance database. The clarity, feasibility, and scientific soundness of the surveillance approach. Also, the extent to which the proposed time table for accomplishing each activity are appropriate and clearly defined. The following elements will be specifically evaluated:
a. How laboratories report BLLs, including ability to identify and assure reporting from private laboratories which perform lead testing.
b. How data are collected and managed.
c. How quality of data and completeness of reporting are assured.
d. How and when data are analyzed.
e. How summary data are reported and disseminated on a regular basis (
f. Protocols for follow-up of individuals with elevated BLLs.
g. Provisions to obtain denominator data (results of all laboratory blood lead tests, regardless of level).
h. Time line and methods for evaluating the Childhood Blood Lead Surveillance (CBLS) approach.
i. Process used to convert paper-based components of the system to electronic data.
j. Use of data including evaluation of prevention activities, especially to target screening and prevention efforts.
For local applicants (Part B only): The applicant's ability to expand their data management system, including the approach to participating in the State CBLS, if applicable. The clarity, feasibility, and scientific soundness of the approach to data management. Also, the extent to which the proposed schedule for accomplishing each activity and method for evaluating each activity are clearly defined and appropriate. The following elements will be specifically evaluated:
a. How laboratories report Blood Lead Levels (BLL), including ability to identify and assure reporting from private laboratories which perform lead testing.
b. How data are collected and managed.
c. How quality of data and completeness of reporting are assured.
d. How and when data are analyzed.
e. How summary data are reported and disseminated on a regular basis (
f. Protocols for follow-up of individuals with elevated BLLs.
g. Provisions to obtain denominator data (results of all laboratory blood lead tests, regardless of level).
h. Time line and methods for evaluating the Childhood Blood Lead Surveillance (CBLS) approach.
i. Process used to convert paper-based components of the system to electronic data.
j. Use of data including evaluation of prevention activities, especially to target screening and prevention efforts.
The applicant's ability to develop Statewide/jurisdiction-wide screening recommendations with appropriate local strategies. The following elements will be specifically evaluated:
a. The approach to developing and carrying out an inclusive State-or jurisdiction-wide screening plan as outlined in “Screening Young Children for Lead Poisoning: Guidance for State and Local Health Officials”.
b. The extent to which the applicant utilized surveillance and program data to produce Statewide/jurisdiction-wide screening recommendations and target the Medicaid population.
c. Description of how collaborations facilitated the development of a screening plan and strengthened childhood lead poisoning prevention strategies.
d. Evidence of collaboration with principal partners, including managed-care organizations, State Medicaid agency, child health-care providers and provider groups, insurers, community-based organizations, housing agencies, and banking, real-estate, and property-owner interests. These collaborations must be demonstrated by letters of support, memoranda of understanding, contracts, or other documented evidence of relationships.
For applicants under Part B, describe progress in developing and implementing the screening plan based upon each of the elements listed above.
The ability to describe the approach and activities taken to achieve a balance among health-department roles in CLPP, including assessment, program and policy development, and monitoring, evaluating, and ensuring the provision of all CLPP activities within their respective categories (for example, Category 3 requires screening plans, surveillance systems, assure follow-up care, and evaluation).
The extent to which the applicant's goals and objectives relate to the CLPP activities in their respective categories under which they applied. Objectives must be relevant, specific, measurable, achievable, and time-framed. There must be a formal work plan with a description of methods and a timetable and program staff responsible for accomplishment of each objective.
The extent to which the applicant has the skills and ability to develop and carry out a comprehensive CLLP program. Specifically the applicant should:
a. Describe the proposed health department staff roles in CLPP, their specific responsibilities, and their level of effort and time. Include a plan to expedite filling of all positions and assure that requested positions have been or will be approved by the applicant's personnel system.
b. Describe the plan to provide training and technical assistance to health department personnel and consultation to collaborators outside the health department, including proposed design of information-sharing systems.
The extent to which the applicant measures the overall impact of health department CLPP activities. Specific criteria should include:
a. Description of the progress made to evaluate the impact and outcome of collective CLPP activities, including the evaluation design, methods, and tasks.
b. Description of the changes in the effectiveness of collaborative activities.
c. Progress made in childhood lead poisoning prevention which resulted from planned health department strategies.
The extent to which the budget is reasonable, clearly justified, and consistent with the intended use of funds.
The applicant's ability to develop a scientifically sound protocol (including adequate sample size with power calculations), quality, feasibility, consistency with project goals, and soundness of the evaluation plan (which should provide sufficient detail regarding the way the protocol will be implemented). The degree to which the applicant has met the CDC policy requirements regarding the inclusion of women, ethnic, and racial groups in the proposed project. This includes: (a) the proposed plan to include of both sexes and racial and ethnic minority populations for appropriate representation; (b) the proposed justification when representation is limited or absent; (c) a Statement as to whether the design of the study is adequate to measure differences when warranted; and (d) a Statement as to whether the plans for recruitment and outreach for study participants includes establishing partnerships with community-based agencies and organizations. Benefits of the partnerships should be described.
The extent to which personnel involved in this project are qualified, including experience in conducting relevant studies. In addition, the applicant's ability to commit appropriate staff time needed to carry out the study.
The applicant's ability to implement and monitor the proposed study to include specific, attainable, and realistic goals and objectives, and evaluation plan.
The extent to which the budget is reasonable, clearly justified, and consistent with the intended use of cooperative agreement funds.
The extent to which the applicant complies with the Department of Health and Human Services regulations (45 CFR Part 46) on the protection of human subjects.
Provide CDC with the original plus two copies of:
1. Quarterly progress reports, which are required of all grantees. The quarterly report narrative should not exceed 25 pages. Time lines for the quarterly reports will be established at the time of award, but are typically due 30 days after the end of each quarter.
2. Calendar year surveillance data and a written surveillance summary report must be submitted annually to CDC in the approved OMB format to be disseminated to State and local public health officials and congressional personnel. Data must be submitted to CDC by March 31st in the required format for analysis.
3. Financial Status Reports, are due within 90 days of the end of the budget period.
4. Final financial reports and performance reports are due within 90 days after the end of the project period.
Send all reports to the Grants Management Specialist identified in the “Where to Obtain Additional Information” section of this announcement.
Data collection initiated under this cooperative agreement program has been approved by the Office of Management and Budget under OMB number (0920-0337), “National Childhood Blood Lead Surveillance System”, Expiration Date: March 31, 2001.
The following additional requirements are applicable to this program. For a complete description of each, see Addendum 1 in the application package.
This program is authorized under sections 301(a), 317A and 317B of the Public Health Service Act [42 U.S.C. 241(a), 247b-1, and 247b-3], as amended. Program regulations are set forth in Title 42, Code of Federal Regulations, Part 51b. The Catalog of Federal Domestic Assistance number is 93.197.
In addition, for interested applicants, a telephone conference call for pre-application technical assistance will be held on Wednesday, February 16, 2000, from 1:30 p.m. to 3:30 p.m, Eastern Standard Time. The bridge number for the conference call is 1-800-311-3437, and the pass code is 350892. For further information about all workshops, please contact Claudette Grant-Joseph at 404-639-2510.
This and other CDC announcements may be downloaded through the CDC homepage on the Internet at http://www.cdc.gov. Please refer to program announcement number 00033 when requesting information. To receive additional written information and to request an application kit, call 1-888-GRANTS4 (1-888-472-6874). You will be asked to leave your name, address, and phone number and will need to refer to Announcement 00033. You will receive a complete program description, information on application procedures, and application forms. CDC will not send application kits by facsimile or express mail.
If you have questions after reviewing the contents of all documents, business management technical assistance may be obtained from: Mattie B. Jackson, Grants Management Specialist, Grants Management Branch, Procurement and Grants Office, Centers for Disease Control and Prevention (CDC), 2920 Brandywine Road, Room 3000, Atlanta, GA 30341-4146, telephone (770) 488-2718, Internet address mij3.@cdc.gov
For programmatic technical assistance, contact: Claudette A. Grant-Joseph, Chief, Program Services Section, Lead Poisoning Prevention Branch, Division of Environmental Hazards and Health Effects, National Center for Environmental Health, Centers for Disease Control and Prevention (CDC), 1600 Clifton Road, NE, Mailstop E-25, Atlanta, GA 30333, telephone (404) 639-2510, Internet address cag4@cdc.gov
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing that a collection of information entitled “Current Good Manufacturing Practices for Blood and Blood Components; Notification of Consignees Receiving Blood and Blood Components at Increased Risk for Transmitting HIV Infection” has been approved by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995.
JonnaLynn P. Capezzuto, Office of Information Resources Management (HFA-250), Food and Drug Administration, 5600 Fishers Lane, Rockville, MD 20857, 301-827-4659.
In the
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing that a collection of information entitled “Reclassification Petitions for Medical Devices” has been approved by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995.
Peggy Schlosburg, Office of Information Resources Management (HFA-250), Food and Drug Administration, 5600 Fishers Lane, Rockville, MD 20857, 301-827-1223.
In the
Food and Drug Administration, HHS.
Notice.
This notice announces a forthcoming meeting of a public advisory committee of the Food and Drug Administration (FDA). The meeting will be open to the public.
Notice of this meeting is given under the Federal Advisory Committee Act (5 U.S.C. app. 2).
Health Care Financing Administration, HHS.
In compliance with the requirement of section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Health Care Financing Administration (HCFA), Department of Health and Human Services, is publishing the following summary of proposed collections for public comment. Interested persons are invited to send comments regarding this burden estimate or any other aspect of this collection of information, including any of the following subjects: (1) The necessity and utility of the proposed information collection for the proper performance of the agency's functions; (2) the accuracy of the estimated burden; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
To obtain copies of the supporting statement and any related forms for the proposed paperwork collections referenced above, access HCFA's Web Site address at http://www.hcfa.gov/regs/prdact95.htm, or E-mail your request, including your address, phone number, OMB number, and HCFA document identifier, to Paperwork@hcfa.gov, or call the Reports Clearance Office on (410) 786-1326. Written comments and recommendations for the proposed information collections must be mailed within 60 days of this notice directly to the HCFA Paperwork Clearance Officer designated at the following address: HCFA, Office of Information Services, Security and Standards Group, Division of HCFA Enterprise Standards, Attention: Dawn Willinghan, Room N2-14-26, 7500 Security Boulevard, Baltimore, Maryland 21244-1850.
In compliance with Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995 concerning opportunity for public comment on proposed collections of information, the Substance Abuse and Mental Health Services Administration will publish periodic summaries of proposed projects. To request more information on the proposed projects or to obtain a copy of the information collection plans, call the SAMHSA Reports Clearance Officer on (301) 443-7978.
Comments are invited on: (a) Whether the proposed collections of information are necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology.
The Annual Census of Patient Characteristics in State and County Mental Hospital Inpatient Services (0930-0093, extension, no change)—The Census, which is conducted by SAMHSA's Center for Mental Health Services (CMHS), is a complete enumeration of all State and county mental hospitals and collects aggregate information by age, gender, and diagnosis for each State on the number of additions during the year and resident patients who are physically present for 24 hours per day in the inpatient service at the end of the reporting year. First conducted in 1840, the Census has provided information throughout the years that is not available from any other sources. The Census is the primary means within CMHS for assessing de-institutionalization practices of State and county mental hospitals. The annual burden estimate is shown in the table below.
Send comments to Nancy Pearce, SAMHSA Reports Clearance Officer, Room 16-105, Parklawn Building, 5600 Fishers Lane, Rockville, MD 20857. Written comments should be received within 60 days of this notice.
In compliance with Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995 concerning opportunity for public comment on proposed collections of information, the Substance Abuse and Mental Health Services Administration will publish periodic summaries of proposed projects. To request more information on the proposed projects or to obtain a copy of the information collection plans, call the SAMHSA Reports Clearance Officer on (301) 443-7978.
Comments are invited on: (a) Whether the proposed collections of information are necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology.
The annual total burden estimates for the Federal Drug Testing Custody and Control Form, the NLCP application, the NLCP inspection checklist, and NLCP recordkeeping requirements is 1,790,664 Hours, as shown below:
Send comments to Nancy Pearce, SAMHSA Reports Clearance Officer, Room 16-105, Parklawn Building, 5600 Fishers Lane, Rockville, MD 20857. Written comments should be received within 60 days of this notice.
Notice is hereby given of the following workshops for the provision of technical assistance to potential applicants for SAMHSA grants.
The Substance Abuse and Mental Health Services Administration's (SAMHSA's) Center for Mental Health Services (CMHS), Center for Substance Abuse Prevention (CSAP) and Center for Substance Abuse Treatment (CSAT), are offering a series of three, two-day regional Technical Assistance Workshops for prospective applicants. These workshops will be conducted jointly by the three SAMHSA Centers to provide support to prospective applicants in preparing their applications in response to published grant announcements.
It is anticipated that several SAMHSA grant announcements will be featured at the workshop, including:
These GFAs can be found at the SAMHSA Web Site at www.SAMHSA.gov following publication in the
The Technical Assistance Workshops will be held at the following locations: Workshop I—March 2 & 3, Ritz Carlton Hotel Atlanta, GA, 404-659-0400 or 800-241-3333; Workshop II—March 7 & 8, Westin Hotel, Kansas City, MO, 816-474-4400 or 800-228-3000; and Workshop III—March 9 & 10, The Wyndham Emerald, San Diego, CA, 619-239-4500.
Registration and check-in at each site will be at 7:30 a.m.; workshop hours on the first day are 8:30 a.m.-5:00 p.m. On the second day, the grant writing session will take place from 8:30 a.m.-3:30 p.m.
Preliminary Agenda Highlights for the TA Workshops include: (1) Review of SAMHSA programs and priorities; (2) Provision of related resource materials; (3) Technical/practical aspects of the grants application process including application requirements, improving applications, instruction in completing required forms, submission, review, and award procedures; (4) Separate breakout sessions for discussion of specific grant announcements; and (5) Opportunity for questions and answers. Plans are underway to include a brief overview at each of the workshops on the Health Resources and Services Administration and the Centers for Disease Control and Prevention programs. On the second day, there will be a session designed to provide further assistance with grant writing and application preparation.
There is no registration fee for the workshops. Preregistration is strongly encouraged.
Registrants will be responsible for costs associated with their own travel, meals, and lodging. Workshop confirmation will be faxed. For logistical assistance please contact Lisa Wilder by phone at (301) 984-1471, x-361 or by fax at (301) 984-4416. For information regarding the content of the TA Workshops, please contact Ms. C. Danielle Johnson at (301) 443-1249. SAMHSA suggests that the attendees be those persons having the responsibility for conceptualizing and writing the application.
Participants are responsible for making their own hotel reservations. When calling the hotel, at the numbers listed above, reference the SAMHSA Grantee Workshop. Registrants are urged to make their reservations as soon as possible.
Office of the Assistant Secretary for Policy Development and Research, HUD.
Notice.
The proposed information collection requirement described below will be submitted to the Office of Management and Budget (OMB) for review, as required by the Paperwork Reduction Act. Public comments on the subject proposal are being solicited.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name or OMB Control Number and be sent to: Reports Liaison Officer, Office of Policy Development and Research, U.S. Department of Housing and Urban Development, 451 7th Street, SW, Room 8226, Washington, DC 20410.
Jane Karadbil, Office of University Partnerships, Department of Housing and Urban Development, 451 7th Street, Washington, DC 20410; telephone (202) 708-1537 (this is not a toll-free number). Copies of the proposed forms and other available documents to be submitted to OMB may be obtained from Ms. Karadbil.
The Department will submit the proposed information collection to OMB for review, as required by the Paperwork Reduction Action of 1995 (44 U.S.C. Chapter 35, as amended).
This Notice is soliciting comments from members of the public and affected entities concerning the proposed information collection to: (1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (2) Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information; (3) Enhance the quality, utility, and clarity of information to be collected; and (4) Minimize the burden of collection of information on those who are to respond; including through the use of appropriated technology, e.g., permitting electronic submission of responses.
This Notice also lists the following information:
The following chart details the respondent burden on an annual basis:
Section 3506 of the Paperwork Reduction Act of 1995, 44 U.S.C. Chapter 35, as amended.
Office of Lead Hazard Control, HUD.
Notice.
The proposed information collection requirement concerning the Notice of Funding Availability (NOFA) for Research to Improve the Evaluation and Control of Residential Lead-Based Paint Hazards will be submitted to the Office of Management and Budget (OMB) for review, as required by the Paperwork Reduction Act. The Department is soliciting public comments on the subject proposal.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB Control Number and should be sent to: Gail N. Ward, Reports Liaison Officer, Department of Housing and Urban Development, 451 7th Street, SW, Room P3206, Washington, DC 20410.
Eugene A. Pinzer, (202) 755-1785 ext. 120 (this is not a toll-free number) for available documents regarding this proposal.
The Department is submitting the proposed information collection to OMB for review, as required by the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35, as amended).
This Notice is soliciting comments from members of the public and affected agencies concerning the proposed collection of information to: (1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (2) evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information; (3) enhance the quality, utility, and clarity of the information to be collected; and (4) minimize the burden of the collection of information on those who are to respond; including through the use of appropriate automated collection techniques or other forms of information technology,
This Notice also lists the following information:
Results from this research will be used to update the HUD Guidelines for the Evaluation and Control of Lead-Based Paint Hazards in Housing. It is anticipated that this targeted research will also increase both the accuracy of residential lead hazard evaluation and the effectiveness of residential lead hazard reduction interventions, while improving the cost-effectiveness of the entire process. This research should contribute to an eventual reduction in the national prevalence of childhood lead poisoning.
The Paperwork Reduction Act of 1995, 44 U.S.C. Chapter 35, is amended.
Office of the Chief Information Officer, HUD.
Notice.
The proposed information collection requirement described below has been submitted to the Office of Management and Budget (OMB) for review, as required by the Paperwork Reduction Act. The Department is soliciting public comments on the subject proposal.
Comments Due Date: March 13, 2000.
Interested persons are invited to submit comments regarding this proposal. Comments should refer to the proposal by name and/or OMB approval number (2502-0538) and should be sent to: Joseph F. Lackey, Jr., OMB Desk Officer, Office of Management and Budget, Room 10235, New Executive Office Building, Washington, DC 20503; (202) 395-7316.
Wayne Eddins, Reports Management Officer, Q, Department of Housing and Urban Development, 451 Seventh Street, Southwest, Washington, DC 20410; e-mail Wayne_Eddins@HUD.gov; telephone (202) 708-2374. This is not a toll-free number. Copies of the proposed forms and other available documents submitted to OMB may be obtained from Mr. Eddins.
The Department has submitted the proposal for the collection of information, as described below, to OMB for review, as required by the Paperwork Reduction Act (44 U.S.C. Chapter 35). The Notice lists the following information: (1) The title of the information collection proposal; (2) the office of the agency to collect the information; (3) the OMB approval number, if applicable; (4) the description of the need for the information and its proposed use; (5) the agency form number, if applicable; (6) what members of the public will be affected by the proposal; (7) how frequently information submissions will be required; (8) an estimate of the total number of hours needed to prepare the information submission including number of respondents, frequency of response, and hours of response; (9) whether the proposal is new, an extension, reinstatement, or revision of an information collection requirement; and (10) the name and telephone number of an agency official familiar with the proposal and of the OMB Desk Officer for the Department.
This Notice also lists the following information:
Section 3507 of the Paperwork Reduction Act of 1995, 44 U.S.C. 35, as amended.
The following applicants have applied for a permit to conduct certain activities with endangered species. This notice is provided pursuant to Section 10(c) of the Endangered Species Act of 1973,
The applicant requests a permit to import and export one captive-born male cheetah (
The applicant requests a permit to import one captive-hatched male Cabot's tragopan (
The applicant requests a permit to import one captive-born female Java gibbon (
The applicant requests a permit to export semen samples collected from one captive-bred Sumatram orangutan (
The applicant requests a permit to re-export the salvaged skeleton of a brown pelican (
Written data or comments should be submitted to the Director, U.S. Fish and Wildlife Service, Office of Management Authority, 4401 North Fairfax Drive, Room 700, Arlington, Virginia 22203 and must be received by the Director within 30 days of the date of this publication.
The public is invited to comment on the following application for a permit to conduct certain activities with marine mammals. The application was submitted to satisfy requirements of the Marine Mammal Protection Act of 1972,
The applicant requests a permit to import a sport-hunted polar bear (
Written data, comments or requests for copies of these complete applications or requests for a public hearing on these applications should be sent to the U.S. Fish and Wildlife Service, Office of Management Authority, 4401 N. Fairfax Drive, Room 700, Arlington, Virginia 22203. These requests must be received within 30 days of the date of publication of this notice. Anyone requesting a hearing should give specific reasons why a hearing would be appropriate. The holding of such a hearing is at the discretion of the Director.
Documents and other information submitted with these applications are available for review,
Bureau of Land Management, Interior.
Notice of availability of the draft Sonoran Pronghorn Forage Enhancement Project Environmental Assessment (EA), Yuma and Phoenix Field Offices.
The draft Sonoran Pronghorn Forage Enhancement Project Environmental Assessment (EA) evaluates the environmental impacts of a proposed project to improve habitat for the endangered Sonoran pronghorn on the Barry M. Goldwater Air Force Range. The Sonoran pronghorn was listed as an endangered subspecies in 1967. Since that time, numbers of the animal in the United States have been estimated to fluctuate between 100 and 400 animals. The population appears to be limited by low recruitment of fawns into the population. Most fawns die each year in late June and early July when the availability of green forage decreases. The proposed forage enhancement project would provide forage for pronghorn on up to 14 plots. The plots would provide native forage for pronghorn and a source of free water to aid in digestion. The plots would not be permanently established and are not meant to interfere with the normal seasonal movements of pronghorn. The project would be jointly carried out by the Arizona Game and Fish Department, Luke Air Force Base, Marine Corps Air Station, Yuma, and the Bureau of Land Management.
Comments on the draft Environmental Assessment will be accepted through March 24, 2000.
Copies of the Environmental Assessment are available upon request to: Field Manager, Bureau of Land Management, 2555 East Gila Ridge Road, Yuma, Arizona 85365. There are also copies available for review at that location and at the Yuma County Library, 350 South Third Avenue, Yuma, Arizona, 85364.
Wildlife Biologist Susanna Henry, Bureau of Land Management, 2555 East Gila Ridge Road, Yuma, Arizona, 85365, telephone (520) 317-3211.
Butte Field Office, Bureau of Land Management, DOI.
Notice of meeting.
The Western Montana Resource Advisory Council will convene at 9 a.m., Wednesday, March 1, 2000, at the Butte Field Office, 106 North Parkmont, Butte, Montana. Issues will include the statewide weed management steering committee, the Elkhorns Westslope Cutthroat Restoration Plan, an update on the Montana/Dakotas Off-Highway Vehicle environmental impact statement, and sage grouse habitat management.
The meeting is open to the public and written comments may be given to the Council. Oral comments may be presented to the Council at 11:30 a.m. The time allotted for oral comment may be limited, depending on the number of persons wishing to be heard. Individuals who plan to attend and need further information about the meeting, or who need special assistance, such as sign language or other reasonable accommodations, should contact Jean Nelson-Dean, Resource Advisory Coordinator, at the Butte Field Office, 106 North Parkmont (P.O. Box 3388), Butte, Montana 59702-3388, telephone 406-494-5059.
Acting Butte Field Manager Tim Bozorth or Jean Nelson-Dean at the above address or telephone number.
Vale District, Bureau of Land Management, Interior.
Meeting of John Day/Snake Resource Advisory Council: Pendleton, Oregon; March 30 & 31, 2000.
A meeting of the John Day/Snake Resource Advisory Council will be held on March 30, 2000 from 8:00 a.m. to 5:00 p.m. and on March 31, 2000 from 7:30 a.m. to 3:00 p.m. at the Red Lion (formerly Doubletree) Inn, 304 SE Nye Avenue, Pendleton, Oregon. The meeting is open to the public. Public comments will be received at 10:00 a.m. on March 31, 2000. Topics to be discussed by the council will include: John Day River Plan update; Social Circle Map; Hells Canyon Subgroup update; ICBEMP update; status of roadless area review, range program status report for BLM & Forest Service offices; T&E presentation on listing process of lynx, wolf and sage grouse; discuss the need for or benefits of a future joint meeting of the three Oregon/Washington councils; and a 15 minute round table for general issues.
Juan Palma, Bureau of Land Management, Vale District Office, 100 Oregon Street, Vale, Oregon 97918, Telephone (541) 473-3144.
National Park Service
Native American Graves Protection and Repatriation Review Committee; Notice of Nomination Solicitation
Nominations should be received by June 19, 2000.
Nominations should be sent to the Assistant Director, Cultural Resources Stewardship and Partnerships, 1849 C Street NW- 350 NC, Washington, DC 20240. Nominations should include a brief biography with home and business addresses and telephone number of each nominated individual.
Mr. John Robbins, Assistant Director, Cultural Resources Stewardship and Partnerships, 1849 C Street NW- 350 NC, Washington, DC 20240; telephone 202/343-3387. A copy of the charter for this review committee is available upon request.
Section 8 (b) of the Act stipulates that the review committee is composed of seven members appointed by the Secretary of the Interior as follows:
a. Three members appointed from nominations by Indian tribes, Native Hawaiian organizations, and traditional religious leaders, with at least two such persons being traditional religious leaders. The term traditional religious leader means:
1. a person who is recognized by members of an Indian tribe or Native Hawaiian organization as being responsible for performing cultural duties relating to the ceremonial or religious traditions of that Indian tribe; or
2. a person who has or is exercising a leadership role in an Indian tribe or Native Hawaiian organization based on the tribe's or organization's cultural, ceremonial, or religious practices.
b. Three members appointed from nominations submitted by national museum organizations and scientific organizations; and
c. One member appointed from a list of persons developed and consented to by all of the other members.
The Secretary of the Interior will appoint one member from nominations received from Indian tribes and Native Hawaiian organizations. This particular appointee is not required to be a traditional religious leader.
The Secretary of the Interior will appoint one member from nominations received from national museum organizations and scientific organizations. The Secretary of the Interior may not appoint Federal officers or employees to the review committee.
National Park Service, Interior.
Notice of Meeting of Going-to-the-Sun Road Advisory Committee.
This notice announces a scheduled meeting of the Going-to-the-Sun Road Advisory Committee. Notice of this meeting is required under the Federal Advisory Committee Act (Pub. L. 92-463).
Tuesday, February 29, 2000 (8:00 a.m. to 12:00 noon and 1:00 p.m. to 5:00 p.m.); Wednesday, March 1, 2000 (8:00 a.m. to 12:00 noon and 1:00 p.m. to 5:00 p.m.); and Thursday, March 2, 2000 (8:00 a.m. to 12:00 noon and 1:00 p.m. to 5:00 p.m.)
Cavanaughs at Kalispell Center, 20 N. Main Street, Kalispell, Montana 59901, 406-752-6660.
On February 29 National Park Service Regional Director Karen Wade will address the Committee. The rest of the morning will focus on the Committee's purpose and related organizational and procedural matters and desired outcomes. The second two days will be devoted to the Going-to-the-Sun Road including the legislated engineering study and economic analysis based on the desired outcomes discussed the previous day. Project scope, schedule, and responsibilities will be part of these discussions.
The Committee may be addressed at various times by other officials of the National Park Service and the Department of the Interior; and other miscellaneous topics and reports may be covered. The order of the agenda may be changed, if necessary, to accommodate travel schedules or for other reasons.
The Committee meeting will be open to the public. Space and facilities to accommodate the public are limited and attendees will be accommodated on a first-come basis. Anyone may file with the Committee a written statement concerning matters to be discussed. The Committee may also permit attendees to address the Committee, but may restrict the length of the presentations, as necessary to allow the Committee to complete its agenda within the allotted time.
Anyone who wishes further information concerning the meeting, or who wishes to submit a written statement, may contact Dayna Hudson, Office of the Superintendent, Glacier National Park, P.O. Box 128, West Glacier, MT 59936 (telephone 406-888-7972).
Draft minutes of the meeting will be available for public information 30 days after the meeting in the Project Manager's Office, Park Headquarters, Glacier National Park, West Glacier, MT.
National Park Service.
Notice.
Notice is hereby given in accordance with the Federal Advisory Committee Act (FACA), 5 U.S.C. Appendix (1988), that a meeting of the Native American Graves Protection and Repatriation Review Committee will be held on April 2, 3, and 4, 2000, in Juneau, Alaska.
The committee will meet at the Centennial Hall Convention Center; telephone: 907/586-5283, fax: 907/586-1135, located at 101 Egan Drive, Juneau, Alaska. Meetings will begin at 8:30 a.m. and will end no later than 5:00 p.m. each day.
The Native American Graves Protection and Repatriation Review Committee was established by Public Law 101-601 to monitor, review, and assist in implementation of the inventory and identification process and repatriation activities required under the Native American Graves Protection and Repatriation Act.
The agenda for this meeting will include: recommendations for disposition of culturally unidentifiable human remains, 1999 Report to Congress, discussion of Federal agency compliance, and implementation of the statute in Alaska.
The meeting will be open to the public. However, facilities and space for accommodating members of the public are limited. Persons will be accommodated on a first-come, first-served basis. Persons wishing to make a presentation to the committee should submit a request to do so by March 3, 2000. Please submit a written abstract of your presentation and your contact information. Any member of the public may also file a written statement for consideration by the committee by March 13, 2000. Both written requests and statements should be addressed to the committee in care of the Assistant Director, Cultural Resources Stewardship and Partnerships.
A block of lodging rooms has been set aside at the Westmark Baranof (800/764-0017) and the Goldbelt Hotel (888/478-6909) at a significantly reduced rate. Reservations must be booked with these hotels by March 4, 2000, to guarantee the reduced rate. Please reference the National Park Service and mention that you are attending the NAGPRA Review Committee Meeting.
Persons wishing further information concerning this meeting, or who wish to submit written statements may contact Mr. John Robbins, Assistant Director, Cultural Resources Stewardship and Partnerships, 1849 C St. NW—350 NC, Washington, DC 20240; telephone: 202/343-3387; fax: 202/343-5260. Transcripts of the meeting will be available for public inspection approximately eight weeks after the meeting at the office of the Assistant Director, Cultural Resources Stewardship and Partnerships, 800 North Capitol St., NW, Suite 350, Washington, DC 20013.
National Park Service, Department of the Interior.
NAGPRA Review Committee Advisory Findings and Recommendations Regarding Human Remains and Associated Funerary Objects in the Control of Chaco Culture National Historical Park.
After full and careful consideration of the information and statements submitted and presented by representatives of the Hopi Tribe and Chaco Culture National Historical Park at its meetings on May 3-5, 1999 and November 18-20, 1999, the Native American Graves Protection and Repatriation Review Committee (Review Committee) considers that:
1. On May 12, 1999, Chaco Culture National Historical Park published a Notice of Inventory Completion regarding 265 Native American human remains and 743 funerary objects. The park determined the human remains and funerary objects to be culturally affiliated with the Hopi Tribe of Arizona; Navajo Nation of Arizona, New Mexico, and Utah; Pueblo of Acoma, New Mexico; Pueblo of Cochiti, New Mexico; Pueblo of Isleta, New Mexico; Pueblo of Laguna, New Mexico; Pueblo of Nambe, New Mexico; Pueblo of Picuris, New Mexico; Pueblo of Pojoaque, New Mexico; Pueblo of San Felipe, New Mexico; Pueblo of San Ildefonso, New Mexico; Pueblo of San Juan, New Mexico; Pueblo of Sandia, New Mexico; Pueblo of Santa Ana, New Mexico; Pueblo of Santa Clara, New Mexico; Pueblo of Santo Domingo, New Mexico; Pueblo of Taos, New Mexico; Pueblo of Tesuque, New Mexico; Pueblo of Zia, New Mexico; and the Zuni Tribe of Zuni Reservation, New Mexico.
2. The Hopi Tribe disputed the park's determinations of cultural affiliation, arguing that:
a. Proper tribe-by-tribe consultation was not performed by the park;
b. The park did not apply a rigorous standard in weighing the evidence in making determinations of cultural affiliation; and
c. Determinations of cultural affiliation must be made on an object-by-object basis, rather than globally for the park as a whole.
3. Chaco Culture National Historical Park answered these objections by pointing to a nine-year record of tribal consultations. The park also argued that there is cultural continuity within Chaco Canyon dating to the Archaic Period (pre 1 AD) and that as such, there was no value in assessing cultural affiliation for each site individually. The park defended its determinations of cultural affiliation on the grounds that a broad range of both scientific and traditional evidence had been used. It was also noted that given the complex history of Chaco Canyon, and the strong
On hearing all of the evidence presented, the Review Committee finds that the complaints made by the Hopi Tribe have merit. While the Review Committee recognizes the efforts made in the area of tribal consultation, tribes were not given adequate opportunity to consult on a one-to-one basis and to make their concerns known outside of a public forum. The Review Committee also agrees with the Hopi Tribe that more is needed in the evaluating and weighing of the evidence for establishing cultural affiliation. Rather than a rigorous determination of cultural affiliation, the park seems to have applied a much looser criterion of cultural relationship to geographical place, as a basis for determining culturally affiliated tribes. The park's global approach to the assessment Chaco archeological sites, effectively precluded any realistic assessment of cultural affiliation based on specific site features, dates, or cultural practices. Likewise, sites with virtually no contextual information were treated as culturally affiliated. The global approach to site assessment and affiliation resulted in a determination of cultural affiliation for all Chaco Canyon remains with all groups expressing cultural relationship to the region.
It is the recommendation of the Review Committee that the Chaco Culture National Historical Park withdraw its published Notice if Inventory Completion and reassess its determination of cultural affiliation. The Review Committee recommends that this reassessment specifically consider the following issues:
1. Determination of cultural affiliation should be made on a site-by-site basis, assessing each site based on the specific data available;
2. While collective consultation can be useful, it should not be used in lieu of individual tribal consultation when requested by an Indian tribe;
3. A proper determination of cultural affiliation necessarily requires the critical evaluation and careful weighing of all available evidence. This weighing should emphasize group identity, time period, specific cultural practices, and traceable cultural continuity;
4. The park should take steps to ensure the objective character of the determinations of cultural affiliation of the human remains and other cultural items in the control of the park. The process the park follows in making cultural affiliation determinations also must be seen by others to have been objective. For example, the Review Committee believes that the park should engage a qualified independent contractor to re-evaluate the information from the Chaco sites and offer specific recommendation for cultural affiliation.
Review Committee member James Bradley did not participate in the Review Committee's deliberations nor in the formulation of these advisory findings and recommendations.
These advisory findings and recommendations do not necessarily represent the views of the National Park Service or the Secretary of the Interior. The National Park Service and the Secretary of the Interior have not taken a position on these matters.
National Park Service.
Notice.
Notice is hereby given in accordance with provisions of the Native American Graves Protection and Repatriation Act (NAGPRA), 43 CFR 10.9, of the completion of an inventory of human remains from Rockbridge County, VA in the possession of the Virginia Department of Historic Resources, Richmond, VA.
A detailed assessment of the human remains was made by Virginia Department of Historic Resources professional staff in consultation with representatives of the Chickahominy, the Eastern Chickahominy, the Mattaponi, the Monacan Indian Nation, the Nansemond, the Pamunkey, the United Rappahannock, the Upper Mattaponi, all non-Federally recognized Indian groups which are formally recognized by the Commonwealth of Virginia.
In 1901, human remains representing a minimum of 105 individuals were excavated from the Hayes Creek Mound, Rockbridge County, VA by Edward P. Valentine, an amateur archeologist with the Valentine Museum, Richmond, VA. In 1989, these human remains were donated to the Virginia Department of Historic Resources by the Valentine Museum. No known individuals were identified. No associated funerary objects are present.
Based on material culture and archeological evidence, the Hayes Creek Mound site has been identified as a Late Woodland (c. 900-1600 A.D.) occupation. Based on the material culture and condition of the human remains, these individuals have been identified as Native American. Archeological and ethnohistoric research indicates the Monacan and Mannahoac were loosely confederated with each other and linked to the earlier mound-building peoples in the Virginia piedmont and eastern mountain regions generally known as the Lewis Creek Mound Culture. Consultation evidence presented by the present-day Monacan indicates a direct lineal connection with the Monacan and related tribes occupying Rockbridge County in the early 17th century. Based on continuities of mound construction and site arrangement, there appears to be a shared ideology and cultural continuity which underlayed and defined not only the Monacan east of the Blue Ridge, but also includes related groups on the immediate west side of the Blue Ridge.
On October 29, 1999, the Virginia Department of Historic Resources requested a finding from the NAGPRA Review Committee concerning the Monacan Indian Nation's request for repatriation for these 105 individuals listed as “culturally unidentifiable” on the Department's NAGPRA inventory. At its November 18-20, 1999 meeting, the NAGPRA Review Committee recommended that the Department proceed with repatriation of these Native American human remains to the Monacan Indian Nation following publication of this Notice of Inventory Completion in the Federal Register.
Based on the above mentioned information, officials of the Virginia Department of Historic Resources have determined that, pursuant to 43 CFR 10.2 (d)(1), the human remains listed above represent the physical remains of a minimum of 105 individuals of Native American ancestry. Officials of the Virginia Department of Historic Resources have determined that, pursuant to 25 U.S.C. 3001 (2), no relationship of shared group identity can be reasonably traced between these Native American human remains and a Federally recognized Indian tribe. However, officials of the Virginia Department of Historic Resources have determined that a relationship of shared group identity can be reasonably traced between these Native American human remains and the Monacan Indian
This notice has been sent to officials of the Chickahominy, the Eastern Chickahominy, the Mattaponi, the Monacan Indian Nation, the Nansemond, the Pamunkey, the United Rappahannock, the Upper Mattaponi. Representatives of any other Federally recognized Indian tribe or other valid claimant under NAGPRA that believes itself to be culturally affiliated with these human remains should contact M. Catherine Slusser, State Archaeologist, Department of Historic Resources, 2801 Kensington Ave., Richmond, VA 23221; telephone: (804) 367-2323, before March 13, 2000. Repatriation of the human remains to the Monacan Indian Nation may begin after that date if no Federally recognized Indian tribes or other valid claimant under NAGPRA makes a claim.
The National Park Service is not responsible for the determinations within this notice.
Bureau of Reclamation, Interior.
Notice.
This notice is issued in accordance with 35 U.S.C. 209(c)(1) and 37 CFR 404.7(a)(1)(I). The Bureau of Reclamation (Reclamation) is contemplating the granting of an exclusive license in the United States to practice the invention embodied in U.S. Patent No. 5,544,973 titled “Concrete Step Embankment Protection”. The exclusive license is to be granted to Lee Masonary Products, L.L.C., DBA Armortec, having a place of business in Bowling Green, Kentucky. The patent rights in this invention has been assigned to the United States of America.
The prospective exclusive license will be royalty-bearing and will comply with the terms and conditions of 35 U.S.C. 209 and 37 CFR 404.7. While the primary purpose of this notice is to announce Reclamation's intent to grant an exclusive license to practice the invention listed above, it also serves to publish the availability of this invention for licensing in accordance with law. The prospective license may be granted unless Reclamation receives written evidence and argument which establish that the grant of the license would not be consistent with the requirements of 35 U.S.C. 209 and 37 CFR 404.7
Written evidence and arguments against granting the prospective license must be received by May 10, 2000.
Inquiries, comments, and other materials relating to the contemplated license may be submitted to Donald E. Ralston, Bureau of Reclamation, Research and Technology Transfer, MS-7620, 1849 C Street, N.W., Washington, D.C. 20240.
A copy of the above-identified patent may be purchased from the NTIS Sales Desk by telephoning 1-800-553-NTIS or by writing NTIS at 5285 Port Royal Road, Springfield, VA 22161.
Donald Ralston by telephone at (202) 208-5671.
The present invention relates to a dam spillway system for embankment dam overtopping protection comprising a layer of freedraining, angular, gravel filter material, a plurality of rows of overlapping, tapered, concrete blocks assembled over the filter material in shingle-fashion, from the toe of the dam, up the slope to the top of the dam, and a plurality of fixed concrete toe blocks located at the toe of the dam, usually beneath the tailwater, and supporting each of the rows of concrete blocks. The invention has particular application to providing erosion protection for embankment dams that may be subject to overtopping flows.
Properly filed competing applications received by Reclamation in response to this notice will be considered as objections to the grant of the contemplated license.
Office of Surface Mining Reclamation and Enforcement.
Notice and request for comments.
In compliance with the Paperwork Reduction Act of 1995, the Office of Surface Mining Reclamation and Enforcement (OSM) is announcing that the information collection request for 30 CFR 783, Underground Mining Permit Applications—Minimum Requirements for Information on Environmental Resources has been forwarded to the Office of Management and Budget (OMB) for review and comment. The information collection request describes the nature of the information collection and the expected burden and cost.
Comments must be submitted on or before March 13, 2000, to be assured of consideration.
To request a copy of the information collection request, explanatory information and related form, contact John A. Trelease at (202) 208-2783.
The Office of Management and Budget (OMB) regulations at 5 CFR 1320, which implement provisions of the Paperwork Reduction Act of 1995 (Pub. L. 104-13), require that interested members of the public and affected agencies have an opportunity to comment on information collection and recordkeeping activities (see 5 CFR 1320.8(d)). OSM has submitted a request to OMB to renew its approval of the collection of information found at 30 CFR 783, Underground Mining Permit Applications—Minimum Requirements for Information on Environmental Resources. OSM is requesting a 3-year term of approval for this information collection activity.
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control number for this collection of information is listed in 30 CFR Part 783, which is 1029-0038.
As required under 5 CFR 1320.8(d), a
The following information is provided for the information collection: (1) title of the information collection; (2) OMB control number; (3) summary of the information collection activity; and (4) frequency of collection, description of the respondents, estimated total annual responses, and the total annual reporting and recordkeeping burden for the collection of information. Where appropriate, OSM has revised burden
Send comments on the need for the collection of information for the performance of the functions of the agency; the accuracy of the agency's burden estimates; ways to enhance the quality, utility and clarity of the information collection; and ways to minimize the information collection burden on respondents, such as use of automated means of collection of the information, to the following address. Please refer to the appropriate OMB control number in all correspondence.
Office of Information and Regulatory Affairs, Office of Management and Budget, Attention: Department of Interior Desk Officer, 725 17th Street, NW, Washington, DC 20503, and to John A. Trelease, Office of Surface Mining Reclamation and Enforcement, 1951 Constitution Ave, NW, Room 210—SIB, Washington DC 20240.
International Trade Commission.
Revised schedule for the subject investigations.
Date of commission action.
Elizabeth Haines (202-205-3200), Office of Investigations, U.S. International Trade Commission, 500 E Street SW, Washington, DC 20436. Hearing-impaired persons can obtain information on this matter by contacting the Commission's TDD terminal on 202-205-1810. Persons with mobility impairments who will need special assistance in gaining access to the Commission should contact the Office of the Secretary at 202-205-2000. General information concerning the Commission may also be obtained by accessing its internet server (http://www.usitc.gov).
On December 1, 1999, the Commission established a schedule for the conduct of the final phase of the subject investigations (
The Commission's new schedule for the investigations is as follows: the Commission will release the staff report to parties on February 18, the final release of information will be on February 25; and final party comments are due on February 29.
For further information concerning these investigations see the Commission's notice cited above and the Commission's Rules of Practice and Procedure, part 201, subparts A through E (19 CFR part 201), and part 207, subparts A and C (19 CFR part 207).
These investigations are being conducted under authority of title VII of the Tariff Act of 1930; this notice is published pursuant to section 207.21 of the Commission's rules.
By order of the Commission.
On the basis
The Commission instituted these investigations effective February 16, 1999, following receipt of petitions filed with the Commission and the Department of Commerce by Bethlehem Steel Corp., Bethlehem, PA; U.S. Steel Group, a unit of USX Corp., Pittsburgh, PA; Gulf States Steel, Inc., Gadsden, AL; IPSCO Steel, Inc., Muscatine, IA; Tuscaloosa Steel Co., Tuscaloosa, AL; and the United Steelworkers of America, Pittsburgh, PA.
The Commission transmitted its determinations in these investigations to the Secretary of Commerce on February 1, 2000. The views of the Commission are contained in USITC Publication 3273 (January 2000), entitled Certain Cut-to-length Steel Plate from France, India, Indonesia, Italy, Japan, and Korea: Investigations Nos. 701-TA-387-391 and 731-TA-816-821 (Final).
International Trade Commission.
Notice.
Notice is hereby given that the U.S. International Trade Commission has determined to review-in-part the final initial determination (“ID”) issued on December 6, 1999, by the presiding administrative law judge (“ALJ”) in the above-captioned investigation finding that there was no violation of section 337 of the Tariff Act of 1930, 19 U.S.C. 1337.
Timothy P. Monaghan, Esq., Office of the General Counsel, U.S. International Trade Commission, 500 E Street, S.W., Washington, D.C. 20436, telephone 202-205-3152. General information concerning the Commission may also be obtained by accessing its Internet server (
This investigation was instituted on March 1, 1999, based on a complaint by VISX, Inc. (“VISX”), 64 Fed. Reg. 10016-17. The respondents named in the investigation are Nidek Co., Ltd., Nidek Inc., and Nidek Technologies, Inc. Complainant alleges importation and sale of certain excimer laser systems for vision correction surgery that infringe claims of U.S. Letters Patent Nos. 4,718,418 (“the ’418 patent”) and 5,711,762 (“the ’762 patent”). An evidentiary hearing was held from August 18, 1999 to August 27, 1999.
On December 6, 1999, the presiding administrative law judge (“ALJ”) issued her final ID finding that complainant VISX failed to establish the required domestic industry, that there was no infringement of any claim at issue, and that the ’762 patent was invalid and unenforceable.
Having examined the record in this investigation, the final ID, the petitions for review, and the responses thereto, the Commission has determined not to review the ID's findings with respect to the ’418 patent. The Commission has determined to review the ID's findings with respect to the ’762 patent. Review questions and a briefing schedule will be issued following the issuance of this notice.
This action is taken under the authority of section 337 of the Tariff Act of 1930, 19 U.S.C. 1337, and sections 210.45-210.51 of the Commission's Rules of Practice and Procedure, 19 CFR 210.45-210.51.
Copies of the public versions of the subject IDs, and all other nonconfidential documents filed in connection with this investigation, are or will be available for inspection during official business hours (8:45 a.m. to 5:15 p.m.) in the Office of the Secretary, U.S. International Trade Commission, 500 E Street S.W., Washington, D.C. 20436, telephone 202-205-2000.
By order of the Commission.
International Trade Commission.
Notice.
Notice is hereby given of the schedule for filing written submissions on the issues under review in the above-captioned investigation in connection with the Commission's review-in-part of the final initial determination (“ID”) issued on December 6, 1999, by the presiding administrative law judge (“ALJ”) in the above-captioned investigation.
Timothy P. Monaghan, Esq., Office of the General Counsel, U.S. International Trade Commission, 500 E Street, SW, Washington, DC 20436, telephone 202-205-3152. General information concerning the Commission may also be obtained by accessing its Internet server (http://www.usitc.gov). Hearing-impaired persons are advised that information on this matter can be obtained by contacting the Commission's TDD terminal on 202-205-1810.
This investigation was instituted on March 1, 1999, based on a complaint by VISX, Inc. (“VISX”), 64 FR 10016-17. The respondents named in the investigation are Nidek Co., Ltd., Nidek Inc., and Nidek Technologies, Inc. Complainant alleges importation and sale of certain excimer laser systems for vision correction surgery that infringe claims of U.S. Letters Patent Nos. 4,718,418 (“the '418 patent”) and 5,711,762 (“the '762 patent”). An evidentiary hearing was held from August 18, 1999, to August 27, 1999.
On December 6, 1999, the presiding administrative law judge (“ALJ”) issued her final ID finding that complainant VISX failed to establish the required domestic industry, that there was no infringement of any claim at issue, and that the '762 patent was invalid and unenforceable.
On February 2, 2000, the Commission determined not to review the ID's findings with respect to the '418 patent and determined to review all the ID's
(1) The construction of the claimed laser delivery system means element of claim 1 of the '762 patent.
(2) The construction of claim 10 of the '762 patent and the ramifications of that construction under the doctrine of claim differentiation as it relates to claims 1 and 10.
(3) A discussion, including a detailed engineering description, of how VISX's STAR, STAR S2, 20/20A, and 20/20B systems function, and whether those systems practice claims 1, 10, or 12 of the '762 patent, both as those claims are construed by the ALJ and if claim 1 is construed as not requiring a proximity mask.
(4) Whether the accused Nidek device infringes claim 1 of the '762 patent literally or under the doctrine of equivalents if claim 1 is construed as not requiring a proximity mask.
In connection with the final disposition of this investigation, the Commission may issue (1) an order that could result in the exclusion of the subject articles from entry into the United States, and/or (2) cease and desist orders that could result in respondents being required to cease and desist from engaging in unfair acts in the importation and sale of such articles. Accordingly, the Commission is interested in receiving written submissions that address the form of remedy, if any, that should be ordered. If a party seeks exclusion of an article from entry into the United States for purposes other than entry for consumption, the party should so indicate and provide information establishing that activities involving other types of entry either are adversely affecting it or likely to do so. For background, see In the Matter of Certain Devices for Connecting Computers via Telephone Lines, Inv. No. 337-TA-360, USITC Pub. No. 2843 (December 1994) (Commission Opinion).
If the Commission contemplates some form of remedy, it must consider the effects of that remedy upon the public interest. The factors the Commission will consider include the effect that an exclusion order and/or cease and desist orders would have on (1) the public health and welfare, (2) competitive conditions in the U.S. economy, (3) U.S. production of articles that are like or directly competitive with those that are subject to investigation, and (4) U.S. consumers. The Commission is therefore interested in receiving written submissions that address the aforementioned public interest factors in the context of this investigation.
If the Commission orders some form of remedy, the President has 60 days to approve or disapprove the Commission's action. During this period, the subject articles would be entitled to enter the United States under a bond, in an amount determined by the Commission and prescribed by the Secretary of the Treasury. The Commission is therefore interested in receiving submissions concerning the amount of the bond that should be imposed.
The parties to the investigation, interested government agencies, and any other interested parties are encouraged to file written submissions on the issues under review, and on remedy, the public interest, and bonding. Such submissions should address the January 31, 2000, recommended determination by the ALJ on remedy and bonding. Complainant and the Commission investigative attorney are also requested to submit proposed remedial orders for the Commission's consideration. The written submissions and proposed remedial orders must be filed no later than close of business on February 14, 2000. Reply submissions must be filed no later than the close of business on February 18, 2000. No further submissions on these issues will be permitted unless otherwise ordered by the Commission.
Persons filing written submissions must file with the Office of the Secretary the original document and 14 true copies thereof on or before the deadlines stated above. Any person desiring to submit a document (or portion thereof) to the Commission in confidence must request confidential treatment unless the information has already been granted such treatment during the proceedings. All such requests should be directed to the Secretary of the Commission and must include a full statement of the reasons why the Commission should grant such treatment. See § 201.6 of the Commission's rules of practice and procedure, 19 CFR § 201.6. Documents for which confidential treatment by the Commission is sought will be treated accordingly. All nonconfidential written submissions will be available for public inspection at the Office of the Secretary.
This action is taken under the authority of section 337 of the Tariff Act of 1930, 19 U.S.C. § 1337, and section 210.45 of the Commission's rules of practice and procedure, 19 CFR § 210.45.
Copies of the public version of the subject ID, and all other nonconfidential documents filed in connection with this investigation, are or will be available for inspection during official business hours (8:45 a.m. to 5:15 p.m.) in the Office of the Secretary, U.S. International Trade Commission, 500 E Street SW, Washington, DC 20436, telephone 202-205-2000.
United States International Trade Commission.
Scheduling of full five-year reviews concerning the antidumping duty orders on heavy forged handtools from China.
The Commission hereby gives notice of the scheduling of full reviews pursuant to section 751(c)(5) of the Tariff Act of 1930 (19 U.S.C. 1675(c)(5)) (the Act) to determine whether revocation of the antidumping duty orders on heavy forged handtools from China would be likely to lead to continuation or recurrence of material injury. For further information concerning the conduct of these reviews and rules of general application, consult the Commission's rules of practice and procedure, part 201, subparts A through E (19 CFR part 201), and part 207, subparts A, D, E, and F (19 CFR part 207). Recent amendments to the rules of practice and procedure pertinent to five-year reviews, including the text of subpart F of part 207, are published at 63 FR 30599, June 5, 1998, and may be downloaded from the Commission's World Wide Web site at http://www.usitc.gov/rules.htm.
February 3, 2000.
Olympia DeRosa Hand (202-205-3182), Office of Investigations, U.S.
On October 1, 1999, the Commission determined that responses to its notice of institution of the subject five-year reviews were such that full reviews pursuant to section 751(c)(5) of the Act should proceed (64 FR 55958, October 15, 1999). A record of the Commissioners' votes, the Commission's statement on adequacy, and any individual Commissioner's statements will be available from the Office of the Secretary and at the Commission's web site.
Persons, including industrial users of the subject merchandise and, if the merchandise is sold at the retail level, representative consumer organizations, wishing to participate in these reviews as parties must file an entry of appearance with the Secretary to the Commission, as provided in § 201.11 of the Commission's rules, by 45 days after publication of this notice. A party that filed a notice of appearance following publication of the Commission's notice of institution of the reviews need not file an additional notice of appearance. The Secretary will maintain a public service list containing the names and addresses of all persons, or their representatives, who are parties to the reviews.
Pursuant to § 207.7(a) of the Commission's rules, the Secretary will make BPI gathered in these reviews available to authorized applicants under the APO issued in the reviews, provided that the application is made by 45 days after publication of this notice. Authorized applicants must represent interested parties, as defined by 19 U.S.C. 1677(9), who are parties to the reviews. A party granted access to BPI following publication of the Commission's notice of institution of the reviews need not reapply for such access. A separate service list will be maintained by the Secretary for those parties authorized to receive BPI under the APO.
The prehearing staff report in the reviews will be placed in the nonpublic record on April 26, 2000, and a public version will be issued thereafter, pursuant to § 207.64 of the Commission's rules.
The Commission will hold a hearing in connection with the reviews beginning at 9:30 a.m. on May 16, 2000, at the U.S. International Trade Commission Building. Requests to appear at the hearing should be filed in writing with the Secretary to the Commission on or before May 8, 2000. A nonparty who has testimony that may aid the Commission's deliberations may request permission to present a short statement at the hearing. All parties and nonparties desiring to appear at the hearing and make oral presentations should attend a prehearing conference to be held at 9:30 a.m. on May 11, 2000, at the U.S. International Trade Commission Building. Oral testimony and written materials to be submitted at the public hearing are governed by §§ 201.6(b)(2), 201.13(f), 207.24, and 207.66 of the Commission's rules. Parties must submit any request to present a portion of their hearing testimony
Each party to the reviews may submit a prehearing brief to the Commission. Prehearing briefs must conform with the provisions of § 207.65 of the Commission's rules; the deadline for filing is May 5, 2000. Parties may also file written testimony in connection with their presentation at the hearing, as provided in § 207.24 of the Commission's rules, and posthearing briefs, which must conform with the provisions of section 207.67 of the Commission's rules. The deadline for filing posthearing briefs is May 25, 2000; witness testimony must be filed no later than three days before the hearing. In addition, any person who has not entered an appearance as a party to the reviews may submit a written statement of information pertinent to the subject of the reviews on or before May 25, 2000. On June 23, 2000, the Commission will make available to parties all information on which they have not had an opportunity to comment. Parties may submit final comments on this information on or before June 27, 2000, but such final comments must not contain new factual information and must otherwise comply with § 207.68 of the Commission's rules. All written submissions must conform with the provisions of § 201.8 of the Commission's rules; any submissions that contain BPI must also conform with the requirements of §§ 201.6, 207.3, and 207.7 of the Commission's rules. The Commission's rules do not authorize filing of submissions with the Secretary by facsimile or electronic means.
In accordance with §§ 201.16(c) and 207.3 of the Commission's rules, each document filed by a party to the reviews must be served on all other parties to the reviews (as identified by either the public or BPI service list), and a certificate of service must be timely filed. The Secretary will not accept a document for filing without a certificate of service.
These reviews are being conducted under authority of title VII of the Tariff Act of 1930; this notice is published pursuant to § 207.62 of the Commission's rules.
By order of the Commission.
United States International Trade Commission.
Scheduling of full five-year reviews concerning the antidumping duty orders on certain industrial belts from Germany, Italy, Japan, and Singapore.
The Commission hereby gives notice of the scheduling of full reviews pursuant to section 751(c)(5) of the Tariff Act of 1930 (19 U.S.C. 1675(c)(5)) (the Act) to determine whether revocation of the antidumping duty orders on certain industrial belts from Germany, Italy, Japan, and Singapore would be likely to lead to continuation or recurrence of material injury. For further information concerning the conduct of these reviews and rules of general application, consult the Commission's Rules of Practice and
February 3, 2000.
Joanna Bonarriva (202-708-4083), Office of Investigations, U.S. International Trade Commission, 500 E Street SW, Washington, DC 20436. Hearing-impaired persons can obtain information on this matter by contacting the Commission's TDD terminal on 202-205-1810. Persons with mobility impairments who will need special assistance in gaining access to the Commission should contact the Office of the Secretary at 202-205-2000. General information concerning the Commission may also be obtained by accessing its internet server (http://www.usitc.gov).
On September 3, 1999, the Commission determined that responses to its notice of institution of the subject five-year reviews were such that full reviews pursuant to section 751(c)(5) of the Act should proceed (64 FR 50106, September 15, 1999). A record of the Commissioners' votes, the Commission's statement on adequacy, and any individual Commissioner's statements will be available from the Office of the Secretary and at the Commission's web site.
Persons, including industrial users of the subject merchandise and, if the merchandise is sold at the retail level, representative consumer organizations, wishing to participate in these reviews as parties must file an entry of appearance with the Secretary to the Commission, as provided in § 201.11 of the Commission's rules, by 45 days after publication of this notice. A party that filed a notice of appearance following publication of the Commission's notice of institution of the reviews need not file an additional notice of appearance. The Secretary will maintain a public service list containing the names and addresses of all persons, or their representatives, who are parties to the reviews.
Pursuant to § 207.7(a) of the Commission's rules, the Secretary will make BPI gathered in these reviews available to authorized applicants under the APO issued in the reviews, provided that the application is made by 45 days after publication of this notice. Authorized applicants must represent interested parties, as defined by 19 U.S.C. 1677(9), who are parties to the reviews. A party granted access to BPI following publication of the Commission's notice of institution of the reviews need not reapply for such access. A separate service list will be maintained by the Secretary for those parties authorized to receive BPI under the APO.
The prehearing staff report in the reviews will be placed in the nonpublic record on June 7, 2000, and a public version will be issued thereafter, pursuant to § 207.64 of the Commission's rules.
The Commission will hold a hearing in connection with the reviews beginning at 9:30 a.m. on June 27, 2000, at the U.S. International Trade Commission Building. Requests to appear at the hearing should be filed in writing with the Secretary to the Commission on or before June 19, 2000. A nonparty who has testimony that may aid the Commission's deliberations may request permission to present a short statement at the hearing. All parties and nonparties desiring to appear at the hearing and make oral presentations should attend a prehearing conference to be held at 9:30 a.m. on June 23, 2000, at the U.S. International Trade Commission Building. Oral testimony and written materials to be submitted at the public hearing are governed by §§201.6(b)(2), 201.13(f), 207.24, and 207.66 of the Commission's rules. Parties must submit any request to present a portion of their hearing
Each party to the review may submit a prehearing brief to the Commission. Prehearing briefs must conform with the provisions of § 207.65 of the Commission's rules; the deadline for filing is June 16, 2000. Parties may also file written testimony in connection with their presentation at the hearing, as provided in § 207.24 of the Commission's rules, and posthearing briefs, which must conform with the provisions of § 207.67 of the Commission's rules. The deadline for filing posthearing briefs is July 7, 2000; witness testimony must be filed no later than three days before the hearing. In addition, any person who has not entered an appearance as a party to the reviews may submit a written statement of information pertinent to the subject of the reviews on or before July 7, 2000. On July 28, 2000, the Commission will make available to parties all information on which they have not had an opportunity to comment. Parties may submit final comments on this information on or before August 1, 2000, but such final comments must not contain new factual information and must otherwise comply with § 207.68 of the Commission's rules. All written submissions must conform with the provisions of § 201.8 of the Commission's rules; any submissions that contain BPI must also conform with the requirements of §§ 201.6, 207.3, and 207.7 of the Commission's rules. The Commission's rules do not authorize filing of submissions with the Secretary by facsimile or electronic means.
In accordance with §§ 201.16(c) and 207.3 of the Commission's rules, each document filed by a party to the reviews must be served on all other parties to the reviews (as identified by either the public or BPI service list), and a certificate of service must be timely filed. The Secretary will not accept a document for filing without a certificate of service.
These reviews are being conducted under authority of title VII of the Tariff Act of 1930; this notice is published pursuant to section 207.62 of the Commission's rules.
United States International Trade Commission.
Scheduling of full five-year reviews concerning the countervailing duty order and antidumping duty order on magnesium from Canada.
The Commission hereby gives notice of the scheduling of full reviews pursuant to section 751(c)(5) of the Tariff Act of 1930 (19 U.S.C. 1675(c)(5)) (the Act) to determine whether revocation of the countervailing duty and antidumping duty orders on magnesium from Canada would be likely to lead to continuation or recurrence of material injury within a reasonably foreseeable time. For further information concerning the conduct of these reviews and rules of general application, consult the Commission's Rules of Practice and Procedure, part 201, subparts A through E (19 CFR part 201), and part 207, subparts A, D, E, and F (19 CFR part 207). Recent amendments to the Rules of Practice and Procedure pertinent to five-year reviews, including the text of subpart F of part 207, are published at 63 FR 30599, June 5, 1998, and may be downloaded from the Commission's World Wide Web site at http://www.usitc.gov/rules.htm.
February 3, 2000.
Jeff Clark (202-205-3195), Office of Investigations, U.S. International Trade Commission, 500 E Street SW, Washington, DC 20436. Hearing-impaired persons can obtain information on this matter by contacting the Commission's TDD terminal on 202-205-1810. Persons with mobility impairments who will need special assistance in gaining access to the Commission should contact the Office of the Secretary at 202-205-2000. General information concerning the Commission may also be obtained by accessing its internet server (http://www.usitc.gov).
On November 4, 1999, the Commission determined that responses to its notice of institution of the subject five-year reviews were such that full reviews pursuant to section 751(c)(5) of the Act should proceed (64 FR 62690, November 17, 1999). A record of the Commissioners' votes, the Commission's statement on adequacy, and any individual Commissioner's statements are available from the Office of the Secretary and at the Commission's web site.
Persons, including industrial users of the subject merchandise and, if the merchandise is sold at the retail level, representative consumer organizations, wishing to participate in these reviews as parties must file an entry of appearance with the Secretary to the Commission, as provided in § 201.11 of the Commission's rules, by 45 days after publication of this notice. A party that filed a notice of appearance following publication of the Commission's notice of institution of the reviews need not file an additional notice of appearance. The Secretary will maintain a public service list containing the names and addresses of all persons, or their representatives, who are parties to the reviews.
Pursuant to § 207.7(a) of the Commission's rules, the Secretary will make BPI gathered in these reviews available to authorized applicants under the APO issued in the reviews, provided that the application is made by 45 days after publication of this notice. Authorized applicants must represent interested parties, as defined by 19 U.S.C. § 1677(9), who are parties to the reviews. A party granted access to BPI following publication of the Commission's notice of institution of the reviews need not reapply for such access. A separate service list will be maintained by the Secretary for those parties authorized to receive BPI under the APO.
The prehearing staff report in the reviews will be placed in the nonpublic record on April 28, 2000, and a public version will be issued thereafter, pursuant to § 207.64 of the Commission's rules.
The Commission will hold a hearing in connection with the reviews beginning at 9:30 a.m. on May 31, 2000, at the U.S. International Trade Commission Building. Requests to appear at the hearing should be filed in writing with the Secretary to the Commission on or before May 23, 2000. A nonparty who has testimony that may aid the Commission's deliberations may request permission to present a short statement at the hearing. All parties and nonparties desiring to appear at the hearing and make oral presentations should attend a prehearing conference to be held at 9:30 a.m. on May 26, 2000, at the U.S. International Trade Commission Building. Oral testimony and written materials to be submitted at the public hearing are governed by § 201.6(b)(2), 201.13(f), 207.24, and 207.66 of the Commission's rules. Parties must submit any request to present a portion of their hearing testimony
Each party to the reviews may submit a prehearing brief to the Commission. Prehearing briefs must conform with the provisions of § 207.65 of the Commission's rules; the deadline for filing is May 16, 2000. Parties may also file written testimony in connection with their presentation at the hearing, as provided in § 207.24 of the Commission's rules, and posthearing briefs, which must conform with the provisions of § 207.67 of the Commission's rules. The deadline for filing posthearing briefs is June 9, 2000; witness testimony must be filed no later than three days before the hearing. In addition, any person who has not entered an appearance as a party to the reviews may submit a written statement of information pertinent to the subject of the reviews on or before June 9, 2000. On July 3, 2000, the Commission will make available to parties all information on which they have not had an opportunity to comment. Parties may submit final comments on this information on or before July 6, 2000, but such final comments must not contain new factual information and must otherwise comply with § 207.68 of the Commission's rules. All written submissions must conform with the provisions of § 201.8 of the Commission's rules; any submissions that contain BPI must also conform with the requirements of § 201.6, 207.3, and 207.7 of the Commission's rules. The Commission's rules do not authorize filing of submissions with the Secretary by facsimile or electronic means.
In accordance with § 201.16(c) and 207.3 of the Commission's rules, each document filed by a party to the reviews must be served on all other parties to the reviews (as identified by either the public or BPI service list), and a certificate of service must be timely filed. The Secretary will not accept a document for filing without a certificate of service.
These reviews are being conducted under authority of title VII of the Tariff Act of 1930; this notice is published pursuant to § 207.62 of the Commission's rules.
In accordance with 28 CFR 50.7, 38 FR 19029, notice is hereby given that on January 25, 2000, a proposed consent decree with respect to defendants Harry Grant and Sandalwood Construction Company in
The consent decree provides that the defendants Harry Grant and Sandalwood Construction Company shall pay a civil penalty of $60,000. The consent decree also provides,
The Department of Justice will receive comments relating to the proposed consent decree for a period of thirty (30) days from the date of this publication. Comments should be addressed to the Assistant Attorney General, Environment and Natural Resources Division, Department of Justice, Washington, DC 20530, and should refer to
The proposed consent decree may be examined at the office of the United States Attorney, 970 Broad St., Room 502, Newark, NJ 07102 and at the Region II office of the Environmental Protection Agency, 290 Broadway, New York, New York 10007. A copy of the proposed consent decree may also be obtained by mail from the Department of Justice Consent Decree Library, PO Box 7611, Washington, DC 20044. In requesting a copy, please enclose a check (there is a 25 cent per page reproduction cost) in the amount of $4.25 payable to the “Consent Decree Library.”
In accordance with Departmental Policy, 28 CFR 50.7, 38 FR 19029, and 42 U.S.C. 9622(d), notice is hereby given that a proposed Consent Decree in
Under the proposed consent decree, Cornell will cash out its liability for the Site, subjects to reopeners, by paying to the United States the sum of $30,000 in partial reimbursement of EPA's past response costs and paying $335,500 toward future operable unit 3 (“OU3”) Site costs to the responsible parties who are performing OU3 under an earlier consent decree. In exchange for the work and payment of response costs, Defendants will receive a covenant not to sue for response actions at the Site subject to certain reservations of rights.
The Department of Justice will receive, for a period of thirty (30) days from the date of this publication, written comments relating to the proposed Consent Decree. Comments should be addressed to the Assistant Attorney General for the Environment and Natural Resources Division, Department of Justice, Washington, D.C. 20530, and should refer to
The proposed Consent Decree may be examined at the Office of the United States Attorney, Northern District of New York, James Foley U.S. Courthouse, 445 Broadway, Room 231, Albany, New York 12207; and at the Region II Office of the U.S. Environmental Protection Agency, 290 Broadway, New York, New York 10278. Copies of the Consent Decree may be obtained by mail from the consent Decree Library, United States Department of Justice, PO Box 7611 Ben Franklin Station, Washington, DC 20044, (202) 514-1547. In requesting a copy, please enclose a check in the amount of $5.25 (25 cents per page reproduction costs) payable to the Consent Decree Library.
Notice is hereby given that on January 18, 2000, a proposed settlement agreement (“Settlement Agreement”) in
The Settlement Agreement provides for a payment, under the conditions specified in the Agreement, to Leach in the amount of up to $ 1.5 million from the proceeds of the sale of the portion of the Raymark Site owned by Raymark Industries, Inc.
The proposed Settlement Agreement may be examined at the office of the United States Attorney for the District of Connecticut, 915 Lafayette Blvd., Room 309, Bridgeport, Ct. 06604; and at the Region I office of the Environmental Protection Agency, 1 Congress St., Boston, Mass. 02114-2023. A copy of the proposed Settlement Agreement may also be obtained by mail from the Consent Decree Library, PO Box 7611,
Notice is hereby given that, on August 19, 1999, pursuant to Section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
No other changes have been made in either the membership or planned activity of the joint venture. Membership in this joint venture remains open, and Digital Imaging Group, Inc. intends to file additional written notification disclosing all changes in membership.
On September 25, 1997, Digital Imaging Group, Inc. filed its original notification pursuant to Section 6(a) of the Act. The Department of Justice published a notice in the
The last notification was filed with the Department on June 10 1999. A notice has not yet been published in the
Notice is hereby given that, on August 23, 1999, pursuant to section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
No other changes have been made in either the membership or planned activity of the group research project. Membership in this group research project remains open, and OBI Consortium, Inc. intends to file additional written notification disclosing all changes in membership.
On Saturday 10, 1997, OBI Consortium, Inc. filed its original notification pursuant to section 6(a) of the Act. The Department of Justice published a notice in the
The last notification was filed with the Department on May 27, 1999. A notice has not yet been published in the
Notice is hereby given that, on July 17, 1999, pursuant to section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
Notice is hereby given that, on August 12, 1999, pursuant to section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
No other changes have been made in either the membership or planned activity of the group research project. Membership in this group research project remains open, and Salutation Consortium, Inc. intends to file additional written notification disclosing all changes in membership.
On March 30, 1995, Salutation Consortium, Inc. filed its original notification pursuant to section 6(a) of the Act. The Department of Justice published a notice in the
The last notification was filed with the Department on May 6, 1999. A notice has not been published in the
Notice is hereby given that, on April 5, 1999, pursuant to section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
No other changes have been made in either the membership or planned activity of the group research project. Membership in this group research project remains open, and Southwest Research Institute (“SwRI”)—Durability and Life Assessment of GTD-111 Buckets intends to file additional written notification disclosing all changes in membership.
On October 31, 1995, Southwest Research Institute (“SwRI”)—Durability and Life Assessment of GTD-111 Buckets filed its original notification pursuant to Section 6(a) of the Act. The Department of Justice published a notice in the
The last notification was filed with the Department on October 21, 1998. A notice was published in the
Notice is hereby given that, on August 19, 1999, pursuant to Section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
No other changes have been made in either the membership or planned activity of the group research project. Membership in this group research project remains open, and Telematics Suppliers Consortium, Inc. (“Telematics”) intends to file additional written notification disclosing all changes in membership.
On March 12, 1999, Telematics Suppliers Consortium, Inc. (“Telematics”) filed its original notification pursuant to Section 6(a) of the Act. The last notification was filed with the Department on May 26, 1999. A notice was published in the
Notice is hereby given that, on July 20, 1999, pursuant to section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
Notice is hereby given that, on April 20, 1999, pursuant to section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301
No other changes have been made in either the membership or planned activity of the group research project. Membership in this group research project remains open, and VSI Alliance intends to file additional written notification disclosing all changes in membership.
On November 29, 1996, VSI Alliance filed its original notification pursuant to Section 6(a) of the Act. The Department of Justice published a notice in the
The last notification was filed with the Department on February 11, 1999. A notice has not yet been published in the
By Notice dated October 8, 1999, and published in the
The firm will manufacture propiram in the process of manufacturing other targeted test compounds for another firm.
DEA has considered the factors in Title 21, United States Code, Section 823(a) and determined that the registration of Cedarburg Laboratories, Inc. to manufacture propiram is consistent with the public interest at this time. DEA has investigated the company to ensure that the company's registration is coninspection and testing of the company's physical security systems, verification of the company's compliance with state and local laws, and a review of the company's background and history. Therefore, pursuant to 21 U.S.C. 823 and 28 CFR 0.100 and 0.104, the Deputy Assistant Administrator, Office of Diversion Control, hereby orders that the application submitted by the above firm for registration as a bulk manufacturer of the basic class of controlled substance listed above is granted.
By Notice dated October 1, 1999, and published in the
The firm plans to bulk manufacture methamphetamine to produce products for distribution to its customers.
DEA has considered the factors in Title 21, United States Code, Section 823(a) and determined that the registration of Chattem Chemicals, Inc. to manufacture methamphetamine is consistent with the public interest at this time. DEA has investigated the firm on a regular basis to ensure that the company's continued registration is consistent with the public interest. These investigations have included inspection and testing of the company's physical security systems, verification of the company's compliance with state and local laws, and a review of the company's background and history. Therefore, pursuant to 21 U.S.C. 823 and 28 CFR § 0.100 and 0.104, the Deputy Assistant Administrator, Office of Diversion Control, hereby orders that the application submitted by the above firm for registration as a bulk manufacturer of the basic class of controlled substance listed above is granted.
By Notice dated October 8, 1999, and published in the
The firm plans to import the phenylacetone for the manufacture of amphetamine.
No comments or objections have been received. DEA has considered the factors in Title 21, United States Code, Section 823(a) and 952(a), and determined that the registration of Chirex Technology Center, Inc., DBA Chirex Cauldron to import phenylacetone is consistent with the public interest and with United States obligations under international treaties, conventions, or protocols in effect on May 1, 1971, at this time. DEA has investigated the company to ensure that the company's registration is consistent with the public interest. This investigation included inspection and testing of the company's physical security systems, verification of the company's compliance with state and local laws, and a review of the company's background and history. Therefore, pursuant to Section 1008(a) of the Controlled Substances Import and Export Act and in accordance with Title 21, Code of Federal Regulations, Section 1301.34, the above firm is granted registration as an importer of the basic class of controlled substance listed above.
Pursuant to § 1301.33(a) of Title 21 of the Code of Federal Regulations (CFR), this is notice that on November 29, 1999, Ganes Chemicals Inc., Industrial Park Road, Pennsville, New Jersey 08070, made application by renewal to the Drug Enforcement Administration (DEA) for registration as a bulk manufacturer of the basic classes of controlled substances listed below:
The firm plans to manufacture the controlled substances for distribution as bulk products to its customers.
Any other such applicant and any person who is presently registered with DEA to manufacture such substance may file comments or objections to the issuance of the proposed registration.
Any such comments or objections may be addressed, in quintuplicate, to the Deputy Assistant Administrator, Office of Diversion Control, Drug Enforcement Administration, United States Department of Justice, Washington, DC 20537, Attention: DEA Federal Register Representative (CCR), and must be filed no later than April 10, 2000.
Pursuant to § 1301.33(a) of Title 21 of the Code of Federal Regulations (CFR), this is notice that on October 24, 1999, High Standard Products, 1100 W. Florence Avenue, #B, Inglewood, California 90301, made application by renewal to the Drug Enforcement Administration (DEA) for registration as a bulk manufacturer of the basic classes of controlled substances listed below:
The firm plans to manufacture analytical reference standards.
Any other such applicant and any person who is presently registered with DEA to manufacture such substances may file comments or objections to the issuance of the proposed registration.
Any such comments or objections may be addressed, in quintuplicate, to the Deputy Assistant Administrator, Office of Diversion Control, Drug Enforcement Administration, United States Department of Justice, Washington, DC 20537, Attention: DEA Federal Register Representative (CCR), and must be filed no later than April 10, 2000.
By Notice dated October 1, 1999, and published in the
The firm plans to manufacture methylphenidate for demonstration purposes and for dosage form development and stability studies.
DEA has considered the factors in Title 21, United States Code, Section
By Notice dated October 8, 1999, and published in the
The firms plans to use gram quantities of the listed controlled substances to manufacture drug abuse test kits.
DEA has considered the factors in Title 21, United States Code, Section 823(a) and determined that the registration of LifePoint, Inc. to manufacture the listed controlled substances is consistent with the public interest at this time. DEA has investigated the firm on a regular basis to ensure that the company's continued registration is consistent with the public interest. These investigations have included inspection and testing of the company's physical security systems, audits of the company's records, verification of the company's compliance with state and local laws, and a review of the company's background and history. Therefore, pursuant to 21 U.S.C. 823 and 28 CFR 0.100 and 0.104, the Deputy Assistant Administrator, Office of Diversion Control, hereby orders that the application submitted by the above firm for registration as a bulk manufacturer of the basic classes of controlled substances listed above is granted.
Drug Enforcement Administration (DEA), Justice.
Notice of aggregate production quotas for 2000.
This notice establishes initial 2000 aggregate production quotas for controlled substances in Schedules I and II of the Controlled Substances Act (CSA). This notice replaces and supersedes the final order dated December 21, 1999 and published in the
February 10, 2000.
Frank L. Sapienza, Chief, Drug and Chemical Evaluation Section, Drug Enforcement Administration, Washington, DC 20537, Telephone: (202) 307-7183.
Section 306 of the CSA (21 U.S.C. 826) requires that the Attorney General establish aggregate production quotas for each basic class of controlled substance listed in Schedules I and II. This responsibility has been delegated to the Administrator of the DEA by § 0.100 of Title 28 of the Code of Federal Regulations. The Administrator, in turn, has redelegated this function to the Deputy Administrator, pursuant to § 0.104 of Title 28 of the Code of Federal Regulations.
The 2000 aggregate production quotas represent those quantities of controlled substances that may be produced in the United States in 2000 to provide adequate supplies of each substance for: The estimated medical, scientific, research and industrial needs of the United States; lawful export requirements; and the establishment and maintenance of reserve stocks (21 U.S.C. 826(a) and 21 CFR 1303.11). These quotas do not include imports of controlled substances for use in industrial processes.
On October 21, 1999, a notice of the proposed initial 2000 aggregate production quotas for certain controlled substances in Schedules I and II was published in the
Six companies commented on a total of 16 Schedules I and II controlled substances within the published comment period. The companies commented that the proposed aggregate production quotas for alfentanial, amphetamine, diphenoxylate, fentanyl, hydromorphone, levorphanol, meperidine, levo-desoxyephedrine, methamphetamine (for sale), methamphetamine (for conversion), methylphenidate, noroxymorphone (for conversion), oxycodone (for sale), oxycodone (for conversion), sufentanil and thebaine were insufficient to provide for the estimated medical, scientific, research and industrial needs of the United States, for export requirements and for the establishment and maintenance of reserve stocks.
In addition, one comment was received after the published comment
DEA has taken into consideration the above comments along with the relevant 1999 manufacturing quotas, current 1999 sales and inventories, 2000 export requirements and research and product development requirements. Based on this information, the DEA has adjusted the initial aggregate production quotas for alfentanil, dihydromorphine, diphenoxylate, fentanyl, hydromorphone, levorphanol, meperidine, levo-desoxyephedrine, methaphetamine (for conversion), noroxymorphone (for conversion), osycodone (for sale), sufentanil and thebaine to meet the legitimate needs of the United States. Significant portions of the increases for alfentanil, diphenoxylate, fentanyl, hydromorphone, levorphanol, noroxymorphone (for conversion) and sufentanil are due to a change in the manner in which manufacturing losses are accounted for by a bulk manufacturer.
In addition, one company requested a hearing to address the aggregate production quota for oxycodone (for sale) or hydromorphone if the aggregate production quotas were not increased sufficiently. The DEA, based on the data provided, has increased the aggregate production quotas for both oxycodone (for sale) and hydromorphone and has determined that a hearing is not necessary.
Regarding amphetamine, methamphetamine (for sale), methylphenidate and oxycodone (for conversion), the DEA has determined that the proposed initial 2000 aggregate production quotas are sufficient to meet the current 2000 estimated medical, scientific, research and industrial needs of the United States.
Pursuant to Section 1303 of Title 21 of the Code of Federal Regulations, the Deputy Administrator of the DEA will, in early 2000, adjust aggregate production quotas and individual manufacturing quotas allocated for the year based upon 1999 year-end inventory and actual 1999 disposition data supplied by quota recipients for each basic class of Schedules I or II controlled substance.
Therefore, under the authority vested in the Attorney General by Section 306 of the Controlled Substances Act of 1970 (21 U.S.C. 826), delegated to the Administrator of the DEA by § 0.100 of Title 28 of the Code of Federal Regulations, and redelegated to the Deputy Administrator pursuant to § 0.104 of Title 28 of the Code of Federal Regulations, the Deputy Administrator hereby orders that the 2000 initial aggregate production quotas for the following controlled substances, expressed in grams of anhydrous acid or base, be established as follows:
The Deputy Administrator further orders that aggregate production quotas for all other Schedules I and II controlled substances included in §§ 1308.11 and 1308.12 of Title 21 of the Code of Federal Regulations be established at zero.
The Office of Management and Budget has determined that notices of aggregate production quotas are not subject to centralized review under Executive Order 12866. This action has been analyzed in accordance with the principles and criteria contained in Executive order 12612, and it has been determined that this matter does not have sufficient federalism implications to warrant the preparation of a Federalism Assessment.
The Deputy Administrator hereby certifies that this action will have no significant impact upon small entities whose interests must be considered under the Regulatory Flexibility Act, 5 U.S.C. 601
(Closing this meeting is taken in accordance with the exemption provided under Title 45, CFR, Part 1703.202(a)(9)), Los Angeles Times Building, 145 South Spring Street, Los Angeles, CA.
The National Award for Library Service.
The time of the closed meeting on February 17, 2000 has been extended.
The meeting will be closed from 8:30 to 11:30 a.m.
For additional information, see Sunshine Meeting Notice published 01/25/00 @ 65 FR 3980.
National Council on Disability (NCD).
This notice announces the establishment of NCD's Youth Advisory Committee.
Mark S. Quigley, Public Affairs Specialist, National Council on Disability, 1331 F Street NW, Suite 1050, Washington, DC 20004-1107; 202-272-2004 (voice), 202-272-2074 (TTY), 202-272-2022 (fax), mquigley@ncd.gov (e-mail).
The National Council on Disability is an independent federal agency composed of 15 members appointed by the President of the United States and confirmed by the U.S. Senate. Its overall purpose is to promote policies, programs, practices, and procedures that guarantee equal opportunity for all people with disabilities, regardless of the nature of severity of the disability; and to empower people with disabilities to achieve economic self-sufficiency, independent living, and inclusion and integration into all aspects of society.
The purpose of NCD's Youth Advisory Committee is to provide input into NCD activities consistent with the values and goals of the Americans with Disabilities Act.
This committee is necessary to provide advice and recommendations to NCD on disability issues.
We are seeking a balanced, culturally diverse membership representing a variety of disabling conditions and from across the United States. One member will be chosen from each of the 10 federal regions.
Region I states include Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont.
Region II states include New Jersey, New York, Puerto Rico, and the Virgin Islands.
Region III states include Delaware, District of Columbia, Maryland, Pennsylvania, Virginia, and West Virginia.
Region IV states include Alabama, Florida, Georgia, Kentucky, Mississippi, North Carolina, South Carolina, and Tennessee.
Region V states include Illinois, Indiana, Michigan, Minnesota, Ohio, and Wisconsin.
Region VI states include Arkansas, Louisiana, New Mexico, Oklahoma, and Texas.
Region VII states include Iowa, Kansas, Missouri, and Nebraska.
Region VIII states include Colorado, Montana, North Dakota, South Dakota, Utah, and Wyoming.
Region IX states include Arizona, California, Guam, Hawaii, and Nevada.
Region X states include Alaska, Idaho, Oregon, and Washington.
National Credit Union Administration (NCUA).
New Collection of Information.
The NCUA intends to submit the following information collection to the Office of Management and Budget (OMB) for review and clearance under the Paperwork Reduction Act of 1995 (Public Law 104-13, 44 U.S.C. Chapter 35). This information collection is published to obtain comments from the public. It was originally published on
Comments will be accepted until March 13, 2000.
Interested parties are invited to submit written comments to NCUA Clearance Officer or OMB Reviewer listed below:
Clearance Officer: Mr. James L. Baylen (703) 518-6411, National Credit Union Administration, 1775 Duke Street, Alexandria, Virginia 22314-3428, Fax No. 703-518-6433, E-mail: jbaylen@ncua.gov.
OMB Reviewer: Alexander T. Hunt (202) 395-7860, Office of Management and Budget, Room 10226, New Executive Office Building, Washington, DC 20503.
Copies of the information collection requests, with applicable supporting documentation, may be obtained by calling the NCUA Clearance Officer, James L. Baylen, (703) 518-6411.
Proposal for the following collection of information:
By the National Credit Union Administration Board on February 3, 2000.
The U.S. Nuclear Regulatory Commission (the Commission) has granted the request of Consumers Energy Company (the licensee) to withdraw its November 9, 1998, application for proposed amendment to Facility Operating License No. DPR-20 for the Palisades Plant, located in Covert, Michigan.
The proposed amendment would have revised the Technical Specifications by deleting the chemical and volume control system (CVCS) operability and surveillance requirements, which the licensee had incorporated into the facility's Operating Requirements Manual (ORM). In its letter of January 13, 2000, the licensee stated that the proposed amendment was no longer needed because (1) the CVCS repairs anticipated at the time of the application for amendment were completed during a subsequent forced outage, and (2) the NRC's subsequent approval of the Improved Technical Specifications (Amendment 189, dated November 30, 1999) deleted the CVCS requirements that the licensee had incorporated into the ORM.
The Commission had previously issued a Notice of Consideration of Issuance of Amendment published in the
For further details with respect to this action, see the application for amendment dated November 9, 1998, and the licensee's letter dated January 13, 2000, which withdrew the application for license amendment. The above documents are available for public inspection at the Commission's Public Document Room, the Gelman Building, 2120 L Street, NW., Washington, DC, and accessible electronically through the ADAMS Public Electronic Reading Room link at the NRC Web site (http://www.nrc.gov).
For the Nuclear Regulatory Commission.
Pursuant to the authority contained in 10 CFR §§ 2.721 and 2.1207, the Presiding Officer in the captioned 10 CFR Part 2, Subpart L proceeding is hereby replaced by appointing Administrative Judge Thomas S. Moore as Presiding Officer in place of Administrative Judge Peter B. Bloch.
All correspondence, documents and other material shall be filed with the Presiding Officer in accordance with 10 CFR § 2.1203 (1997). The address of the new Presiding Officer is: Administrative Judge Thomas S. Moore, Atomic Safety and Licensing Board Panel, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
This Board reconstitution order is issued pursuant to the authority of the Chief Administrative Judge of the Atomic Safety and Licensing Board Panel.
Indiana Michigan Power Company (IM or the licensee) is the holder of Facility Operating License Nos. DPR-58, and DPR-74 issued by the Nuclear Regulatory Commission (NRC or Commission) pursuant to 10 CFR Part
As a result of the accident at Three Mile Island, Unit 2 (TMI-2), the NRC issued NUREG-0737, “Clarification of TMI Action Plan Requirements,” in November 1980. Generic Letters 82-05 and 82-10, issued on March 17 and May 5, 1982, respectively, requested licensees of operating power reactors to furnish information pertaining to their implementation of specific TMI Action Plan items described in NUREG-0737. Orders were issued to licensees confirming their commitments made in response to the generic letters. The Confirmatory Order that was issued to IM on March 14, 1983, required the licensee to implement and maintain the various TMI Action Plan Items, including Item II.F.1, Attachment 6 pertaining to monitoring of the hydrogen concentration in the containment following a safety injection.
Significant improvements have been achieved since the TMI accident in the areas of understanding risks associated with nuclear plant operations and developing better strategies for managing the response to potential severe accidents at nuclear power plants. Recent insights pertaining to plant risks and severe accident assessment tools have led the NRC staff to conclude that some TMI Action Plan items can be revised without reducing, and perhaps enhancing, the ability of licensees to respond to severe accidents. The NRC's efforts to understand the risks associated with commercial nuclear power plant operations more effectively and to reduce unnecessary regulatory burden on licensees and the public have prompted the NRC's decision to revise the post-TMI requirement to monitor containment hydrogen concentration.
The Confirmatory Order of March 14, 1983, imposed requirements upon the licensee to have continuous monitoring of containment hydrogen concentration provided in the control room, as described by TMI Action Plan Item II.F.1, Attachment 6. Information about hydrogen concentration supports the licensee's assessments of the degree of core damage and whether a threat to the integrity of the containment may be posed by hydrogen gas combustion. TMI Action Item II.F.1, Attachment 6, states:
If an indication is not available at all times, continuous indication and recording shall be functioning within 30 minutes of the initiation of safety injection.
This requirement to have monitoring of the hydrogen concentration in the containment within 30 minutes following the start of safety injection has defined both design and operating characteristics for hydrogen monitoring systems at nuclear power plants since the implementation of NUREG-0737. In addition, the technical specifications of most nuclear power plants and NRC regulation 10 CFR 50.44, “Standards for combustible gas control system in light-water-cooled power reactors,” require availability of hydrogen monitors.
By letter dated December 22, 1999, IM used the Oconee and Arkansas Nuclear One confirmatory orders of November 29, 1999, and September 28, 1998, respectively, as guidance to request relief for the two CNP units from the requirement to have indication of hydrogen concentration in the containment within 30 minutes of the initiation of safety injection. Specifically, the licensee requested that risk-informed insights be used to determine the functional requirements for monitoring of containment hydrogen concentration that would allow extending the monitoring requirement to more than 30 minutes following initiation of safety injection. The basis for this request was that the additional time would allow the operators to complete their initial accident assessment and mitigation duties before redirecting their attention to the relatively longer-term recovery actions, such as actuating the hydrogen recombiners, that are not needed for at least 24 hours.
Based on the staff's evaluation of the justification provided by the licensee, and improved understanding of insights pertaining to plant risks, severe accident assessment, and emergency planning since the TMI-2 accident, the staff has concluded that the licensee's request should be approved. Giving the licensee the flexibility and responsibility for determining the appropriate time limit for establishing monitoring of containment hydrogen concentration will preclude control room personnel from being distracted from various important tasks in the early phases of accident mitigation, while allowing cognizant personnel, mostly outside the control room, to be aware of hydrogen concentration based on a risk-informed functional assessment at a reasonable time following an accident. Because the appropriate balance between control room activities and longer-term management of the response to severe accidents can best be determined by the licensee, the NRC staff has determined that the licensee may elect to adopt a risk-informed functional requirement in lieu of the current 30-minute time limit for establishing monitoring of the hydrogen concentration as imposed by the Order dated March 14, 1983, and as described by TMI Action Item II.F.1, Attachment 6, in NUREG-0737. The appropriate functional requirement is as follows:
Procedures shall be established for ensuring that monitoring of hydrogen concentration in the containment atmosphere is available in a sufficiently timely manner to support the implementation of the Donald C. Cook Nuclear Plant Emergency Plan (and related procedures) and related activities such as guidance for severe accident management. Hydrogen monitoring will be initiated based on: (1) the appropriate priority for establishing monitoring of hydrogen concentration within the containment in relation to other activities in the control room, (2) the use of the monitoring of hydrogen concentration by decision makers for severe accident management and emergency response, and (3) insights from experience or evaluation pertaining to possible scenarios that result in significant generation of hydrogen that would be indicative of core damage or a potential threat to the integrity of the containment building. Affected licensing basis documents and other related documents will be appropriately revised and/or updated in accordance with applicable NRC regulations.
The licensee's Post Accident Monitoring Instrumentation Technical Specifications and 10 CFR 50.44 require the licensee to maintain the ability to monitor hydrogen concentration in the containment. However, the details pertaining to design and manner of operation of the hydrogen monitoring system are determined by the licensee.
Accordingly, pursuant to Sections 103, 104b, 161b, 161i, 161o, 182, and 186 of the Atomic Energy Act of 1954, as amended, and the Commission's regulations in 10 CFR 2.202 and 10 CFR Part 50, IT IS HEREBY ORDERED that:
NRC License Nos. DPR-58 and DPR-74 are modified as follows:
The licensee may elect to either maintain the 30-minute time limit for monitoring of hydrogen in the containment, as described by TMI Action Plan Item II.F.1, Attachment 6, in NUREG-0737 and required by the Confirmatory Order of March 14, 1983, or modify the time limit in the manner specified in Section II of this Order.
The Director, Office of Nuclear Reactor Regulation, may, in writing, relax or rescind any of the above conditions upon demonstration by the licensee of good cause.
Any person adversely affected by this Confirmatory Order, other than the licensee, may request a hearing within
If the hearing is requested by a person whose interest is adversely affected, the Commission will issue an Order designating the time and place of any hearing. If a hearing is held, the issue to be considered at such hearing will be whether this Confirmatory Order should be sustained.
In the absence of any request for hearing, or written approval of an extension of time in which to request a hearing, the provisions specified in Section IV above will be final 20 days from the date of this Order without further order or proceedings. If an extension of time for requesting a hearing has been approved, the provisions specified in Section IV will be final when the extension expires if a hearing request has not been received.
For the Nuclear Regulatory Commission.
Northeast Nuclear Energy Company is authorized to act as agent for the joint owners of the Millstone Nuclear Power Station, Unit 3 (Millstone 3), and has exclusive responsibility and control over the physical construction, operation, and maintenance of the facility as reflected in Facility Operating License No. NPF-49. Central Maine Power Company (Central Maine), one of the joint owners, holds a 2.5-percent possessory interest in Millstone 3. The U.S. Nuclear Regulatory Commission (NRC) issued Facility Operating License No. NPF-49 on January 31, 1986, pursuant to Part 50 of Title 10 of the Code of Federal Regulations (10 CFR Part 50). The facility is located in New London County, on the southern coast of the State of Connecticut.
By letter dated October 6, 1999, through counsel, Central Maine informed the NRC of a proposed merger involving the acquisition of Central Maine's parent, CMP Group, Inc. (CMP), by Energy East Corporation (Energy East). Central Maine requested that the NRC determine that the proposed merger and acquisition would not, in fact, constitute a transfer of Facility Operating License NPF-49 for Millstone 3, to the extent held by Central Maine in regard to Central Maine's 2.5-percent ownership interest in Millstone 3. Central Maine also requested if the NRC does find that the proposed acquisition of CMP would constitute an indirect transfer of Facility Operating License NPF-49 to the extent it is held by Central Maine, that the NRC consent to the indirect transfer of Central Maine's license to Energy East. The NRC determined that an indirect transfer of the license, to the extent that it is held by Central Maine, would be involved and that approval pursuant to 10 CFR 50.80 would be required. The NRC informed Central Maine of this decision in a letter dated November 15, 1999.
Central Maine is an electric utility primarily engaged in the transmission, sale, and distribution of electricity in the State of Maine and is incorporated in Maine. CMP holds all the common stock of Central Maine and also is incorporated in the State of Maine. Energy East is an investor-owned holding company incorporated in New York. Through its subsidiaries, Energy East is an energy delivery, products, and services company with operations in New York and several other northeastern States.
According to Central Maine's October 6, 1999, submittal (the “application”), on June 14, 1999, CMP and Energy East signed a definitive merger agreement for the acquisition of CMP by Energy East. To accomplish the acquisition, EE Merger Corporation, a Maine corporation that is a wholly owned subsidiary of Energy East, will merge with and into CMP, with CMP being the surviving corporation. Upon completion of the merger, CMP will become a wholly owned subsidiary of Energy East, with Energy East acquiring all of CMP's common stock. CMP will continue its corporate existence under the laws of the State of Maine, and CMP will continue to own all of Central Maine's common stock. The application notes, however, that in the event that the Securities and Exchange Commission does not permit Energy East to maintain CMP as an intermediate holding company, Energy East plans to hold Central Maine directly.
Whether Central Maine becomes directly or indirectly held by Energy East, Central Maine will continue to hold and to be the licensee for its 2.5-percent ownership interest in Millstone 3. In the case of either direct or indirect ownership by Energy East, an indirect transfer of the license to the extent it is held by Central Maine will occur as a result of the merger.
Approval of the indirect license transfer was requested pursuant to 10 CFR 50.80. Notice of the application for approval and an opportunity for a hearing was published in the
Under 10 CFR 50.80, no license, or any right thereunder, shall be transferred, directly or indirectly, through transfer of control of the license, unless the Commission shall give its consent in writing. Upon review of the information in the application and other information before the Commission, the NRC staff has determined that the subject merger will not affect the qualifications of Central Maine to hold the Millstone 3 license to the extent currently held, and that the indirect transfer of the license, to the extent effected by the proposed merger,
Accordingly, pursuant to Sections 161b, 161i, 161o, and 184 of the AEA, as amended, 42 USC §§ 2201(b), 2201(i), 2201(o), and 2234; and 10 CFR 50.80, IT IS HEREBY ORDERED that the license transfer referenced above is approved, subject to the following conditions:
(1) Central Maine shall provide the Director of the Office of Nuclear Reactor Regulation a copy of any application, at the time it is filed, to transfer (excluding grants of security interests or liens) from Central Maine to its current or proposed direct or indirect parent or to any other affiliated company, facilities for the production, transmission, or distribution of electric energy having a depreciated book value exceeding 10 percent (10%) of Central Maine's consolidated net utility plant, as recorded on Central Maine's books of account.
The foregoing condition shall supersede Condition (1) of the Order dated June 2, 1998, which approved the application regarding the restructuring of Central Maine by establishment of a holding company.
(2) Should the proposed merger of CMP and Energy East not be completed by January 30, 2001, this Order shall become null and void, provided, however, on application and for good cause shown, such date may be extended.
This Order is effective upon issuance.
For further details with respect to this Order, see the application dated October 6, 1999, which is available for public inspection at the Commission's Public Document Room, the Gelman Building, 2120 L Street, NW., Washington, DC, and accessible electronically through the ADAMS Public Electronic Reading Room link at the NRC Web site
For the Nuclear Regulatory Commission.
The U.S. Nuclear Regulatory Commission (the Commission) is considering the issuance of an order under 10 CFR 50.80 approving the transfer of Facility Operating License No. DPR-22 for the Monticello Nuclear Generating Plant currently held by Northern States Power Company (NSP) as owner and licensed operator of Monticello. The transfer would be to a newly formed company (referred to herein as “New NSP”). The Commission is also considering amending the license for administrative purposes to reflect the proposed transfer.
By application dated October 29, 1999, the Commission was informed that NSP entered into an agreement on March 24, 1999, to merge with New Century Energies, Inc. (NCE). Under the agreement, NCE will be merged with and into NSP, which will be renamed Xcel Energy, Inc. (Xcel). At the time of the merger, NSP will transfer all of its existing electric and natural gas utility facilities and responsibility and control over operations to New NSP, which will be a wholly owned subsidiary of Xcel. New NSP would assume title to the facilities following approval of the proposed license transfer, and would become responsible for the operation, maintenance, and eventual decommissioning of Monticello. No physical changes to the facility or operational changes other than the transfer of operating authority to New NSP are being proposed in the application.
The proposed amendment would add a footnote to the license to reflect its transfer from NSP to the newly formed, wholly owned subsidiary.
Pursuant to 10 CFR 50.80, no license, or any right thereunder, shall be transferred, directly or indirectly, through transfer of control of the license, unless the Commission shall give its consent in writing. The Commission will approve an application for the transfer of a license, if the Commission determines that the proposed transferee is qualified to hold the license, and that the transfer is otherwise consistent with applicable provisions of law, regulations, and orders issued by the Commission pursuant thereto.
Before issuance of the proposed conforming license amendment, the Commission will have made findings required by the Atomic Energy Act of 1954, as amended (the Act), and the Commission's regulations.
As provided in 10 CFR 2.1315, unless otherwise determined by the Commission with regard to a specific application, the Commission has determined that any amendment to the license of a utilization facility which does no more than conform the license to reflect the transfer action involves no significant hazards consideration. No contrary determination has been made with respect to this specific license amendment application. In light of the generic determination reflected in 10 CFR 2.1315, no public comments with respect to significant hazards considerations are being solicited, notwithstanding the general comment procedures contained in 10 CFR 50.91.
The filing of requests for hearing and petitions for leave to intervene, and written comments with regard to the license transfer application, are discussed below.
By March 1, 2000, any person whose interest may be affected by the Commission's action on the application may request a hearing, and, if not the applicants, may petition for leave to intervene in a hearing proceeding on the Commission's action. Requests for a hearing and petitions for leave to intervene should be filed in accordance with the Commission's rules of practice set forth in Subpart M, “Public Notification, Availability of Documents and Records, Hearing Requests and Procedures for Hearings on License Transfer Applications,” of 10 CFR Part 2. In particular, such requests and petitions must comply with the requirements set forth in 10 CFR 2.1306, and should address the considerations contained in 10 CFR 2.1308(a). Untimely requests and petitions may be denied, as provided in 10 CFR 2.1308(b), unless good cause for failure to file on time is established. In addition, an untimely request or petition should address the factors that the Commission will also consider, in reviewing untimely requests or petitions, set forth in 10 CFR 2.1308(b)(1)-(2)
Requests for a hearing and petitions for leave to intervene should be served upon Jay Silberg, Esq., counsel for NSP, at Shaw, Pittman, Potts, and Trowbridge, 2300 N Street, NW, Washington, DC 20037 (tel: 202-663-8063; fax: 202-663-8007; e-mail: jay.silberg@shawpittman.com); and the General Counsel, U.S. Nuclear Regulatory Commission, Washington,
The Commission will issue a notice or order granting or denying a hearing request or intervention petition, designating the issues for any hearing that will be held and designating the Presiding Officer. A notice granting a hearing will be published in the
As an alternative to requests for hearing and petitions to intervene, by March 13, 2000, persons may submit written comments regarding the license transfer application, as provided for in 10 CFR 2.1305. The Commission will consider and, if appropriate, respond to these comments, but such comments will not otherwise constitute part of the decisional record. Comments should be submitted to the Secretary, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, Attention: Rulemakings and Adjudications Staff, and should cite the publication date and page number of this
For further details with respect to this action, see the application dated October 29, 1999, available for public inspection at the Commission's Public Document Room, the Gelman Building, 2120 L Street, NW., Washington, DC, and accessible electronically through the ADAMS Public Electronic Reading Room link at the NRC Web site (http://www.nrc.gov).
For the Nuclear Regulatory Commission.
The U.S. Nuclear Regulatory Commission (the Commission) is considering the issuance of an order under 10 CFR 50.80 and 10 CFR 72.50 approving the transfer of Facility Operating Licenses Nos. DPR-42 and DPR-60 for the Prairie Island Nuclear Generating Plant, Units 1 and 2, and Materials License No. SNM-2506 for the Prairie Island Independent Spent Fuel Storage Installation (ISFSI) currently held by Northern States Power Company (NSP), as owner and licensed operator of Prairie Island, Units 1 and 2, and Prairie Island ISFSI. The transfer would be to a newly formed company (referred to herein as “New NSP”). The Commission is also considering amending the licenses for administrative purposes to reflect the proposed transfer.
By application dated October 29, 1999, the Commission was informed that Northern States Power Company entered into an agreement on March 24, 1999, to merge with New Century Energies, Inc. (NCE). Under the agreement, NCE will be merged with and into NSP, which will be renamed Xcel Energy, Inc. At the time of the merger, NSP will transfer all of its existing electric and natural gas utility facilities and responsibility and control over operations to New NSP. New NSP would assume title to the facilities following approval of the proposed license transfers, and would become responsible for the operation, maintenance, and eventual decommissioning of Prairie Island, Units 1 and 2, and Prairie Island ISFSI. No physical changes to the Prairie Island, Units 1 and 2, or Prairie Island ISFSI facilities or operational changes other than the transfer of operating authority to New NSP are being proposed in the application.
The proposed amendment would add a footnote to the licenses to reflect their transfer from NSP to the newly formed, wholly owned subsidiary.
Pursuant to 10 CFR 50.80 and 10 CFR 72.50, no license, or any right thereunder, shall be transferred, directly or indirectly, through transfer of control of the license, unless the Commission shall give its consent in writing. The Commission will approve an application for the transfer of a license, if the Commission determines that the proposed transferee is qualified to hold the license, and that the transfer is otherwise consistent with applicable provisions of law, regulations, and orders issued by the Commission pursuant thereto.
Before issuance of the proposed conforming license amendment, the Commission will have made findings required by the Atomic Energy Act of 1954, as amended (the Act), and the Commission's regulations.
As provided in 10 CFR 2.1315, unless otherwise determined by the Commission with regard to a specific application, the Commission has determined that any amendment to the license of a utilization facility or the license of an independent spent fuel storage installation which does no more than conform the license to reflect the transfer action, involves respectively, “no significant hazards consideration” or “no genuine issue as to whether the health and safety of the public will be significantly affected.” No contrary determination has been made with respect to this specific license amendment application. In light of the generic determinations reflected in 10 CFR 2.1315, no public comments with respect to significant hazards considerations are being solicited, notwithstanding the general comment procedures contained in 10 CFR 50.91.
The filing of requests for hearing and petitions for leave to intervene, and written comments with regard to the license transfer application, are discussed below.
By March 1, 2000, any person whose interest may be affected by the Commission's action on the application may request a hearing, and, if not the applicants, may petition for leave to intervene in a hearing proceeding on the Commission's action. Requests for a hearing and petitions for leave to intervene should be filed in accordance with the Commission's rules of practice set forth in Subpart M, “Public Notification, Availability of Documents and Records, Hearing Requests and Procedures for Hearings on License Transfer Applications,” of 10 CFR Part 2. In particular, such requests and petitions must comply with the requirements set forth in 10 CFR 2.1306, and should address the considerations contained in 10 CFR 2.1308(a). Untimely requests and petitions may be denied, as provided in 10 CFR 2.1308(b), unless good cause for failure to file on time is established. In
Requests for a hearing and petitions for leave to intervene should be served upon Jay Silberg, Esq., counsel for NSP, at Shaw, Pittman, Potts, and Trowbridge, 2300 N Street, NW, Washington, DC 20037 (tel: 202-663-8063; fax: 202-663-8007; e-mail: jay.silberg@shawpittman.com); and the General Counsel, U.S. Nuclear Regulatory Commission, Washington, DC 20555 (e-mail address for filings regarding license transfer cases only: OGCLT@NRC.gov); and the Secretary of the Commission, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, Attention: Rulemakings and Adjudications Staff, in accordance with 10 CFR 2.1313.
The Commission will issue a notice or order granting or denying a hearing request or intervention petition, designating the issues for any hearing that will be held and designating the Presiding Officer. A notice granting a hearing will be published in the
As an alternative to requests for hearing and petitions to intervene, by March 13, 2000, persons may submit written comments regarding the license transfer application, as provided for in 10 CFR 2.1305. The Commission will consider and, if appropriate, respond to these comments, but such comments will not otherwise constitute part of the decisional record. Comments should be submitted to the Secretary, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, Attention: Rulemakings and Adjudications Staff, and should cite the publication date and page number of this
For further details with respect to this action, see the application dated October 29, 1999, available for public inspection at the Commission's Public Document Room, the Gelman Building, 2120 L Street, NW., Washington, DC, and accessible electronically through the ADAMS Public Electronic Reading Room link at the NRC Web site(http://www.nrc.gov).
For the Nuclear Regulatory Commission.
Nuclear Regulatory Commission.
Weeks of February 7, 14, 21, and 28, 2000.
Commissioners' Conference Room, 11555 Rockville Pike, Rockville, Maryland.
Public and Closed.
There are no meetings scheduled for the Week of February 14.
* The schedule for Commission meetings is subject to change on short notice. To verify the status of meetings call (recording)—(301) 415-1292.
Bill Hill (301) 415-1661.
The NRC Commission Meeting Schedule can be found on the Internet at: http://www.nrc.gov/SECY/smj/schedule.htm
This notice is distributed by mail to several hundred subscribers; if you no longer wish to receive it, or would like to be added to it, please contact the Office of the Secretary, Attn: Operations Branch, Washington, D.C. 20555 (301-415-1661). In addition, distribution of this meeting notice over the Internet system is available. If you are interested in receiving this Commission meeting schedule electronically, please send an electronic message to wmh@nrc.gov or dkw@nrc.gov.
The Nuclear Regulatory Commission has issued a new guide in its Regulatory Guide Series. This series has been developed to describe and make available to the public such information as methods acceptable to the NRC staff for implementing specific parts of the Commission's regulations, techniques used by the staff in evaluating specific problems or postulated accidents, and data needed by the staff in its review of applications for permits and licenses.
Regulatory Guide 1.180, “Guidelines for Evaluating Electromagnetic and Radio-Frequency Interference in Safety-Related Instrumentation and Control Systems,” endorses design, installation, and testing practices acceptable to the NRC staff for addressing the effects of electromagnetic interference, radio-frequency interference, and power surges on safety-related instrumentation and control systems in a nuclear power plant. The guide endorses, with certain conditions, the design and installation practices described in the Institute of Electrical and Electronics Engineers standard, IEEE Std 1050-1996, “IEEE Guide for Instrumentation and Control Equipment Grounding in Generating Stations.” Electromagnetic compatibility testing practices from military and commercial standards are endorsed to address electromagnetic emissions, electromagnetic and radio-frequency interference immunity, and power surge withstand capability.
Comments and suggestions in connection with items for inclusion in guides currently being developed or improvements in all published guides are encouraged at any time. Written comments may be submitted to the Rules and Directives Branch, Division of Administrative Services, Office of Administration, U.S. Nuclear Regulatory Commission, Washington, DC 20555.
Regulatory guides are available for inspection or downloading at the NRC's Public Electronic Reading Room at <www.nrc.gov>. Single copies of regulatory guides may be obtained free of charge by writing the Reproduction and Distribution Services Section, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by fax to (301) 415-2289, or by email to <DISTRIBUTION@NRC.GOV>. Issued guides may also be purchased from the National Technical Information Service on a standing order basis. Details on this service may be obtained by writing NTIS, 5285 Port Royal Road, Springfield, VA 22161. Regulatory guides are not copyrighted, and Commission approval is not required to reproduce them.
For the Nuclear Regulatory Commission.
In accordance with the requirement of Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995 which provides opportunity for public comment on new or revised data collections, the Railroad Retirement Board (RRB) will publish periodic summaries of proposed data collections.
Under Section 1(b)(1) of the Railroad Retirement Act (RRA), the term “employee” includes an individual who is an employee representative. As defined in Section 1(c) of the RRA, an employee representative is an officer or official representative of a railway labor organization other than a labor organization included in the term “employer,” as defined in the RRA, who before or after August 29, 1935, was in the service of an employer under the RRA and who is duly authorized and designated to represent employees in accordance with the Railway Labor Act, or, any individual who is regularly assigned to or regularly employed by such officer or official representative in connection with the duties of his or her office. The requirements relating to the application for employee representative status and the periodic reporting of the compensation resulting from such status is contained in 20 CFR 209.10.
The RRB utilizes Forms DC-2a, Employee Representative's Status Report, and DC-2, Employee Representative's Report of Compensation to obtain the information needed to determine employee representative status and to maintain a record of creditable service and compensation resulting from such status. Completion is required to obtain or retain a benefit. One response is requested of each respondent.
Minor editorial changes are proposed to Form DC-2a and Form DC-2. The completion time for Form DC-2 is estimated at 30 minutes per response. The RRB estimates that approximately 65 Form DC-2's are received annually. The RRB estimates that less than 10 Form DC-2a's are received annually.
To request more information or to obtain a copy of the information collection justification, forms, and/or supporting material, please call the RRB Clearance Officer at (312) 751-3363. Comments regarding the information collection should be addressed to Ronald J. Hodapp, Railroad Retirement Board, 844 North Rush Street, Chicago, Illinois 60611-2092. Written comments should be received within 60 days of this notice.
Upon Written Request, Copies Available From: Securities and Exchange Commission, Office of Filings and Information Services, Washington, D.C. 20549.
Extension: Rule 6e-2, SEC File No. 270-177, OMB Control No. 3235-0177.
Notice is hereby given that pursuant to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.), the Securities and Exchange Commission (“Commission”) is publishing the following summary of collection for public comment.
Rule 6e-2 [17 CFR 270.6e-2] under the Investment Company Act of 1940 (“Act”) is an exemptive rule which permits separate accounts, formed by life insurance companies, to fund certain variable life insurance products. The rule exempts such separate accounts from the registration
Rule 6e-2 provides a separate account with an exemption from the registration provisions of section 8 of the Act if the account files with the Commission Form N-6EI-1, a notification of claim of exemption.
The rule also exempts a separate account from a number of other sections of the Act, provided that the separate account makes certain disclosure in its registration statements, reports to contractholders, proxy solicitations, and submissions to state regulatory authorities, as prescribed by the rule.
Paragraph (b)(9) of Rule 6e-2 provides an exemption from the requirements of section 17(f) of the Act and imposes a reporting burden and certain other conditions. Section 17(f) requires that every registered management company meet various custody requirements for its securities and similar investments. Paragraph (b)(9) applies only to management accounts that offer life insurance contracts subject to Rule 6e-2.
Since 1997, there have been no filings under paragraph (b)(9) of Rule 6e-2 by management accounts. Further, all variable life separate accounts that have filed post-effective amendments to their registration statements during this period have been structured as unit investment trusts and thus have not been subject to the requirements of paragraph (b)(9) of the rule. Therefore, since 1997, there has been no cost or burden to the industry regarding the information collection requirements of paragraph (b)(9) of Rule 6e-2.
Written comments are invited on: (a) whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology. Consideration will be given to comments and suggestions submitted in writing within 60 days of this publication.
Direct your written comments to Michael E. Bartell, Associate Executive Director, Office of Information Technology, Securities and Exchange Commission, 450 Fifth Street, N.W. Washington, D.C. 20549.
Securities and Exchange Commission (“Commission”).
Notice of an application under sections 6(c), 10(f), and 17(b) of the Investment Company Act of 1940 (“Act”) for an exemption from sections 10(f) and 17(a)(1) of the Act.
The requested order would permit certain registered management investment companies to purchase certain securities from an affiliated underwriter and through group orders placed with an underwriting syndicate that includes the affiliated underwriter.
First American Investment Funds, Inc. (“FAIF”); Minnesota Municipal Income Portfolio, Inc.; Minnesota Municipal Term Trust, Inc.; Minnesota Municipal Term Trust, Inc.-II.; U.S. Bank National Association (“U.S. Bank”); and U.S. Bancorp Piper Jaffray Inc. (“Piper Jaffray”).
The application was filed on April 2, 1999 and was amended on December 22, 1999. Applicants have agreed to file an additional amendment, the substance of which is incorporated in this notice, during the notice period.
An order granting the application will be issued unless the Commission orders a hearing. Interested persons may request a hearing by writing to the Commission's Secretary and serving applicants with a copy of the request, personally or by mail. Hearing requests should be received by the Commission by 5:30 p.m. on February 29, 2000 and should be accompanied by proof of service on applicants in the form of an affidavit or, for lawyers, a certificate of service. Hearing requests should state the nature of the writer's interest, the reason for the request, and the issues contested. Persons may request notification by writing to the Commission's Secretary.
Secretary, Securities and Exchange Commission, 450 Fifth Street, NW., Washington, DC 20549-0609. Applicants, c/o James D. Alt, Esq., Dorsey & Whitney LLP, 220 South Sixth Street, Minneapolis, MN 55402.
Rachel H. Graham, Senior Counsel, at (202) 942-0583, or Nadya B. Roytblat, Assistant Director, at (202) 942-0564 (Division of Investment Management, Office of Investment Company Regulation).
The following is a summary of the application. The complete application may be obtained for a fee from the Commission's Public Reference Branch, 450 Fifth Street, N.W., Washington, D.C. 20549-0102 (telephone (202) 942-8090).
1. FAIF is an open-end management investment company registered under the Act. FAIF offers its shares in several series, including the Minnesota Intermediate Tax Free Fund and the Minnesota Tax Free Fund. Minnesota Municipal Income Portfolio, Inc., Minnesota Municipal Term Trust, Inc., and Minnesota Municipal Term Trust, Inc.-II are closed-end management investment companies registered under the Act. The two named series of FAIF, together with the three closed-end investment companies, collectively are referred to in this notice as the “Funds.” The Funds invest primarily in debt securities of the State of Minnesota, its political subdivisions, authorities, agencies, instrumentalities and corporations, the interest on which is exempt from federal and Minnesota personal income taxes (“Minnesota Tax-Excempt Securities”).
2. U.S. Bank, which is exempt from registration as an investment adviser under the Investment Advisers Act of 1940 (“Advisers Act”) pursuant to section 202(a)(11) of the Advisers Act, serves as investment adviser to each Fund. U.S. Bank is a wholly-owned subsidiary of U.S. Bancorp.
3. Piper Jaffray, a registered broker-dealer and investment banking firm, is a wholly-owned indirect subsidiary of U.S. Bancorp. Applicants state that Piper Jaffray is one of the leading underwriters of most types of Minnesota Tax-Exempt Securities based on both dollar volume and number of new issues. In 1998, Piper Jaffray served as underwriter of approximately $2.4 billion in principal amount of Minnesota Tax-Exempt Securities. According to applicants, this amount
4. Applicants request relief under section 10(f) from section 10(f) and under sections 6(c) and 17(b) from section 17(a)(1) to permit the Funds to purchase Minnesota Tax-Exempt Securities from Piper Jaffray, when Piper Jaffray is the sole underwriter of these securities or these securities are unavailable from other members of an underwriting syndicate. Applicants also request relief under these sections to permit the Funds to purchase Minnesota Tax-Exempt Securities through group orders placed with an underwriting syndicate of which Piper Jaffray is a member.
5. Applicants request that any relief granted pursuant to the application also apply to all current and future series of FAIF and to any other registered management investment companies organized in the future that are advised or subadvised by U.S. Bank (or a person controlling, controlled by, or under common control with U.S. Bank) and that invest primarily in Minnesota Tax-Exempt Securities (collectively, “Future Funds”).
1. Section 10(f) of the Act, in relevant part, prohibits a registered investment company from purchasing securities from an underwriting syndicate in which an affiliated person of the company's investment adviser acts as a principal underwriter. Under section 2(a)(3) of the Act, Piper Jaffray is an affiliated person of U.S. Bank because both entities are under the control of U.S. Bancorp.
2. Section 10(f) further provides that the Commission, by rule or order, may exempt any transaction or class of transactions from section 10(f) to the exempt that the exemption is consistent with the protection of investors. Rule 10f-3 under the Act permits a registered investment company to make purchases otherwise prohibited by section 10(f) under certain conditions. Under the rule, the company may not purchase the securities being offered directly or indirectly from its affiliated underwriter, and purchases of municipal securities may not be designated as group sales or otherwise allocated to the account of the affiliated underwriter.
3. Section 17(a)(1) of the Act, in relevant part, prohibits an affiliated person of a registered investment company, or an affiliated person of such person, acting as principal, from selling securities to the investment company. Under section 17(b) of the Act, the Commission will exempt a transaction from the provisions of section 17(a) if it finds that the terms of the proposed transaction are fair and reasonable and do not involve overreaching on the part of any person concerned, and that the proposed transaction is consistent with the policy of the registered investment company and the general purposes of the Act. Section 6(c) of the Act, in relevant part, permits the Commission to exempt any transaction or class of transactions from any provision of the Act if, and to the extent that, the exemption is necessary or appropriate in the public interest and consistent with the protection of investors and the purposes fairly intended by the policy and provisions of the Act.
4. Applicants assert that the supply of newly-issued Minnesota Tax-Exempt Securities has remained relatively stable over the past several years, while the demand for these securities has been increasing. Applicants state that, in their experience, group orders generally are given priority over designated orders and member orders in underwritings of Minnesota Tax-Exempt Securities.
5. Applicants assert that the Funds are largely dependent upon the new issue market for Minnesota Tax-Exempt Securities in order to meet their portfolio needs. According to applicants, the availability of Minnesota Tax-Exempt Securities in the secondary market is unpredictable because, among other reasons, a substantial portion of these securities are held to maturity by their original purchasers. Applicants also assert that prices may be higher in the secondary market because of dealer markups and, because secondary market purchases are often made at a discount to par, a portion of the return on the securities purchased may be treated as taxable income.
6. Applicants state that permitting the Funds to buy Minnesota Tax-Exempt Securities directly from Piper Jaffray when the securities are unavailable from another underwriter, or through group orders when Piper Jaffray is a member of the underwriting syndicate for the securities, would benefit the shareholders of the Funds by providing the Funds with adequate access to the new issue market for Minnesota Tax-Exempt Securities. Applicants assert that, as a condition to the requested relief, the Funds, together with all other persons for whom U.S. Bank and its affiliates have investment discretion (collectively, “Related Purchasers”) would be prohibited from purchasing a majority or more of any class of an issue of Minnesota Tax-Exempt Securities when Piper Jaffray is an underwriter of the securities. This condition would operate in addition to the requirement in rule 10f-3(b)(7)(i) that the aggregate amount of securities of any class of Minnesota Tax-Exempt Securities purchased by the Funds, together with all other investment companies advised by U.S. Bank, may not exceed 25% of the principal amount of the offering of that class. According to applicants, these two requirements would protect the Funds against the dumping of unmarketable securities.
7. Applicants note that, as a further condition to the requested relief, the aggregate value of Minnesota Tax-Exempt Securities held by a fund and acquired pursuant to the order may not exceed 50% of the Fund's total net assets. According to applicants, this condition should ensure that no Fund is operated primarily as a vehicle for purchasing securities in transactions permitted by the order. Applicants state that the order also would be conditioned on certain procedural safeguards designed to protect the independence of U.S. Bank in making investment decisions on behalf of the Funds and to ensure appropriate oversight of all transactions effected in reliance on the order. Applicants further state that the requested order meets the standards for relief set forth in sections 6(c), 10(f), and 17(b) of the Act.
Applicants agree that the order will be subject to the following conditions:
1. Transactions effected pursuant to the order will be effected in accordance with all of the provisions of rule 10f-3, other than paragraph (b)(8). At least a majority of any class of an issue of Minnesota Tax-Exempt Securities purchased pursuant to the order must be purchased by persons who are not Related Purchasers. If the aggregate number of securities the Related Purchasers wish to acquire exceeds the permitted amount, the securities acquired will be allocated to each Related Purchaser in the proportion that the number of securities that such Related Purchaser wishes to acquire bears to the total number of securities that all Related Purchasers wish to acquire.
2. Purchases of Minnesota Tax-Exempt Securities directly from Piper Jaffray or from a syndicate manager of an underwriting syndicate of which Piper Jaffray is a member when the purchases are designated as group sales may be effected only in Minnesota Tax-Exempt Securities that, at the time of purchase, have one of the following investment grade ratings from at least one nationally recognized statistical rating organization: (i) One of the two highest investment grade ratings in the case of securities with remaining maturities of one year or less, or (ii) one of the three highest investment grade ratings in the case of securities with remaining maturities greater than one year.
3. Purchases of Minnesota Tax-Exempt Securities directly from Piper Jaffray or from a syndicate manager of an underwriting syndicate of which Piper Jaffray is a member when the purchases are designated as group sales will be limited so that no such transaction will be effected if, as a result, the aggregate value of Minnesota Tax-Exempt Securities held by a Fund and acquired pursuant to the order would exceed 50% of the total net assets of that Fund.
4. Purchases of Minnesota Tax-Exempt Securities directly from Piper Jaffray or from a syndicate manager of an underwriting syndicate of which Piper Jaffray is a member when the purchases are designated as group sales will be effected only when the Minnesota Tax-Exempt Securities to be acquired are otherwise unavailable for purchase. If Piper Jaffray is the sole underwriter of the securities, this condition is automatically fulfilled because there is no other potential seller. When Piper Jaffray is a member of an underwriting syndicate, U.S. Bank will observe the following procedures to determine when the securities are unavailable from other members of the syndicate. Initially, U.S. Bank will determine the aggregate number of securities that the Related Purchasers wish to acquire. Next, U.S. Bank will attempt to purchase as much of this number as possible from members of the syndicate other than Piper Jaffray. After acquiring as many securities as possible from such other members, U.S. Bank will attempt to purchase from Piper Jaffray the number of securities that the Related Purchasers wish to acquire and have been unable to obtain from such other members. The securities acquired from such other members will be allocated first to the Funds to the extent of the number of securities the Funds wish to acquire, or the number of securities the Funds are entitled to acquire based upon the relative needs of the Related Purchasers and the total number of securities purchased from such other members and from Piper Jaffray, whichever is less.
5. When the Funds purchase Minnesota Tax-Exempt Securities from a syndicate manager of an underwriting syndicate of which piper Jaffray is a member, the Funds will not: (i) Submit designated orders to a syndicate manager that are allocated to Piper Jaffray; (ii) submit group orders to a syndicate manager that designate Piper Jaffray to receive any portion of the commission; or (iii) otherwise allocate orders to Piper Jaffray.
6. The exemption will be valid only so long as U.S. Bank and Piper Jaffray operate as separate entities and independent profit centers within the holding company framework of U.S. Bancorp, with separate officers and employees, separate capitalizations, and separate books and records. Employees of Piper Jaffray will not participate with, or seek to influence, U.S. Bank in its investment decisions as investment adviser to the Funds, other than in the normal course of sales activities of the same nature that are being carried out simultaneously with respect to unaffiliated clients of Piper Jaffray. Senior executives of U.S. Bancorp with responsibility for overseeing the operations of various subsidiaries are not precluded from exercising those functions over U.S. Bank because they oversee Piper Jaffray as well, provided that such persons will not have any involvement with respect to transactions effected pursuant to the exemption and will not attempt to influence or control the purchase of securities by the Funds from Piper Jaffray or an underwriting syndicate of which Piper Jaffray is a member.
7. U.S. Bank and Piper Jaffray will adopt a set of guidelines for their respective personnel to make certain that transactions conducted pursuant to the order comply with the conditions set forth in the application and that the parties maintain arm's length relationships. Compliance officers of U.S. Bank and Piper Jaffray will periodically monitor the activities of their respective companies for compliance with such guidelines and with the conditions set forth in the application.
8. The board of directors of each Fund, including a majority of the directors who are not interested persons under section 2(a)(19) of the Act and have no direct or indirect financial interest in the transaction (other than through ownership of Fund shares), will review, no less frequently, each purchase of Minnesota Tax-Exempt Securities directly from Piper Jaffray or from a syndicate manager of an underwriting syndicate of which Piper Jaffray is a member when the purchases are designated as group sales since the last review and will determine that the terms of such transaction were reasonable and fair to the shareholders of the Fund and did not involve overreaching of the Fund or its shareholders on the part of any person concerned. In considering whether the price paid for the security was reasonable and fair, the price of the security will be analyzed with respect to comparable transactions involving similar securities being purchased or sold during a comparable period of time.
For the Commission, by the Division of Investment Management, under delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934
The Exchange proposes to amend certain provision of its listing standards to simplify the listing process, eliminate certain outdated processes, and to clarify the Exchange's alternative listing guidelines for domestic companies. The text of the proposed rule change is as follows. Proposed new language is in italic; deletions are in brackets.
The approval of an application for the listing of securities is a matter solely within the discretion of the Exchange. To assist companies interested in applying for listing, the Exchange has established certain numerical guidelines, outlined below, which will be considered in evaluating listing eligibility. Other factors which will also be considered include the nature of a company's business, the market for its products, the reputation of its management, its historical record and pattern of growth, its financial integrity, its demonstrated earning power and its future outlook.
The fact that an applicant may meet the Exchange's numerical guidelines does not necessarily mean that its application will be approved. On the other hand, an application may be approved even though the company does not meet all of the numerical guidelines.
[The Exchange will furnish, without charge, a confidential preliminary opinion as to the eligibility of an applicant for listing as described in § 202.]
See §[§'s] 110 [and 115] for special criteria relating to foreign issuers [and member corporations]
([a]
([b]
Additional criteria applicable to various classes of securities and issuers are set forth below. Applicants should also consider the policies regarding conflicts of interest, independent directors and voting rights described in §§ 120-125.
It is recognized that certain financially sound companies are unable to meet fully the Exchange's regular listing criteria because, for example, of the nature of their business, or because of continuing large expenditures of funds for research and development. Such companies may, however, qualify for listing provided they meet the numerical criteria outlined below, have sufficient financial resources to continue operations over an extended period of time, and are otherwise regarded as suitable for Exchange listing.
Among the factors considered by the Exchange in determining a company's listing eligibility are the following:
(a) the nature and scope of the applicant's operations, including its demonstrated ability to acquire or discover and develop new products or properties, the potential or proven market for existing or future products and the company's plans for future development and expansion of its existing resources;
(b) the applicant's financial condition and accounting practices, its ability to service existing debt and other obligations, the availability of financing for currently committed programs and future expansion, and the size of its development expenses in relation to its equity and revenues;
(c) the composition of the applicant's assets including its reserves, royalties, or other rights and patents;
(d) the experience and reputation of the applicant and its management; and
(e) the nature and effect of governmental policies or restrictions on the company's products or properties and the extent of competition and economic conditions within the particular industry.
Numerical Criteria:]
([a]
([b]
([c]
([d]
(a)
(a)-(c) no change
[(d)
Redeemable issues, if subject to redemption in part, must be redeemable only pro rata or by lot. (See § 902)]
For the Exchange to list a debt security, the security must be characterized by one of the following conditions:
(A) the issuer of the debt security has equity securities listed on the Exchange (or on the New York Stock Exchange
(B) an issuer of equity securities listed on the Exchange (or on the New York Stock Exchange
(C) an issuer of equity securities listed on the Exchange (or on the New York Stock Exchange
The listing of warrant issues is concerned on a case by case basis. The Exchange will not consider listing the warrant issue of a company unless the common stock or other securities underlying the warrants are listed and in good standing either on the American or New York Stock Exchanges
(a) no change
[(b)
The Exchange generally will not list the securities of companies organized for the exploration and development of natural resources until they have reached the production stage and meet the criteria set forth in § 101.]
The following requirements and procedures will apply to the original listings of securities of publicly-owned member corporations:
(a) Size-Stockholders' equity of at least $10 million. In determining a listing applicant's ability to meet this standard, the Exchange will value securities owned by the applicant at less than market value, depending upon the ready marketability of such securities. The applicant shall include in its listing application a list and the amounts of the securities owned by it, the names of the exchanges on which they are listed, and whether there are any restrictions against their sale as in the case of securities acquired for investment (“letter stock”).
(b) Earnings-Pre-tax income of at least $1.5 million for the latest fiscal year.
(c) Historical Operations—A history of satisfactory operations for at least 3 years prior to listing in order to demonstrate the applicant's ability to operate profitability under normal conditions. As in the case of all other listing applicants, all relevant factors regarding a member corporation's operations will be carefully considered, including the period of time in which present management has conducted the corporation's operations and the changes, if any, in management during the three year period under review.
(d) Capital Ratios—A regular capital ratio which has not exceeded 10-to-1 (or an alternate capital ratio which has not been less than 5%) for any period of 15 consecutive days during the six-month period preceding filing of the applicant's listing application.
In addition to the usual review procedures applicable to other types of corporations, the following special procedures will apply in reviewing member corporations for listing:
(a) Reports received by the Exchange under FOCUS filing requirements will be reviewed and any problems indicated by such reports will be required to be satisfactorily resolved before listing. FOCUS reports will be required of any member corporation listing applicant not already filing them for a three-month period before consideration of the listing application.
(b) In the case of an applicant which is also a member of the New York Stock Exchange, a copy of the report of the most recent examination by the New York Stock Exchange will be reviewed and any problems disclosed in such report must be satisfactorily resolved before listing.
Any member corporation, which intends to list its securities on the Exchange, will be required to include in its prospectus additional disclosures with respect to certain regulatory actions which the Exchange (or the New York Stock Exchange) may take and which may have an adverse impact on the firm's future income and prospects. Among the actions which such Exchanges may take are:
(a) limiting the opening of new offices, employment of new registered representatives, or opening of new accounts;
(b) requiring an organization to cease business as a clearing organization and become solely an introducing broker;
(c) restricting the types of activities which a member organization performs;
(d) requiring an organization to reorganize or even to liquidate its business; and
(e) requiring a listed member corporation to make timely disclosure of material information concerning its business, financial situation or prospects, or other matters which might have a bearing on its operations.
In addition to publishing quarterly statements of revenues and earnings as required by the rules and regulations of the Exchange, a listed member corporation shall be required to distribute copies of such statements to its stockholders. Such quarterly reports, as well as the annual report, shall also contain a statement regarding the corporation's net capital position in relation to the standards of the Exchange and the New York Stock Exchange.
A listed member corporation shall be required to file with the Exchange copies of its financial statements and questionnaires which it files with the New York Stock Exchange.]
In addition to the many factors considered in the evaluation of any application for original listing (see § 101), the Exchange will give particular attention to the historical record, operating procedures and management personnel of any applicant company which is engaged, to any substantial extent, in gaming operations. An applicant of this nature will be required to demonstrate that it has adequate procedures and management capabilities to detect and appropriately control any of the following:
(a) the association with any person having a criminal background or who would not qualify for a license under any Federal, state or local regulatory requirements under which the applicant company operates;
(b) any misuse of the company's funds or misappropriation of its receipts from gaming operations; or
(c) any activities by persons associated either directly or indirectly with the company designed to promote the company's securities in contravention of the securities laws or to evade the disclosure requirements of the Exchange.
Any of the following factors may be considered by the Exchange as a basis for refusing to approve the application of a company engaged in gaming operations:
(a) if the company (or any predecessor organization that has been responsible for operating such gaming facilities), or any officer, director, controlling stockholder or managerial or supervisory employee of the company or of any such predecessor, or any other person having an association or relationship with the company or such predecessor whereby such person was, or is, in a position to influence management decisions with respect to, or to receive benefits from, the operation of such gaming facilities, has been convicted of any criminal offense relating to gaming or to any other business of the company or such predecessor, or relating to fraud, violation of the securities laws or violation of any Federal or state anti-racketeering or similar statutes, at any time during a period ten (10) years preceding the date of the application for listing;
(b) if any person described in the preceding paragraph has been indicted or cited for violation of any Federal, state or local statute or ordinance relating to gaming or fraud, or has been denied a license or had his license revoked by any Federal, state, or local agency having jurisdiction over gaming operations, or any such person has been identified by an appropriate Federal or state agency as being associated with organized crime or with other persons conspiring to violate gaming or anti-racketeering statutes, at any time during a period of five (5) years preceding the date of the application for listing;
(c) if any investigation (by any appropriate Federal, state or local agency) of the company, or of any predecessor or other person described in the first paragraph above, has disclosed any material violations of any law, rule or regulations applicable to the gaming operations of the company, during a period of five (5) years preceding the date of the application for listing;
(d) if the company has in its employ, or has associated with it in any capacity, any person who, if required to be licensed in any Federal, state or local agency having jurisdiction over gaming operations, is not so licensed or has been denied a license or has been found to be unsuitable to receive a license;
(e) if the company, or any predecessor or other person described in the first paragraph
(f) if the company, or any predecessor described in the first paragraph above, shall have failed to received an unqualified opinion of an independent public accountant with respect to the balance sheet and statement of operations of the company or any such predecessor for each of the five (5) fiscal years preceding the date of the application for listing.
In connection with the subsequent filing of any listing application by a company seeking to issue additional securities, the purpose of which is to enable the company to become engaged to a substantial degree in gaming or related activities, the Exchange will apply all of the above standards to the same extent as though the application were for original listing. Moreover, the Exchange will consider the suspension of trading in, or removal from listing or unlisted trading of, the securities of any company which, after the effective date of this policy, takes steps to become engaged in gaming operations to any substantial degree, unless the company can demonstrate that it meets all of the above special requirements for original listing of companies engaged in gaming operations.]
(a)-(d) no change
[(e)
([f]
([g]
([h]
(i) Additional Listing—(see Part 3 of the Guide);
(ii) Dividends, Stocks Splits and Distributions (see §§ 501-507 and 509 of the Guide);
(iii) [Transfer Facilities, Certificates—(see §§ 801-841 of the Guide);
(iv)] Notification—comply with existing notification requirements of the Exchange.
The eligibility of a Trust for listing is subject to the following:
(a) no change
(b) no change
(c) [Trustees—See § 118A(a).
(d)] Voting—When a share or unit has been divided into separate components, any voting rights accorded the share or unit may be divided between the component securities as specified in the Trust prospectus.
([e]
[The existence of material conflicts of interest between companies and their officers, directors or principal shareholders (or members of their families or concerns controlled by, or affiliated with, them) will be reviewed by the Exchange in considering the eligibility of companies for original listing. In many cases, companies are able to eliminate conflict situations prior to listing or within a reasonable period after listing, and may be asked to do so. Where a conflict cannot be resolved promptly for sound business reasons, the Exchange will consider all pertinent factors.]
no change
Applicants must register the security to be listed under Section 12(b) of the Exchange Act (§ 210) and submit an original listing application (§ 211). [Before doing so, they should first obtain a preliminary opinion as to eligibility (§ 202) which the Exchange will furnish without charge.]
In addition to meeting the foregoing criteria, companies applying for listing enter into agreements with the Exchange and become subject to its rules, regulations and policies applicable to listed companies.
Among other things, listed companies are required to:
(e) [
(g)])
[A processing fee of $1,000 will be charged for special shareholder rights plans in lieu of the fees set forth in the above schedules, so long as such rights are neither exercisable nor tradable as a separate security.]
Upon the shareholder rights becoming exercisable and tradabale separately:
• an original fee will be charged based on the number of shareholder rights then outstanding and on additional issuance of rights[, less the $1,000 processing fee;]
• shareholder rights will be subject to the Exchange's continuing annual fee schedule.
The annual fee is payable in January of each year and is based on the total number of all classes of shares ([including]
In the calendar year in which a company first lists, the annual fee will be prorated to reflect only that portion of the year during which the security has been admitted to dealings and will be payable in December based on the total number of outstanding shares of all classes of stock at the time of original listing.
(a)
(b)
There are normally [eight]
(a) [company request preliminary listing eligibility opinion and receives favorable opinion;]
(b)-(h) reclassified as (a)-(g)
An applicant should obtain an informal and confidential opinion as to the eligibility of a particular issue for listing before preparing and filing a complete listing application. There is no charge for such opinion. The opinion may be obtained by sending the following data to the Exchange:
(a) three copies of the latest prospectus and proxy statement of the company (if available);
(b) three copies of printed annual reports distributed to shareholders for the last fiscal year and one copy of the annual report for preceding two years (if available) or financial statements for such years; five copies of SEC Form 10-K for latest fiscal year (if available); five copies of SEC Form 10-Q (if available) for interim periods since end of latest fiscal year; and one copy of each SEC Form 8-K filed since the latest Form 10-K;
(c) a certificate showing the extent of the public distribution of the stock, to be furnished on a printed form (Listing Form 2) supplies by the Exchange;
(d) information with respect to personal interests of any officers, directors or principal shareholders in any business arrangements involving the company such as the leasing of property to or from the company, interests in minority-held subsidiaries, interests in businesses that are competitors, suppliers or customers of the company, loans to or from the company, if not included in Form 10-K prospectus or proxy statement; and
(e) information concerning material pending litigation if not included in Form 10-K, prospectus, or proxy statement.]
A preliminary listing eligibility opinion is normally rendered within one to two weeks after the opinion is requested. An additional two weeks is normally required for the complete processing of an application.]
Each company is assigned to a [Corporate Relations Manager]
(a) [
A [preliminary] typewritten [draft of the] listing application (signed by an executive officer of the applicant), together with all appropriate attachments, as outlined below, and one copy only of each of the required exhibits, should be [initially] filed with the Exchange for examination. If any deficiencies are noted, or any changes are considered necessary in the form or contents of the application and exhibits, the applicant will be notified.
(b)
(i) no change
(ii) no change
(iii) no change
(iv) [a certificate showing the extent of the public distribution of the stock, to be furnished on a printed form (Listing Form 2) supplied by the Exchange; and
(v) information concerning material pending litigation if not included in Form 10-K, prospectus, or proxy statement; and
(vi) a statement that there have been no material developments since the date of the latest SEC filing; and
(vii)] such other information, documents or materials as may be deemed appropriate by the Exchange for inclusion in the applicant's listing application.
(c)
(d)
[(e)
[An application for original listing of a stock issue shall recite, in substantially the order given below, the following:
(a) name of the applicant, address and telephone number of principal executive officer; and
(b) date of application and formal request for listing; specifying the amount, class and par value of the security applied for.
Application shall be made to list only that part of an issue which is actually issued, including both outstanding and treasury shares. If an additional unissued amount is reserved for issuance for a specific purpose, application may also be made for authority to add that amount to the list, upon official notice of issuance for that specific purpose. The request for authority to list such additional amount should state briefly, but specifically, the purpose of issuance, and that the listing authorization of such shares is effective only if they are issued for that purpose. No additional unissued amount may be applied for, which is not reserved for issuance for a specific purpose by the Board of Directors.
If the applicant has any other classes of stock which are not being listed, the application should indicate how many such shares are outstanding, how many such shares are reserved for future issuance and the purpose thereof.
[The following exhibits must be filed i]
[
[
If counsel, or any partner of such counsel (or, if a firm, any member thereof) is an officer, director or shareholder of the applicant, this fact must be disclosed in the opinion and in the listing application.
[
[
[
In the case of mines which are developing, the engineer's report must contain:
(a) recommendations regarding the development program; (by estimate as to amount of additional funds which will be required to complete the development program as outlined; and (c) estimate of length of time required to complete such development program.
Applicants with
If counsel, or any partner of such counsel (or, if a firm, any member thereof) is an officer, director or shareholder of the applicant, this fact must be disclosed in the opinion and in the listing application.
Applicants with securities already listed on the Exchange should file supporting Exhibits 13-15 above, as well as Exhibits 1 and 5 set forth in § 213.]
Applicants with
If counsel, or a partner of such counsel, is an officer, director or shareholder of the applicant, this fact must be disclosed in the opinion and in the listing application.
In the case of applicants with securities already listed on the Exchange, the supporting Exhibits shall consist of 16, 17, and 18 referred to above, plus Exhibits 1, 2 and 5 specified in § 213.]
Generally, the exhibits to be filed in support of an original listing application of a foreign issue will be substantially the same as those pertaining to an equivalent domestic issue. [See §§ 213, 216 and 219.)]
Where an application is made to list ADRs, rather than the underlying securities, a copy of the Deposit Agreement and a specimen ADR certificate should also be filed in support of the listing application.
Stock to be issued in a forward split or dividend must be listed prior to the distribution date of such action. A company must complete the Reconciliation Sheet provided in the Exchange's form of application, as of the record date of the scheduled distribution.
If fractional shares are to be paid in cash and the exact number of shares cannot be determined in advance, the company should list the maximum number of shares that can be issued and subsequently request cancellation of the listing of the balance of shares not issued.
[
A substitution listing application is necessary whenever a company engages in a reverse stock split, re-incorporates, proposes to list a new class of securities in substitution for a previously listed class of securities or otherwise engages in a transaction which would require it to file a new Form 8-A [or Form 8-B] with SEC in regard to a previously listed security.
[
If a company is listing debt securities in substitution for a previously listed debt issue, it is also required to submit: (i) a specimen certificate of each denomination of security to be listed, with certification from the banknote company as specified in § 823; (ii) a copy of the mortgage, indenture, or equivalent instrument (or amendments thereto) certified by the trustee with amendments; and (iii) a certificate from the trustee showing acceptance of the trust (see Sample Trustee's Certificate in Appendix).
If a company is listing warrants in substitution for a previously listed warrant class, it is also required to submit: (i) a specimen certificate of each denomination of security to be listed, with certification from the banknote company as specified in § 823; (ii) a copy of the contract with each warrant agent on Listing Form 5 (see form in Appendix); and (iii) a certified copy of the warrant agreement.]
A listed company must promptly disclose any action taken by it with respect to the allotment of rights to subscribe or rights or benefits pertaining to the ownership of its listed securities. It is further required to give prompt notice of any such action to the Exchange to afford the holders of such securities a proper period within which to record their interests and exercise their rights. These requirements are further explained in paragraphs (a) through (h) below.
The Exchange will not admit subscription rights to dealings unless the underlying security is or will be listed on the Exchange.
(a) No change
(b)
The mailing of the subscription rights to shareholders should occur as soon after the record date as possible. Most companies have their transfer agents mail the rights on the same date as the record date or, at the latest, on the business day following the record date.
The subscription period should be for at least 14 calendar days following the mailing date. [provided the subscription agent is located in New York City. If the transfer agent (which usually also acts as the subscription agent) is not located in New York City or does not have a New York City “drop” (see § 801), such additional number of days as is equal to the mailing distance between New York City and the location of the subscription agent should be added to the 14 day period. For example, if the sole subscription agent is located in Boston, without “drop” facilities in New York City, the subscription period should be at least 15 days; in Chicago 16 days; and on the Pacific Coast 18 days. Companies not having a New York City transfer agent (or the equivalent thereof) should consider the advisability of appointing a New York City banking institution to act as subscription agent or co-subscription agent to facilitate the handling of subscriptions in relationship to the minimum subscription period involved.] (See §§ 510-522 for further explanation of “ex-rights” rule.)
(c) No change
(d) No change
(e)
Transferable rights may be admitted to dealings on the Exchange as soon as notice is received that the company's Securities Act registration statement or offering circular has become effective. The normal procedure is to admit the rights to dealings at 10:00 a.m. on the day following the day the registration statement or offering circular has become effective. Accordingly, the company should arrange to have the registration statement or offering circular declared effective as of 4:00 p.m. on the date preceding the anticipated trading date. The company or its attorneys should notify the Exchange
Trading in rights on the Exchange will cease at the close of business on the business day preceding the expiration date thereof, if such rights are exercisable in the New York City metropolitan area, and at such time in advance of the expiration date as may be announced by the Exchange, if such rights are exercisable outside such area. (Exchange Rule 17.) This facilitates open contracts to be settled and rights to be exercised on the final day.
(f)
This arrangement is between the brokers for the purchasers and the sellers of the stock, and does not involve the company. For a further explanation, see §§ 510-522.
(g) No change
(h) No change
The Exchange should be consulted prior to the submission of any application involving securities with special shareholder rights. (See § 140 for discussion of the fee.)]
The Exchange considers that the conduct of a fair and orderly market requires every listed company to make available to the public information necessary for informed investing and to take reasonable steps to ensure that all who invest in its securities enjoy equal access to such information. In applying this fundamental principle, the Exchange has adopted the following six specific policies concerning disclosure, each of which is more fully discussed (in a Question and Answer format) in § 402:
(a)
(b)-(f) no change
(a)
Q. When may a company properly withhold material information?
A. Occasionally, circumstances such as those discussed below may arise in which-provided that complete confidentiality is maintained-a company may temporarily refrain from publicly disclosing material information. These situations, however, are limited and constitute an infrequent exception to the normal requirement of immediate public disclosure. Thus, in cases of doubt, the presumption must always be in favor of disclosure.
(i) no change
(ii) When the facts are in a state of flux and a more appropriate moment for disclosure is imminent.
Occasionally, corporate developments give rise to information which, although material, is subject to rapid change. If the situation is about to stabilize or resolve itself in the near future, it may be proper to withhold public disclosure until a firm announcement can be made, since successive public statements concerning the same subject (but based on changing facts) may confuse or mislead the public rather than enlighten it.
For example, in the course of a successful negotiation for the acquisition of another company, the only information known to each party at the outset may be the willingness of the other to hold discussions. Shortly thereafter, it may become apparent to the parties that it is likely an agreement can be reached. Finally, agreement in principle may be reached on specific terms. In such circumstances (and assuming the maintenance of strict confidentiality), a company need not issue a public announcement at each stage of the negotiations, describing the current state of constantly changing facts, but may await agreement in principle on specific terms. If, on the other hand, progress in the negotiations should stabilize at same other point, disclosure should then be made if the information is material.
Whenever material information is being temporarily withheld, the strictest confidentiality must be maintained, and the company should be prepared to make an immediate public announcement, if necessary. During this period, the market action of the company's securities should be closely watched, since unusual market activity frequently signifies that a “leak” may have occurred. This is one reason why it is important to keep the company's [Corporate Relations Manager]
Q. What action is required if rumors occur while material information is being temporarily withheld?
A. If rumors concerning such information should develop, immediate public disclosure becomes necessary. (See also “Clarification or Confirmation of Rumors and Reports” on page 4-7.)
Q. What action is required if insider trading occurs while material information is being temporarily withheld?
A. Immediate public disclosure of the information in question must be effected if the company should learn that insider trading, as defined in section 402(f), has taken or is taking place. In unusual cases, where the trading is insignificant and does not have any influence on the market, and where measures sufficient to halt insider trading and prevent its recurrence are taken, exemptions might be made following discussions with the Exchange. The company's [Corporate Relations Manager]
(b)
Q. What specific disclosure techniques should a company employ?
A. The steps required are as follows:
(i)
(ii)
Concerns that distribute press releases over private [teletype] networks may be extremely helpful in gaining news coverage. Two such organizations are PR Newswire, [150 E. 58th St., New York, N.Y. 10022 [(212) 832-9400 or (800) 832-5522 (outside New York)],] and Business Wire [, 1133 Avenue of the Americas, New York, N.Y. 10036 [(212) 575-8822 or (800) 221-2462 (outside New York)]].
Companies may also wish to broaden their distribution to other news or broadcast media, such as those in the location of the company's plants or offices, and to trade publications. The information in question should always be given to the media in such a way as to promote publication by them as promptly as possible, i.e., by telephone, telecopy, or in writing (by hand delivery), on an “immediate release” basis. Companies are cautioned that some of these media may refuse to publish information given by telephone until it has been confirmed in writing or may require written confirmation after its publication.
Whenever difficulty is encountered or anticipated in having an announcement about a material development published, a company should contact [its Corporate Relations Manager who may frequently]
Three copies of all public announcements should be sent to the Exchange. [Announcements can be telecopied to the Exchange at (212) 306-1488.]
Q. How does the policy on thorough public dissemination apply to meeting with securities analysts, journalists, stockholders and others?
(c)
no change
(d)
Q. What is the significance of unusual market activity from the standpoint of disclosure?
A. Where unusual market action (in price movement, trading activity, or both) occurs without any apparent publicly available information which would account for the action, it may signify trading by persons who are acting either on unannounced material information or on a rumor or report, whether true or false, about the company. Most often, of course, unusual market activity may not be traceable either to insider trading or to a rumor or report. Nevertheless, the market action itself may be misleading to investors, who are likely to assume that a sudden and appreciable change in the price of a company's stock must reflect a parallel change in its business or prospects. Similarly, unusual trading volume, even when not accompanied by a significant change in price, tends to encourage rumors and give rise to speculative trading activity which may be unrelated to actual developments in the company's affairs.
Generally, unusual market activity will first be detected by either the Specialist in the company's securities or the Exchange's Stock Watch Department[. This information will then be passed on to the company's Corporate Relations Manager, who],
(a)
no change
(b)
[Whenever a conflict arises, the company should discuss the matter with the Securities and Exchange Commission, as well as with its Exchange Corporate Relations Manager, who can frequently assist in evaluating the problem.]
(c)
(ii) no change
(iii) Since skill and experience are important to the preparation and editing of accurate, fair and balanced public announcements, the Exchange recommends that a limited group of individuals within the company be given this assignment on a continuing basis. (Since a press announcement usually must be prepared and released as quickly as possible, however, the group charged with this assignment should be large enough to handle problems that arise suddenly and unexpectedly.) The [company's Corporate Relations Manager]
(iv) no change
[As previously noted, the Corporate Relations Managers are primarily responsible for the day-to-day relations with listed companies. They are familiar with the affairs of their assigned companies and are connected by direct wire to the trading floor of the Exchange. They also maintain close contact with the Exchange's Stock Watch Department, which is responsible for monitoring unusual market situations.]
A company expecting to make a material corporate announcement should first contact its Corporate Relations Managers who is in a unique position to evaluate disclosure problems as they arise and explain their effect on the public, the company and the Exchange. By means of such advance consultation, effective liaison between companies and the Exchange is maintained, and a company can obtain the benefit of the Representative's experience in the day-to-day application of the Exchange's policies relating to corporate disclosure.]
no change
A company is not permitted to close its stock transfer books for any reason, including the declaration of a dividend. Rather, it must establish a record date for shareholders entitled. To a dividend which is at least ten days after the date on which the dividend is declared (declaration date). [However, in the
Immediately after the board of directors has declared a cash or stock dividend, the company should: (a) release the news to the newspapers and news services, including the news-ticker services operated by Dow Jones & Company, Inc., and Reuters Ltd., (see § 402); and (b) notify the Exchange by telephone[, telegram] or [telecopier]
[In the establishment and announcement of ex-dividend dates, the Exchange proceeds as follows:
The “ex-dividend” date established by the Exchange is based on the location of the transfer facilities either in, or nearest to, New York City. Thus, if an issue transfers both in New York City and outside of New York City, the “ex” date is based on the New York City transfer facilities. If an issue does not transfer in New York City, but transfers in two or more cities outside of that area, the “ex” date is based on the location of the transfer facilities closest to New York City.
To avoid unnecessary claims for dividends, members receiving deliveries of stocks against “dividend on” transactions, are urged to provide for the early mailing of such stocks which transfer out of town, in order to ensure receipt by the transfer agent by the record date.]
(a) no change
(b) no change
(c) “
A listed company is required to notify its [Corporate Relations Managers]
A company should immediately notify its Corporate Relations Manager whenever it files with the SEC a request for extension of time for the filing of its interim statements on SEC Form 12b-25.]
A listed company is required to file with the Exchange a copy of any amendment to its charter or by-laws (or equivalent documents), as soon as it becomes effective. Such filing must include:
(a)
(b)
The Exchange will require shareholder approval (pursuant to a proxy solicitation conforming to SEC proxy rules) as a prerequisite to approval of applications to list additional shares to be issued in connection with:
(a) a transaction involving:
(i) the sale
(ii) the sale
(b) a transaction which would involve the application of the Exchange's original listing guidelines as described in § 341.
[An] Exchange specialists [is]
Listed companies are required to maintain transfer and registry facilities (including facilities for conversion or exchange) for their listed securities, which are satisfactory to the Exchange. Such transfer and registry facilities may be located in New York City or outside of New York City provided, in each case, that the requirements of Rule 891 of the Board of Governors of the Exchange, set forth below, are met.
Requirements in order to qualify as a Transfer Agent for securities listed on the American Stock Exchange (where the listed Company does not act as its own Transfer Agent) in respect of (i) all Transfer Agents located in New York City, and (ii) Transfer Agents located out-of-town where the listed Company has no Transfer Agent in New York City.
1. Office facilities (hereinafter referred to as the “office”) satisfactory to the Exchange and the issuer to receive and redeliver securities must be located south of Chambers Street in the Borough of Manhattan, City of New York.
2. Routine transfers are to be processed and available for pick-up at the office under normal conditions within 48 hours,
3. The Transfer Agent must assume total responsibility and liability for securities from the time of deposit at the office until delivery at the window. The Transfer Agent must maintain insurance coverage of a least $10,000,000 to protect securities while in transit or in process of transfer, and it must
4. Out-of-town agents having a drop in New York must make appropriate arrangements to pick up from and deliver to Depositary Trust Company normally within the 48-hour period and framework mentioned above.
5. Personnel at the office must have sufficient experience to respond promptly to inquiries regarding transfers, including legal items.
6. Securities received before the close business at the office on a record date or any other date involving the rights of a security holder must be recorded as of the date so as to establish the transferee's rights.
7. Facilities should be available for expediting transfer service when needed. No objection will be made if a reasonable charge is made for such special service.
8. The Exchange reserves the right to request a company with securities listed on the Exchange to terminate the appointment of its transfer agent in the event of failure of such transfer agent to conform to all of the foregoing requirements.
A company is required to cause its transfer agent or agents to enter into an agreement with the Exchange (Listing Form 3 for common stock and Listing Form 5 for warrants) whereby the transfer agent must notify the Exchange 10 days after the close of each calendar quarter of the number of shares outstanding as of the last business day of the calendar quarter for each security listed on the Exchange. The transfer agent must also notify the Exchange if its services are discontinued.
A company is also required to cause its registrar or registrars to enter into an agreement with the Exchange (Listing Form 4) whereby the registrar agrees to notify the Exchange 10 days after the close of each calendar quarter of the number of shares registered for each security listed on the Exchange. A registrar must also notify the Exchange if its services are discontinued.
Transfer and registry agencies maybe maintained in more than one city. However, when shares are transferred in more than one transfer office, the combined amounts of stocks registered in all transfer offices shall not exceed the amount authorized for listing (See also § 829.)
A qualified bank, trust company, listed company or other qualified organization may act in the dual capacities of transfer agent and registrar, provided that it countersigns stock certificates in both capacities. All entities which act in the dual capacity of transfer agent and registrar are required to assure the Exchange that such functions are maintained separately and distinctly with appropriate internal controls, subject to an annual review by the agent's independent auditors which shall be provided to the entity's board of directors.
A listed company acting in the dual capacity of transfer agent and registrar for its own securities shall be required to sign an appropriate agreement with the Exchange to, among other things:
1. maintain offices, staffed by qualified personnel, with adequate facilities for the safekeeping of securities in its possession where transfer and registration may be completed within forty-eight hours;
2. be responsible to indemnify purchasers for any loss arising out of over/under issuance of all securities delivered to, or picked up by, it as agent, until such securities are delivered pursuant to instructions; and
3. maintain the transfer agent and registrar functions as separate and distinct with appropriate internal controls, such controls to be reviewed annually by the company's independent auditors.
If a security is transferred and/or registered at the company's office, the persons who shall be authorized to sign certificates in the capacity of registrar and transfer agent shall be appointed by specific authority of the board of directors and shall not be an officer who is otherwise authorized to sign certificates on the company's behalf.
A company is not permitted to appoint a transfer agent, registrar, or other fiscal agent of a security of the company listed on the Exchange without prior notice to and approval of the Exchange. A registrar must, at the time of its appointment, be acceptable to the Exchange as a registrar for securities listed on the Exchange.
If the transfer books of a company should be closed permanently, the company is required to continue to split-up certificates into smaller denominations in the same name so long as such stock remains listed on the Exchange.
A company applying for the listing (or having listed) registered bonds or debentures on the Exchange is required to maintain in New York City (See § 801) an office or agency, satisfactory to the Exchange, where such bonds or debentures are registerable. In the case of bonds or debentures issued in bearer form, such office or agency must provide for the payment of principal and interest on such indebtedness.
A listed company is permitted to designate an agent, satisfactory to the Exchange, located in or outside New York City, for the payment of dividends, interest and principal (on bonds or debentures), and other payments with respect to a listed security. If, however, checks for such payments are drawn on a bank located outside New York City, additional arrangements must be made for payment against such checks at a bank, trust company or agency located in New York City; and the details of those arrangements disclosed to the payee.
(a)
(b)
(c)
(d)
In addition to complying with the requirements set forth below, companies should submit the following to the Exchange for review and approval:
(a) proofs of a security prior to final printing; and
(b) specimens of the security in final form, printed on the bond paper to be used for the definitive security, accompanied by the banknote company agreement described in § 823. No change in the form of a certificate should be made without the approval of the Exchange.
The face of listed securities (stocks and bonds) must be printed from at least one engraved steel border plate produced by a banknote company whose work is acceptable to the Exchange. The company may, at its option, use a second steel engraved face plate.
The engraved border plate (and engraved face plate, if used) must be original to the banknote company which prepared the security, and the name of such banknote company must appear on the face of all securities and also on the face of coupons and filing panel of each bond.
The border plate shall remain in the permanent possession of the banknote company which produced it. The plate may be used by such banknote company in the production of “controlled stock” securities of more than one company, provided that such securities are prepared in their entirety on the premises of such banknote company, which shall furnish the Exchange with the certificate and agreement described in § 823.
The final specimen submitted to the Exchange must be accompanied by:
(a) a certificate of the banknote company that:
(i) the security has been prepared in accordance with the printing and engraving requirements of the American Stock Exchange; and
(ii) all work done in connection with the preparation and manufacture of the dies, rolls, plates and certificates has been and will be done entirely on the premises of the banknote company, except as may be specifically noted (if there are any exceptions, full details must be given);
(b) an agreement by the banknote company (by its terms binding upon the banknote company, its successors and assigns) that all dies, rolls, plates and other engravings used in connection with the manufacture of certificates of the particular issue will, at all times, be and remain in the possession of the banknote company and, when not actually being used in connection with the manufacture and preparation of certificates, will be kept in a vault on the premises of the banknote company, and all completed certificates of the issue and all certificates in process will, prior to delivery to or upon the order of the issuing company (except when in actual process of manufacture), be kept in such vault. (See Appendix for suggested format.)
The printing of securities must be in distinctive colors to make classes and denominations readily distinguishable.
All paper used for securities must be of an excellent grade of bond paper, of adequate weight and strong enough to withstand the strains and stresses of frequent handling. Stock certificates shall be of the standard size of 8 × 12 inches.
The Exchange has no requirements as to denominations of stock certificates and permits either the sole use of single (unlimited) denomination certificates, or certificates for 100 shares, less than 100 shares and unlimited denominations.
The denomination of 100 shares, less than 100 shares and more than 100 share certificates should be appropriately indicated on the certificate by engraving or surface printing at the option of the company. Companies which do not have a separate certificate for more than 100 shares may alter the certificate for 100 shares or for less than 100 shares by over-printing.
Certificates for other than 100 shares should indicate the exact number of shares by the use of a macerating machine that breaks the paper or a matrix. A company may also use a punchout panel in addition to one of the methods noted above.
The par value of common stock may be eliminated from common stock certificates, except where required by law. Par value may also be eliminated from preferred stock certificates, except where the dividend rate is expressed as a percentage of par value. Where a company elects to eliminate par value from its stock certificates, an opinion of counsel as to legality under applicable state law and the company's charter should be filed with the Exchange. Where par value is shown on certificates, either as the result of legal requirements or a company's preference, it may be surface printed rather than engraved.
If the stock certificates of a company do not recite the preference of all classes of its stock, the company is required to furnish to its shareholders, upon request and without charge, a printed copy of preferences of all classes of its stock. A reference to the availability of such copy should appear on such certificates.
When shares are transferred in more than one transfer office, certificates should be interchangeably transferable and identical in color and form, except as to names of transfer agent and registrar, and the certificates shall bear a legend naming all cities in which they may be transferred.
A company is required to have on hand at all times a sufficient supply of certificates to meet the demands for transfer.
A company is required to issue new certificates for securities listed on the Exchange replacing lost ones immediately upon notification of loss and receipt of proper indemnity.
In the event of the issuance of any duplicate bond to replace a bond which has been alleged to be lost, stolen or destroyed and the subsequent appearance of the original bond in the hands of an innocent bondholder, either the original or the duplicate bond will be taken up and canceled and the company must deliver to such holder another bond theretofore issued and outstanding.
Certificates for listed securities are required to have imprinted thereon the appropriate CUSIP identification number which is provided by Standard & Poor's Corp.
A company is required to report to the Exchange, within ten days after the close of each fiscal quarter, any reacquisition or disposition of its previously issued shares listed on the Exchange made during the quarter. Such reports are to include treasury share transactions for the account of the company, whether direct or indirect, and are to show separate totals for acquisitions and dispositions and the number of treasury shares held by it at the end of the quarter.
A sample form of report is shown below:
Dear Sirs: Pursuant to section 901 of the Company Guide, this is to report that the company effected transactions in shares of its previously issued common stock, $1 par value, during the quarter ended (date), as follows:
A company is not permitted to select any of its listed securities for redemption
Bonds, debentures or preferred stocks issued, or to be issued, under an indenture or charter provision not conforming to this requirement are not eligible for listing on the Exchange.
A company is also required to notify the Exchange promptly of any corporate action which will result in the redemption, cancellation or retirement, in whole or in part, of any of its securities listed on the Exchange, and to notify the Exchange as soon as the company has notice of any other action which will result in any such redemption, cancellation or retirement.
Notices under this section should be directed to the attention of the company's Corporate Relations Manager.
(a)
Since such transactions may involve state and Federal legal considerations, it is recommended that company counsel and officials of the Exchange be consulted prior to effecting a proposed repurchase of listed securities above the market.
It is the policy of the Exchange to make such reports available to the public in its library. In addition, the Exchange may require the company to issue a public announcement and a notice to its shareholders regarding such repurchase.
(b)
Companies planning to repurchase their securities in the marketplace, should consult with their Corporate Relations Manager (whether or not they plan to rely on the safe harbor of the Rule) to ascertain the appropriate disclosure necessary for the maintenance of a fair and orderly market.
(c)
(d)
Inasmuch as a tender offer may significantly affect the market for or the continued listing eligibility of the security, the company should consult with its Corporate Relations Manager prior to the announcement and commencement of such offer.
(e)
(i) the use of a retroactive record date (
(ii) the tender offer should remain open for a sufficient period of time to provide all odd-lot holders with ample opportunity to participate; and
(iii) since many odd-lot holdings are in “street” or nominee names, the company should provide a mechanism which allows its beneficial holders to participate equally with record holders. In this connection, a company may wish to consider the following:
(A) a “broker guarantee” provision which permits the tender of odd-lot holdings that are not readily available for physical delivery within the tender period;
(B) a requirement that holders of record tendering on behalf of a beneficial owner confirm to the company that the securities tendered represent the beneficial owner's entire holdings of that security.]
From time to time, company officials inquire about Exchange rules or regulations affecting their relationship to the registered specialist in their securities.
(a)
(b)
(c)
A company may make available to the specialist whatever information it has provided to its stockholders, security analysts or the general public, such as specific data and information concerning general trends relating to the company's business, as well as industry and general economic developments that may influence the company's welfare. It is improper, however, to furnish to the specialist any material information not previously released to the public regarding such matters as earnings, forecasts, anticipated dividend action, a proposed stock split, merger negotiations or any other undisclosed matter which is likely to have a significant effect on the price of the company's securities or influence investment decisions.
While it is not contemplated that a company will be in continuous contact with its specialist, the specialist may from time to time inform company officials of unusual market problems and respond to broad questions about the market in the company's stock. The restrictions imposed on [a] specialist
Within this framework, company officials and specialists should feel free to call upon each other so that a mutually beneficial understanding of the problems encountered by each is fostered.
(d)
With respect to any security in which a specialist is registered, Exchange rules prohibit [the] specialist
(i) disclosing, at any time, to any person other than a Floor Official or authorized Exchange Official, any information in regard to orders entrusted to the specialist or the name of a buyer or seller except as may be necessary solely for the purpose of processing a transaction; however, that when requested by a member, member organization, or representative of the issuer of the security involved, [the] specialist
(ii) effecting transactions for [his]
(iii) acquiring, holding or granting an option in any such security;
(iv) being an officer or director of the issuer of any such security;
(v) nominating, directly or indirectly, any person to be on the board of directors of the issuer of any such security;
(vi) effecting, directly or indirectly, any business transaction with the issuer of any such security or any officer, director or 10% stockholder of any such issuer;
(vii) accepting an order for the purchase or sale of any stock directly from the company issuing such stock; from any officer, director or 10% stockholder of that company; from any pension or profit-sharing fund; or from any bank, trust company, insurance company, investment company, or similar institution;
(viii) soliciting any proxy, directly or indirectly, on behalf of [himself]
(ix) voting, directly or indirectly, in any proxy contest involving any such security in which [he]
With respect to any security in which a specialist is registered, Exchange rules require the specialist to report to the Exchange:
(i) unusual activity or price change:
(ii) information which may materially affect the business or financial structure of the issuer of, or the market for, such security;
(iii) the existence of options or selling agreements;
(iv) any unusual transaction in which the specialist participates as a broker or dealer; and
(v) each purchase and sale for the specialists' own account.
[(e)
A company proposing to change its name should:
(c) As soon as the change in name has been approved by shareholders, notify the Exchange [(by telephone or telex)] of the time when the amendment to the charter will be filed and the change in name will become effective. Confirm this advice by letter.
(e) Notify the Exchange [(by telephone or telex)] as soon as the amendment has actually been filed and confirm this advice by letter.
[(f) As soon as available, furnish the Exchange with a copy of the amendment to the charter covering the change in name certified as to its filing by the office of the Secretary of State. A specimen copy of each denomination of the stock certificates on which the change in name is reflected (in the form in which such certificates will be issued against transfers after the effective date of the change in name) should also be furnished.]
A company that changes the par value of a stock issue listed on the Exchange,
[(d) Immediately after the filing of the charter amendment, the company must furnish the Exchange with the following documents:
(i) A copy of the Certificate of Amendment of the charter effecting the change in par value, certified by the Secretary of State or corresponding authority.
(ii) Specimens of all denominations of the new or changed form of stock certificates reflecting the change in par value. It is advisable to furnish these prior to the filing of the charter amendment.
(iii) Opinion of counsel of satisfactory standing: (A) as to the legality of authorization of the change and the validity of the new par value shares resulting from such change; (B) that the new par value shares are validly issued, fully-paid and non-assessable; and (C) that no personal liability attaches to ownership thereof. If such counsel or any partner of such, counsel (or, if a firm, any member thereof) is an officer, director or shareholder of the company, this fact should be stated in the opinion.]
Copies of new or revised rules, policies, or forms, adopted subsequent to the date of this Guide, will be distributed, following their adoption. Questions concerning new materials, as well as materials contained in this Guide, should be directed to a company's assigned [Corporate Relations manager]
A company having a security listed on the Exchange and registered under Section 12(b) of the Securities Exchange Act of 1934 is required to file information, documents and reports with the SEC (or other appropriate regulatory agency) on a timely basis and file original or conformed copies with the Exchange. With the exception of annual reports to shareholders, which must continue to be filed with the Exchange in hard copy, a company which submits such material electronically to the SEC will be deemed to have satisfied this requirement.
The Exchange also requires timely notice and written confirmation of certain additional information, including proposed amendments to and certified copies of the Certificate of Incorporation, By-laws or other similar organization documents and all material sent to shareholders or released to the press. A summary guide to the Exchange's filing requirements following:
The Exchange established the Emerging Company Marketplace to accommodate the listing of companies, domestic or foreign, which are too small to qualify for regular listing. In May 1995 the Exchange determined to discontinue the list of new companies on the ECM. Companies which were listed on the ECM at that time were permitted to continue listed there, subject to all the rules applicable to ECM issues.
In addition to satisfying the assets, equity and price criteria set forth in A above, the company must (i) appear to be in a financial position sufficient to satisfactorily service the dividend requirements for the issue, and (ii) have at least 100,000 preferred shares publicly held (as defined in A above) with an aggregate market value of at least 2,000,000.
The Exchange will not list convertible preferred issues containing a provision which gives the company the right, as its discretion, to reduce the conversion price for periods of time, or from time to time, unless the company establishes a minimum period of ten business days within which such price reduction will be in effect.* The Exchange also will not consider listing a convertible preferred issue unless the underlying common stock meets all the criteria set forth in Part A above.
The Exchange strongly recommends that each preferred issue listed on the ECM be structured so as to comply with the voting requirements of Section 124 of the Company Guide.
The listing of warrant issues is subject to all of the numerical criteria set forth in Part A, except for those with respect to price and market value. However, the Exchange will not consider listing warrants exercisable into common stock unless such common stock meets all the criteria set forth in Part A above.*
The Exchange will not list warrant issues containing provisions which give the company the right, at its discretion, to reduce the exercise price of the warrants for periods of time, or from time to time, during the life of the warrants, unless the company establishes a minimum period of ten business days within which such price reduction will be in effect. This policy will not preclude the listing of warrant issues for which regularly scheduled and specified changes in the exercise price have been previously established.
Whenever a company having warrants listed on the Exchange effects a split of 3-for-2 or greater in the underlying shares, the Exchange requires that a corresponding split be made in the warrants.
Companies applying for listing of bonds or debenture issues are expected to meet the following criteria:
(a) The company appears to be in a financial position sufficient to satisfactorily service the debt issue to be listed and meets the assets and stockholders' equity criteria set forth in A above.
(b) Listing will be limited to debt securities of at least $5 million in principal amount/aggregate market value.
(c) The Exchange will not list convertible debt issues containing a provision which gives the company the right, at its discretion, to reduce the conversion price for periods of time, or from time to time, unless the company establishes a minimum period of ten business days within which such price reduction will be in effect.* The Exchange also will not consider listing a convertible debt issue unless the underlying common stock meets all the criteria set forth in Part A above.
The Exchange may list units comprised of one or more of the securities enumerated above provided that each of the component parts of the unit would otherwise separately satisfy the applicable listing requirements.
A company is not permitted to select any of its listed securities for redemption otherwise than pro rata or by lot, and is required to notify the Exchange at least 15 days in advance of any redemption and to furnish it promptly with any information requested in connection with the redemption.
A company which satisfies the original listing criteria may apply for a confidential preliminary listing eligibility opinion which will be furnished without charge as described in § 202.
There is a one-time original listing fee of $5,000 which is inclusive of all issues which become listed on the ECM. In addition, an annual fee shall be payable, as provided by § 141.]
Continued listing on the Exchange is dependent upon compliance with the following numerical criteria:
no change
In addition to satisfying the assets, equity, market value and price criteria set forth in A above, the company will be subject to
Warrant issues must satisfy all the numerical criteria set forth in Part A, except those with respect to price and market value. In addition if the warrants are exercisable into common stock, the warrants are subject to delisting if the common stock is not in compliance with the numerical criteria set forth in A above.
Continued listing on the Exchange for bond and debenture issues is dependent upon compliance with the criteria specified in §§ 1003 (b)(iii) and (e) of the
Continued listing on the Exchange of units comprised of one or more of the securities enumerated above is dependent upon compliance by each component part of the unit with the applicable criteria enumerated above.
Companies with a deficiency in market value or price for 10 consecutive trading days shall have 90 days thereafter in which to comply with the continued listing requirements. Companies with a deficiency in any other criteria shall be immediately subject to delisting in accordance with the procedures set forth in § 1010 of the Company Guide.
In addition, the Exchange shall delist any issue which “ceases to be an Eligible Security” pursuant to Section VI(c)(iii) of the Consolidated Tape Plan, and the issues of any company which fails to take appropriate steps to ensure that no ECM-listed securities are sold in its behalf in reliance upon the exemption from state securities registration which is otherwise available to companies listed on the Exchange.
(1) Comply with all Exchange rules, policies and procedures which apply to listed companies as they are now in effect and as they may be amended from time to time, regardless of whether the company's organization documents would allow for a different result.
(2) Notify the Exchange, at least 20 days in advance, of any change in the form or nature of any listed security or in the rights, benefits and privileges of the holders of such security.
(3) File with the Exchange (i) proposed amendments to and certified copies of the Certificate of Incorporation; By-Laws or other similar organization documents; (ii) all SEC filings; and (iii) all material sent to shareholders or released to the press.]
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In its filing with the Commission, the Exchange included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
Due to the merger between the National Association of Securities Dealers (“NASD”) and the Amex, the qualifications functions for the Nasdaq Stock Market (“Nasdaq”) and the Amex have been centralized in the Nasdaq-Amex Listing Qualifications Department (“Listing Qualifications”). As a result of this centralization, a number of Exchange rules have been reviewed with the goal of modernizing the Exchange's initial and continued listing process, creating consistent rules and processes across all of the NASD's marketplaces, and reflecting the current business practices and procedures used by Listing Qualifications. This filing addresses those goals and makes other non-substantive changes to reflect changed job titles
Currently, Exchange rules encourage issuers to obtain an informal opinion from Amex staff, known as the Preliminary Listing Eligibility Opinion (“PLEO”), as to whether the issuer is eligible to list before formally applying to the Exchange. Because of the time involved for the issuer to prepare for this extra review and for staff to conduct this extra review, the PLEO process causes a delay in the time it takes for a final determination to be made on an issuer's application for listing on the Exchange. This process is also inconsistent with the Nasdaq process in which an application is filed at the outset of the process. As a result, when an issuer initially pursues listing on both markets, the issuer faces a delay in its ability to make a decision as to where to list. In order to streamline the application process, the Exchange proposes to eliminate the PLEO process. Accordingly, the Exchange proposes to delete Sections 202 and 203 of the Listing Standards, Policies and Requirements and modify Sections 101, 130, 201 and 211 to eliminate references to the PLEO process. Under the proposed revision, issuers will only file their completed listing application with the Exchange's staff.
In addition, Exchange rules currently require a number of documents to be submitted with an original listing application. The Exchange proposes to eliminate certain requirements, including the Exchange's Listing Form 2 (Certificate of Distribution), Charter, By-Laws, Specimen Certificates, Trustee Certificates, Form for Indenture, Board Resolutions and certain contracts. Many of these documents are electrically available through an Issuer's public filings, or they are generally available to Listing Qualifications through other means (or upon request by Exchange staff from the issuer). Therefore, the Exchange proposes to remove these general requirements and instead request specific documents as necessary.
Similarly, the Exchange proposes that issuers no longer be required to obtain an opinion of counsel which, among other things, relates to the legality of the organization and existence of the issuer and the validity of the securities to be listed. These rules were originally enacted to prevent unauthorized securities from entering into the market and to protect the Exchange from legal liability, which might arise from the listing and trading of such securities. Today, however, such concerns are unwarranted. In particular, an issuer's independent auditor reviews the issuance of securities as part of its annual audit and, generally, legal comfort is provided to market participants with respect to most securities issuances, including public offerings. Furthermore, the Exchange is largely protected from legal claims against it by its status as a self-regulatory organization and no
The Exchange currently requires an application to be submitted by an issuer whenever a shareholder rights plan is established and the underlying rights are registered with the Commission. These rights, commonly known as “poison pills,” technically constitute a separate security but trade in tandem with an as part of the issuer's common stock. Upon the occurence of a “triggering” such as the announcement of a hostile takeover or the acquisition of a specified percentage of the company's outstanding common stock, the rights would detached from the common stock and become freely tradable as separate securities. At that point, under Exchange rules, the issuer is required to file a listing application with respect to those new securities. Given the listing application requirement upon the occurrence of a triggering event and the fact that until that time the securities are not traded as separate securities, the Exchange believes the requirements of Section 343 are not necessary.
Sections 104 and 105 of the Listing Standards allow the listing of debt and warrants on the Amex, but only if the issuer is listed on the Amex or the New York Stock Exchange (“NYSE”. This rule is no longer necessary or appropriate, given the level of the listing standards on Nasdaq in comparison to those of the Amex and the NYSE. The Exchange therefore proposes to expand the issues which may be listed on Amex to include debt and warrants of issuers listed on Nasdaq.
Sections 112, 115, and 116 of the Listing Requirements impose more stringent standards on specific types of issuers: exploration and development companies, member corporations, and companies engaged in gaming operations. These rules arose when such companies generally remained private and the listing of companies in such sectors was fairly unusual. The Exchange proposes to eliminate these sector-specific sections since the listing of securities of issuers in these sectors is now fairly common across all markets and issuers in these sectors now operate in highly regulated environments. Specifically, with respect to exploration and development companies, the Exchange notes that detailed disclosures about the issuer's stage of development and prospects are provided to potential investors in required, publicly filed reports. Accordingly, the Exchange does not believe it is appropriate to discriminate against such exploration stage companies seeking to raise capital on the Exchange. With respect to member corporations, the Exchange notes that these issuers are regulated by both the Commission and the membership organization to which the issuer belongs. Finally, with respect to companies engaged in gaming operations, the Exchange notes that these issuers operate in a highly regulated environment and are subject to substantial state and/or federal regulation. Furthermore, the Exchange notes that under its discretionary authority over all issuers, pursuant to Section 101, it has authority to deny listing to issuers based on sector-specific issues in appropriate situations. Accordingly, the Exchange does not believe that the specific rules relating to issuers in these sectors are necessary or appropriate.
The Exchange also proposes to clarify that the alternate listing guidelines contained in Section 101 of the Listing Standards are not limited to issuers in certain sectors. The alternate guidelines were first adopted in 1977 and then modified in 1986 to allow a broader range of companies to qualify. The guidelines referenced as examples, companies that were unable to satisfy the basic criteria due to significant research and development or other similar business development costs. The Exchange proposes changes to Section 101 to clarify that the numerical aspects of the alternate guidelines apply to all issuers, regardless of industry. This change would be consistent with the approach used on Nasdaq, SmallCap Market, and the NYSE, where alternative listing requirements are available to all issuers that meet the quantitative requirements.
Section 144 of the Listing Standards currently imposes a $250 non-refundable service charge that is subtracted from any refund otherwise due an issuer that is not approved for listing or that withdraws after completing the application process. Given the cost incurred by the Exchange in reviewing an application, the Exchange proposes to raise the non-refundable portion of the initial inclusion fee from $250 to $1,000 and to require the payment of this amount in advance of processing the application, in order to timely recoup such costs, especially in situations where these costs are incurred by the Exchange and the application is then withdrawn. The Exchange notes that this proposed change will not affect the listing fees paid by issuers who ultimately list on the Exchange and that this practice is consistent with that followed by Nasdaq. In addition, the Exchange notes that if an issuer applies for listing on both the Exchange and on Nasdaq, only a single $1,000 non-refundable fee would be collected for review of both applications.
The Exchange also proposes to modify the treatment of treasury shares for fee purposes. Under existing Section 141, Amex listing fees are based on all shares outstanding, including treasury shares. The Exchange proposes to modify Section 141 to excluse treasury shares when calculating shares outstanding for fee purposes
Finally, as discussed above, because the Exchange proposes to eliminate Section 343, requiring the submission of an application upon the creation of a shareholder rights plan, the Exchange also proposes to modify Section 140, to eliminate the $1,000 fee associated with the shareholder rights plan application.
The Exchange proposes to eliminate several archaic rules that require additional time between the declaration and dividend date for dividends of issuers that do not have transfer facilities in the New York City area. Given the current state of communication networks and electronic interaction between issuers, transfer agents and investors, these additional time periods are no longer necessary. Accordingly, the Exchange proposes to modify Sections 502, 512, and 521 and to eliminate Section 520 to implement this proposed change.
Likewise, the Exchange proposes to remove a variety of rules concerning the qualification of Transfer Agents, Registrars, and Bond Trustees presently contained in Sections 801-811. The Commission regulates the transfer agent industry and, since 1976, has imposed a series of rules over the industry
The Exchange also proposes to remove requirements relating to the form of securities and lost security holders. The rules relating to the form of securities are antiquated and may impede the use of innovations in this area, such as DTC holdings and book entry methods. Furthermore, the Exchange notes that there are no comparable rules on Nasdaq. Accordingly, the Exchange proposes
Existing Exchange rules require an issuer to report changes in the number of treasury shares. Given the changes proposed to the fee calculation for issuers, resulting in the exclusion of treasury shares from the fee base, the Exchange no longer needs this information. Accordingly, the Exchange proposes to eliminate Section 901 of the Listing Standards. Furthermore, Section 903, on repurchases of listed company securities, in unnecessary because it does not impose any Exchange requirements, but merely refers issuers to federal securities laws. Finally, the Exchange notes that Section 902 allows an issuer to redeem securities only in a
The Exchange proposes certain changes to the listing requirements for issuers listed on the Amex. The Exchange proposes to change the definition of “public distribution” and “public shareholders” as defined in Section 102. Currently, in determining the number of shares in the public, Exchange rules exclude concentrated holdings of 5% or greater. The comparable rules on Nasdaq, as well as the NYSE, only exclude holdings of 10% or greater. The Exchange believes that it is appropriate to exclude holdings of between 5% and 10% from the definition of public distribution and accordingly, proposes to modify Section 102.
Next, the Exchange proposes to modify Section 120, relating to conflicts of interest. The existing Exchange rule states that the Exchange will consider conflicts situations in connection with the original listing of an issuer. The Exchange believes that a broader, ongoing review of related party transactions is appropriate and that the issuer's Audit Committee (or a comparable body) is an appropriate body for conducting such a review. Furthermore, the Exchange notes that under the proposed change, as in all cases, it may review a transaction using the Exchange's general discretionary authority if a transaction involved a conflict that raised public interest concerns. Accordingly, the Exchange proposes to adopt this revised listing requirement to better protect investors.
The Exchange also proposes to amend its rules relating to shareholder approval contained in Section 713 to clarify that shareholder approval is required prior to issuance of a security that has the
In May 1995, the Exchange determined to discontinue the listing of new companies on the Emerging Company Marketplace and subsequently received Commission approval.
The Exchange believes that the proposed rule change is consistent with Section 6(b)(5) of the Act,
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the Act.
The Exchange did not solicit or receive written comments on the proposed rule change.
Within 35 days of the date of publication of this notice in the
(A) by order approve such proposed rule change, or
(B) institute proceedings to determine whether the proposed rule change should be disapproved.
Interested persons are invited to submit written data, views and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Persons making written submissions should file six copies thereof with the Secretary, Securities and Exchange Commission, 450 Fifth Street, NW, Washington, DC 20549-0609. Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for inspection and copying in the Commission's Public Reference Room. Copies of such filing will also be available for inspection and copying at the principal office of the Amex. All submissions should refer to the File No. SR-Amex-99-39 and should be submitted by March 2, 2000.
On September 1, 1999, the American Stock Exchange LLC (“Amex” or “Exchange”) submitted to the Securities and Exchange Commission (“SEC” or ‘Commission”) pursuant to Section
The Amex proposes to delete Exchange Rule 106, “Substitute Principals.” Exchange rule 106 currently provides that: “No party to a contract shall be compelled to accept a substitute principal unless the name proposed to be substituted was declared in, and as part of, the bid or offer giving rise to the contract.” Rule 106 dates back to the 1921 Constitution of the New York Curb market,
For the reasons discussed below, the Commission finds that the proposed rule change is consistent with the Act and the rules and regulations under the Act applicable to national securities exchange. In particular, the Commission believes the proposed rule change is consistent with the Section 6(b)(5)
Since Exchange Rule 106 was adopted in 1921 the process of clearance and settlement has evolved. Broker-dealers no longer compare individual trades as was the case at the time of the inception of Exchange Rule 106. Today, trades executed on the Amex are required to be cleared and settled through a registered clearing agency.
Clearing agencies perform comparison, clearance, and settlement of trades. Clearance activities confirm the identity and quantity of the security being bought or sold, the transaction price and date, and the identity of the buyer and the seller, Settlement is the fulfillment, by the parties to the transaction, of the obligations of the trade.
The largest clearing agency is the National Securities Clearing Corporation (“NSCC”), which acts as the contraside to every trade it processes. The NSCC guarantees the trades of its member participants and incurs the risk of default from the time of the guarantee until the settlement of obligations and payments. Thus, it is the NSCC and not the Exchange member—as was the case in 1921—who assumes counterparty risk. When the NSCC guarantees a trade, it becomes the buyer to every seller and the seller to every buyer. As a result, the clearing corporation incurs the risk that a counterparty to a transaction might default on its obligations.
Rule 106 was adopted in another era, prior to the utilization of modern clearing practices. The total assumption of default risk by clearing agencies has obviated the need for Exchange members to maintain strict control over the identify of trading counterparties. Because clearing corporations like NSCC eliminate the risk of trade default, trades are guaranteed irrespective of the identity of a counterparty. Thus, in light of clearance corporations and modern clearance and settlement practices, Rule 106 no longer serves the purpose of protecting a counterparty from the default risks associated with a trade.
Furthermore, Rule 106 may have the disruptive effect of permitting parties to Exchange contracts to break trades without appropriate justification. This kind of action is contrary to the goals of preserving the public's interest and protecting investors. The Commission therefore believes it is appropriate for the Exchange to rescind Rule 106.
For the Commission, by the Division of Market Regulation, pursuant to delegated authority.
On June 16, 1998, the Chicago Board Options Exchange, Inc. (“CBOE” or “Exchange”) submitted to the Securities and Exchange Commission (“SEC” or “Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Commission received two comments on the proposed rule change.
The CBOE proposes to amend its rule governing the execution of orders by order book officials (“OBO”) or designated primary market makers' (“DPM”) book staff to provide for the electronic execution of certain orders on the “live ammo” screen. The proposal will allow an OBO or a DPM to designate orders to be electronically executed against market makers standing in the crowd.
Currently, an OBO or a DPM, acting in his or her capacity as an OBO,
The “live ammo” screen, which is an undisplayed portion of the EBook, receives for further processing orders that are market orders or limit orders that improve the market. An order may be routed to the live ammo screen under a number of circumstances. First, if a customer submits a cancel/replace market order to cancel and replace an order already displayed by the Book, the replacement market order will automatically be routed to the live ammo screen rather than returning directly to the displayed portion of the EBook. Second, if a customer submits a cancel/replace limit order and the replacement order has a limit price that betters the same-side market quote for an order displayed on the EBook, the replacement order will automatically be routed to the live ammo screen. Third, market orders received through the Exchange's “order shoe” that are manually booked are automatically routed to the live ammo screen. Fourth, limit orders that better the same-side market quote that are received through the order shoe and that are manually booked are automatically routed to the live ammo screen. Fifth, limit orders that better the same-side market quote and that are routed directly to the book when the routing parameters have been set at “O” are automatically sent to the live ammo screen.
Orders sent to the live ammo screen are either traded manually in open outcry or sent to the EBook if book eligible, by either the OBO or the DPM, as the case may be.
To address this problem and accelerate the process of executing orders that are on the live ammo screen, the Exchange proposes to implement a new feature created for the live ammo screen, which will allow the OBO (or DPM) to send RAES-eligible orders on the live ammo screen to RAES for automatic execution. Under the proposal, the OBO (or DPM) may select all or any portion of the orders displayed on a live ammo page to be routed to RAES.
As proposed, there may be instances when a RAES-eligible live ammo order may be executed before a non-RAES-eligible live ammo order that was received earlier. Therefore, the Exchange proposes to implement this live ammo to RAES feature notwithstanding the provisions of CBOE Rule 6.45. CBOE Rule 6.45 gives priority to some bids and offers, because they were made earlier in time, over other bids and offers.
The Commission received two comments on the proposal both of which expressed their support.
After careful review, the Commission finds that the proposed rule change, as amended, is consistent with the requirements of the Act and the rules and regulations thereunder applicable to a national securities exchange.
The Commission believes that the proposed rule change should help in providing timely executions of orders on the live ammo screens of the CBOE's EBook. Currently, the OBO (or DPM) must individually represent orders that are displayed on the live ammo screen in the crowd. In periods of high volume or volatility, the OBO (or DPM) may not be able to manually represent these live ammo orders in a timely fashion. According to the Exchange, these marketable orders may stay on the live ammo screen for up to 30 minutes, during which time the market could move significantly away from the market that was quoted at the time the order was routed to the live ammo screen. Thus, investors currently may not be receiving the best price on the CBOE floor when their orders are placed on the live ammo screen.
To address this problem, the Exchange is proposed to implement a new mechanism of the live ammo screen, which will allow the OBO (or DPM) to send RAES-eligible orders to RAES for automatic execution. This feature should help to address the problem of orders being left on the live ammo screen for long periods of time when the OBO (or DPM) is unable to manually represent the live ammo orders in a timely fashion. As a result, customer orders routed to the live ammo screen should receive more timely executions during periods of high volume or volatility on the Exchange. Although non-RAES eligible orders may be executed out of time priority under the proposal, the Commission is hopeful that the proposed rule change will enhance the timely processing of all live ammo orders. That having been said, however, the Commission is concerned that the continued use of the live ammo screen may unfairly disadvantage customer orders. As a result, the Commission is approving this proposal as an interim measure to provide the Exchange with the time to make modifications to its order processing systems to improve the handling of customer orders that currently are routed to the live ammo screen. In particular, the Commission expects that the Exchange will make the necessary systems enhancements to ensure that a maximum number of customer orders in the CBOE system are matched against one another.
Moreover, the Commission expects that the Exchange will develop the necessary systems enhancements to ensure that when there are no opportunities for matching customer orders in the CBOE system, RAES-eligible orders will be routed directly to RAES without the interim step of appearing first on the live ammo screen. The Commission requests that the Exchange submit any proposed rule changes to implement these enhancements by August 31, 2000. The Commission also notes that the Exchange has agreed to provide the Commission with an analysis of the
The Commission finds good cause for approving Amendment No. 6 to the proposed rule change prior to the thirtieth day after the date of publication of notice in the
Interested persons are invited to submit written data, views, and arguments concerning Amendment No. 6, including whether Amendment No. 6 is consistent with the Act. Persons making written submissions should file six copies thereof with the Secretary, Securities and Exchange Commission, 450 Fifth Street, N.W., Washington, D.C. 20549-0609. Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for inspection and copying in the Commission's Public Reference Room. Copies of such filing will also be available for inspection and copying at the principal office of the CBOE. All submissions should refer to File No. SR-CBOE-98-27 and should be submitted by March 2, 2000.
For the Commission, by the Division of Market Regulation, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The CBOE is proposing to make changes to its fee schedule pursuant to CBOE rule 2.40,
In its filing with the Commission, the CBOE included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The CBOE has prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements.
Pursuant to CBOE Rule 2.40, on September 1, 1999, the Exchange's Equity Floor Procedure Committee (“EFPC”) approved the following fees for the following option classes:
These fees went into effect on Thursday, September 2, 1999. All of the option classes above are currently multiple listed on at least one other exchange. The most recent certification for multiple listing relates to options on The Boeing Company (BA) (“Boeing”), which were listed on the Pacific Exchange (“PCX”) beginning on September 2, 1999. All of the market-maker surcharge fees, except those applicable to Boeing, reflect reductions in former market-maker surcharge fees imposed pursuant to Exchange Rule 2.40.
With respect to options on Boeing, CBOE Rule 2.40(e) requires that an option be listed for trading on another exchange before a market-maker surcharge fee can be assessed. Boeing has been certified by the Options Clearing Corporation to be listed on the PCX. Therefore, the CBOE began assessing the market-market surcharge on September 2, 1999, when Boeing was first listed on the PCX.
The CBOE represents that the market-maker surcharge fees were effective from September 2, 1999 until the options at issue were designated to DPMs—September 7, 1999 for FGI, NAQ, OQM, QOL, QSI, SNV, WHC, and ZBQ, and September 13, 1999 for BA. The fees were eliminated when the options were designated to DPMs.
The proposed rule change is consistent with Section 6(b) of the Act,
The Exchange does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act.
The Exchange did not solicit or receive written comments on the proposed rule change.
Because the foregoing rule change establishes or changes a due, fee, or other charge imposed by the Exchange, it has become effective pursuant to Section 19(b)(3)(A)(ii) of the Act,
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Persons making written submissions should file six copies thereof with the Secretary, Securities and Exchange Commission, 450 Fifth Street, NW., Washington, DC 20549-0609. Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for inspection and copying in the Commission's Public Reference Room. Copies of such filing will also be available for inspection and copying at the principal office of the CBOE. All submissions should refer to the File No. SR-CBOE-99-52 and should be submitted by March 2, 2000.
For the Commission, by the Division of Market Regulation, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934
The Board has filed proposed amendments to MSRB Rules G-8, on books and records, G-9, on record retention, and G-27, on supervision (hereinafter referred to as the “proposed rule change”). The proposed rule change will revise the Board's supervision and record retention rules to provide dealers with flexibility in developing reasonable procedures for the review of correspondence with the public. The amendments are intended to recognize the growing use of correspondence sent and received in electronic format while still providing for effective supervision. The Board has also filed with the Commission a draft notice that will provide guidance to dealers on how to implement these rule changes. The proposed rule change and accompanying notice are modeled after and designed to conform to the rules and guidance of the National Association of Securities Dealers (“NASD”). The text of the proposed rule change is set forth below. Additional are italicized and deletions are bracketed.
(a) Description of Books and Records Required to be Made. Except as otherwise specifically indicated in this rule, every broker, dealer and municipal securities dealer shall make and keep current the following books and records, to the extend applicable to the business of such broker, dealer or municipal securities dealer:
(i)-(xix) No Change.
(xx)
(b)-(f) No Change.
(a) No Change.
(b) Records to be Preserved for Three Years. Every broker, dealer and municipal securities dealer shall preserve the following records for a period of not less than three years:
(i)-(vii) No Change.
(viii) the following records, to the extent made or received by such broker, dealer or municipal securities dealer in connection with its business as such broker, dealer or municipal securities dealer and not otherwise described in this rule:
(A)-(B) No Change.
(C) all written
(D)-(E) No Change.
(ix)-(xiii) No Change.
(a)-(b) No change
(c) Written supervisory procedures. Each dealer shall adopt, maintain and enforce written supervisory procedures reasonably designed to ensure that the conduct of the municipal securities activities of the dealer and its associated persons are in compliance as required in section (a) of this rule. Such procedures shall codify the dealer's supervisory system for ensuring compliance and, at a minimum, shall establish procedures
(i)-(vi) No change
(vii) for the prompt review and written approval by a designated principal of:
(A) the opening of each customer account introduced or carried by the dealer in which transactions in municipal securities may be effected;
(B) each transaction in municipal securities on a daily basis, including each transaction in municipal securities effected with or for a discretionary account introduced or carried by the dealer [; and
(C) all correspondence pertaining to the solicitation or execution of transactions in municipal securities].
[(d)]
In its filing with the Commission, the Board included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Board has prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements.
In May 1996, the Commission issued an Interpretive Release on the use of Electronic Media by the Broker-Dealers,
On December 31, 1997, the Commission approved proposed rule changes filed by the NASD
Most of these rules became effective on April 7, 1998.
As amended, NASD Rule 3010(d)(1) provides that procedures for review of correspondence with the public relating to a member's investment banking of securities business be designed to provide reasonable supervision for each registered representative, be described in an organization's written supervisory procedures, and be evidenced in an appropriate manner.
NASD Rule 3010(d)(2), as amended, requires each member to develop written policies and procedures for review of correspondence with the public relating to its investment banking or securities business tailored to its structure and the nature and size of its business and customers. These procedures must also include the review of incoming, written correspondence directed to registered representatives and related to the member's investment banking or securities business to properly identify and handle customer complaints and to ensure that customer funds and securities are handled in accordance with dealer's procedures.
The Board has determined to adopt substantially similar rule changes. The Board believes that conforming its rule language to the language in the NASD rules will help ensure a coordinated regulatory approach to the supervision of correspondence. In addition, in connection with Commission approval of the proposed rule change, the Board will issue a notice to dealers to provide guidance to dealers on how to implement the proposed rule changes. This guidance has been coordinated with NASD NTM 98-11 and NASD NTM 99-03 and is described below.
The proposed amendments to MSRB Rule G-27(d), provide, among other things, that a dealer must establish procedures for the review by a designated principal of each municipal securities representative's incoming and outgoing written (
Currently, MSRB Rule 27(c)(vii)(C) provides that each dealer shall establish procedures for the review and written approval by a designated principal of all correspondence pertaining to the solicitation or execution of transactions in municipal securities. Under the proposed MSRB Rule G-27(d)(ii), a review of each item of correspondence will no longer be required. Dealers will be allowed flexibility in developing procedures for the review of correspondence relating to the dealer's municipal securities activities—both incoming and outgoing, written or electronic—tailored to the nature and size of the dealer's business and customers.
With respect to incoming, written (
The proposed rule change will include amendments to MSRB Rules G-8(a)(xx), G-9(b)(viii) and (xiv), and G-7(d)(i), (ii), and (iii) requiring each dealer to preserve correspondence of municipal securities representatives relating to the municipal securities activities and maintain the records of written supervisory procedures, education and training required under Rule G-27(c) and (d) for three years. The proposed rule change also requires that the names of the persons who prepared and reviewed correspondence must be ascertainable from the retained records and the records must be made available, upon request, to the appropriate enforcement agency (
The notice to dealers will provide guidance on how to implement the proposed rule change. In particular, the notice states that in adopting review procedures pursuant to Rule G-27(d)(i), dealers must:
• Specify, in writing, the dealer's policies and procedures for reviewing different types of correspondence;
• Identify how supervisory reviews will be conducted and documented;
• Identify what types of correspondence will be pre- or post-reviewed;
• Identify the organizational position(s) responsible for conducting review of the different types of correspondence;
• Specify the minimum frequency of the reviews for each type of correspondence;
• Monitor the implementation of and compliance with the dealer's procedures for reviewing public correspondence; and
• Periodically re-evaluate the effectiveness of the dealer's procedures for reviewing public correspondence and consider any necessary revisions.
The notice also states that in conducting reviews, dealers may use reasonable sampling techniques. As an example of appropriate evidence of review, e-mail related to the dealer's municipal securities activities may be reviewed electronically and the evidence of review may be recorded electronically.
In developing supervisory procedures for the review of correspondence with the public pursuant to Rule G-27(d)(ii), the notice states that each dealer must consider its structure, the nature and size of its business, other pertinent characteristics, and the appropriateness of implementing uniform firm-wide procedures or tailored procedures (
The notice also provides guidance on adopting review procedures pursuant to Rule G-27(d)(ii), and states that dealers must, at a minimum:
• Specify procedures for reviewing municipal securities representatives' recommendations to customers;
• Require supervisory review of some of each municipal securities representative's public correspondence, including recommendations to customers;
• Consider the complaint and overall disciplinary history, if any, of municipal securities representatives and other employees (with particular emphasis on complaints regarding written or oral communications with clients); and
• Consider the nature and extent of training provided municipal securities representatives and other employees, as well as their experience in using communications media (although a dealer's procedures may not eliminate or provide for minimal supervisory reviews based on an employee's training or level of experience in using communications media).
In addition, the notice provides that supervisory and procedures must also:
• Provide that all customer complaints, whether received via e-mail or in written form from the customer, are kept and maintained;
• Describe any dealer standards for the content of different types of correspondence; and
• Prohibit municipal securities representatives' and other employees' use of electronic correspondence to the public unless such communications are subject to supervisory and review procedures developed by the dealer. For example, the Board would expect dealers to prohibit correspondence with customers from employees' home computers or through third party systems unless the dealer is capable of monitoring such communications.
The notice also states that the method used for conducting reviews of incoming, written correspondence to identify customer complaints and funds may vary depending on the dealer's office structure. Where the office structure permits review of all correspondence, dealers should designate a municipal securities representative or other appropriate person to open and review correspondence prior to use or distribution to identify customer complaints and funds. The designated person must not be supervised or under the control of the municipal securities representative whose correspondence is opened and reviewed. Unregistered persons who have received sufficient training to enable them to identify complaints and funds would be permitted to review correspondence.
Where the office structure does not permit the review of correspondence
• Forwarding opened incoming, written correspondence related to the dealer's municipal securities activities to a designated office, or supervising branch office, for review on a weekly basis;
• Maintenance of a separate log for all checks received and securities products sold, which is forwarded to the supervising branch office on a weekly basis;
• Communication to clients that they can contact the dealer directly for any matter, including the filing of a complaint, and providing them with an address and telephone number of a central office of the dealer for this purpose; and
• Branch examination verification that the procedures are being followed.
The Board believes that the proposed rule change is consistent with Section 15B(b)(2)(C)
In particular, the Board believes that the proposed rule change is consistent with the Act in allowing dealers to use new technology, such as e-mail and the Internet, while still providing for appropriate supervision and review. In addition, the proposed rule change will make the Board's rules on supervision and record retention substantially similar to the NASD rules. The Board believes that such similar rules by the self-regulatory organizations should facilitate dealer compliance with these requirements.
The Board does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in the furtherance of the Act's purposes because it would apply equally to all brokers, dealers and municipal securities dealers.
Written comments were neither solicited nor received.
Within 35 days of the date of publication of this notice in
(A) By order approve such proposed rule change, or
(B) Institute proceedings to determine whether the proposed rule change should be disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Persons making written submissions should file six copies thereof with the Secretary, Securities and Exchange Commission, 450 Fifth Street, N.W., Washington, D.C. 20549-0609. Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than
For the Commission, by the Division of Market Regulation, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The proposed rule change consists of amendments to existing rules governing error accounts (Rule 134) and a new rule regarding Floor member account disclosure (Rule 407A).
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements.
The Exchange is proposing a series of initiatives to strengthen the regulation of activities of members on the Floor. The initiatives proposed herein consist of amendments to existing rules governing error accounts and a new rule regarding Floor member account disclosure.
At present there is no requirement that a member maintain an error account. The Exchange believes that the amendment to Rule 134 will enhance its ability to monitor and detect potential abuses such as on-Floor trading by members. Error account transaction information will be localized to one place for each member, and not scattered among several accounts which, at present, could be held in the name of another member or member organization.
This would include situations where the execution was wrong (
Alternatively, a customer could accept the error, in which case the transaction would be placed in the customer's account. An error transaction could also be accepted by the specialist in the security into his or her organization's account as a trade “on account of error.”
When a customer accepts an error transaction, a monetary settlement (a “difference check”) may be made by the member or member organization. If the difference check is for more than $500, the member or member organization involved would be required under the proposal to maintain records detailing the transaction. In some instances, a customer may accept an error, but not wish to receive a difference check for bookkeeping or other reasons. The member or member organization involved would be required to maintain records in these situations, as well.
The proposal further prescribes the way a member would be required to
The Exchange stipulates that if the order can be executed on its original terms or on better terms, the member or member organization is expected to execute the order pursuant to its terms, as would typically be the case with a “not held” order. A member representing a “not held” order is not permitted to “miss the market.” and must execute the order pursuant to its terms. The member would not be permitted to simply issue a report out of his or her error account.
The Exchange notes that all members and member organizations would be required under the proposal to maintain details of all errors, profitable or not. For members and member organizations that do not act primarily as a Floor broker, these records would be reviewed in connection with the normal oversight activities of the Exchange.
Purchases of securities of a publicly-traded registered investment company directly from the issuer or principal underwriter would not be considered a reportable securities account. However, interests in a non-publicly-traded investment vehicle, including hedge funds, would be reportable.
The Exchange believes that these reporting requirements would provide it with current information on where members carry securities accounts and enhance its ability to investigate quickly the trading of securities by members of the Exchange.
The Exchange bases the proposed rule change on Section 6(b)(5)
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
The Exchange has neither solicited nor received written comments on the proposed rule change.
Within 35 days of the date of publication of this notice in the
(A) By order approve such proposed rule change, or
(B) Institute proceedings to determine whether the proposed rule change should be disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Persons making written submissions should file six copies thereof with the Secretary, Securities and Exchange Commission, 450 Fifth Street, N.W., Washington, D.C. 20549-0609. Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for inspection and copying in
For the Commission, by the Division of Market Regulation, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“ACT”)
The PCX is proposing to amend its rules on disciplinary proceedings at the Exchange,
Rule 10.1—No change.
Rule 10.2(a). The Exchange
(b) No member or person associated with a member shall impede or delay an Exchange investigation with respect to possible violations within the disciplinary jurisdiction of the Exchange nor refuse to furnish testimony, documentary materials or other information requested by the Exchange during the course of its investigation. Failure to furnish such testimony, documentary materials or other information requested by the Exchange pursuant to this Rule on the date or within the time period required by the Exchange shall be considered obstructive of an Exchange inquiry or investigation and subject to formal disciplinary action.]
[(c) A member or member organization shall submit such trade data elements specified in Commentary .01 below in such automated format as may be prescribed by the Exchange from time to time, in regard to such transaction or transactions as may be the subject of a particular request for information made by the Exchange. Failure to submit such data in the required format shall be considered obstructive of an Exchange inquiry or investigation and subject to formal disciplinary action.]
[(b)]
[(c)]
.01—No change.
[(d)]
.01 The terms “exchange” and “self-regulatory organization,” as used in Rule [10.2(d)]
.02 Any person or entity required to furnish information or testimony pursuant to Rule [10.2(d)]
[Rule 10.4] (Note—Rule 10.4 has been renumbered as Rule 10.5)
Rule [10.3]
The Respondent shall have fifteen business days after service of the charges to file a written answer thereto. The answer shall specifically admit or deny each allegation contained in the charges, and the Respondent shall be deemed to have admitted any allegation not specifically denied. The answer may also contain any defense which the Respondent wishes to submit and may be accompanied by documents in support of his answer or defense. In the event the Respondent fails to file an answer, the charges shall be considered to be admitted.
The time period to file any answer may be extended for such further periods as may be granted by the Exchange, if such request for extension of the filing period is received by the Exchange within five business days prior to the date on which the answer is due.
[Rule 10.5] (Note: Rule 10.5 has been renumbered as Rule 10.4(c))
[Rule 10.4]
(b) Prior to the hearing, the Parties shall be notified of the composition of the Panel. Any objection to the composition of the Panel must be submitted to the Hearing Administrator within five business days of receipt of the notification regarding the composition of the Panel.
(c) At least five business days prior to the hearing the parties shall submit to the Hearing Administrator a list of witnesses and any documentary evidence or other materials to be presented at the hearing. The Hearing Administrator shall immediately furnish such list of witnesses, documentary evidence or other materials to the other parties.
(d) At the hearing, both the Complainant and the Respondent shall be entitled to be heard in person and to present any relevant matter. Any witnesses, testimony or evidence offered by the Complainant or the Respondent shall be subject to cross-examination by the other party. The Panel shall determine all questions concerning the admissibility of evidence and shall otherwise regulate the conduct of the hearing. Formal rules of evidence shall not apply. The charges shall be presented by one or more representatives of the Exchange, who along with Respondent and any other party, may present evidence and produce witnesses who shall testify under oath and are subject to being questioned by the Panel and other parties. The Panel, upon its own motion or the motion of the Complainant or Respondent, may request the production of documentary materials and witnesses. No member or person associated with a member shall refuse to furnish relevant testimony, documentary materials or other information requested by the Panel during the course of the hearing. The Respondent and intervening parties are entitled to be represented by counsel who may participate fully in the hearing. A transcript for the hearing shall be made and shall become part of the record.
(e) Any person not otherwise a party may intervene as a party to the hearing upon demonstrating to the satisfaction of the Panel that he has an interest in the subject of the hearing and that the disposition of the matter may, as a practical matter, impair or impede his ability to protect that interest. Also, the Panel may in its discretion permit a person to intervene as a party to the hearing when the person's claim or defense and the main action have questions of law or fact in common. Any person wishing to intervene as a party to a hearing shall file with the Panel a notice requesting the right to intervene, stating the grounds therefor, and setting forth the claim or defense for which intervention is sought. The Panel, in exercising its discretion concerning intervention, shall take into consideration whether the intervention will unduly delay or prejudice the adjudication of the rights of the original parties.
[(f) Except in writing, with copies to the other parties, neither the Complainant, the Respondent, nor any interested party may discuss with the Panel any matter concerning the facts or allegations in the complaint unless the other parties to the action are given
Rules 10.6-10.14—No change.
In its filing with the Commission, the PCX included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The PCX has prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements.
More specifically, proposed Exchange Rule 10.3(a)(1) provides that unless on adequate notice and reasonable opportunity for all parties to participate, no person who is a subject of a pending Exchange investigation (“Subject”) or a Respondent in a pending disciplinary proceeding, or counsel for or a representative of the Subject or the Respondent, with knowledge of a pending Exchange investigation or disciplinary proceeding, may make or knowingly cause to be made an
Proposed PCX Rule 10.3(a)(2) provides that unless on adequate notice and reasonable opportunity for all parties to participate, no person who is a member of a Hearing Panel or the disciplinary committee with jurisdiction over an investigation or disciplinary proceeding, with knowledge of a pending investigation or disciplinary proceeding, may make or knowingly cause to be made an ex parte communication, as defined below, relevant to the facts or allegations of the investigation or the disciplinary proceeding to: (a) A member of the Board of Governors; (b) a member of the Executive Committee; (c) a person who advises the Board of Governors or the Executive Committee; (d) any member of Exchange Regulatory Staff; or (e) the Subject of a pending Exchange investigation or a Respondent in a pending disciplinary proceeding, or counsel for or a representative of the Subject or the Respondent.
Proposed Rule 10.3(a)(3) provides that unless on adequate notice and reasonable opportunity for all parties to participate, no person who is a member of the Board of Governors or the Executive Committee, or any person who advises the Board of Governors or the Executive Committee, with knowledge of a pending investigation or disciplinary proceeding, may knowingly make or cause to be made an ex parte communication, as defined below, relevant to the facts or allegations of the investigation or the disciplinary proceeding to: (a) Any member of Exchange Regulatory Staff; (b) the Subject of a pending Exchange investigation or a Respondent in a pending disciplinary proceeding, or counsel for or a representative of the Subject or the Respondent; or (c) a member of a Hearing Panel or the disciplinary committee with jurisdiction over the investigation or disciplinary proceeding.
With respect to the disclosure of prohibited communications, proposed PCX Rule 10.3(b) provides that any person who receives, makes or knowingly causes to be made a communication prohibited by this Rule must promptly submit to Exchange Regulatory Staff for inclusion in the record of the investigation or disciplinary proceeding: (1) All such written communications; (2) memoranda stating the substance of all such oral communications; and (3) all written responses and memoranda stating the substance of any oral responses to such communications.
Proposed Exchange Rule 10.3(c) sets forth remedies applicable to situations in which prohibited communications have been made. Specifically, the rule provides that any member, member organization or associated person who made or knowingly caused to be made a communication prohibited by subsection (a) will be subject to disciplinary action. The rule further provides that an Exchange disciplinary committee, to the extent consistent with the interests of justice, may issue to the member organization or associated person responsible for the communication or who benefited from the communication an order to show cause why the claim, defense or interest of the member, member organization or associated person should not be adversely affected by reason of such ex parte communication, including but not limited to the entry of an adverse summary decision. The rule further provides that all parties to a disciplinary proceeding and Exchange Regulatory Staff will be provided with adequate notice and a reasonable opportunity to respond to any allegations or contentions contained in the prohibited communication and any responses will be included in the record of the
Proposed PCX Rule 10.3(d) clarifies that nothing in the rule on ex parte communications prohibits the members of a disciplinary committee or Exchange Regulatory Staff from discussing a pending investigation or disciplinary proceeding at a meeting of the committee in connection with: (1) The adjudication of the investigation pursuant to the Minor Rule Plan; (2) the determination of whether to impose informal discipline; (3) the determination of whether to authorize a complaint or take no further action; or (4) the determination of whether to accept an offer of settlement.
Proposed Commentary .01 to Exchange Rule 10.3 defines an “ex parte communication” as an oral or written communication made without notice to all parties,
Finally, proposed Commentary .02 to PCX Rule 10.3 states that a disciplinary proceeding will be considered to be pending from the date that a Complaint has been issued pursuant to Rule 10.5 until the proceeding, including any appeals, becomes final. This provision will serve to clarify the scope of statements prohibited by PCX Rule 10.3.
With regard to amending outstanding Complaints, proposed PCX Rule 10.4(b) provides that at any time prior to service of the written answer to the Complaint, the Complaint may be amended to allege new matters of fact or law. It further provides that after service of the written answer, the hearing panel may allow amendment of the Complaint upon submission of a written motion by the Exchange and a showing of good cause.
Finally, the Exchange is proposing to adopt new Commentary .01 to new PCX Rule 10.4 to provide that the term “probable cause” means that facts and circumstances establish a reasonable likelihood that the person committed the violation in issue.
The PCX believes the proposed rule change is consistent with Section 6(b)
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
Written comments on the proposed rule change were neither solicited nor received.
Within 35 days of the publication of this notice in the
(A) By order approve the proposed rule change, or
(B) Institute proceedings to determine whether the proposed rule change should be disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Persons making written submissions should file six copies thereof with the Secretary, Securities and Exchange Commission, 450 Fifth Street, N.W., Washington, D.C. 20549-0609. Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for inspection and copying at the Commission's Public Reference Room. Copies of such filing also will be available for inspection and copying at the principal office of the PCX.
All submissions should refer to File No. SR-PCX-99-10 and should be submitted by March 2, 2000.
For the Commission, by the Division of Market Regulation, pursuant to delegated authority.
On December 21, 1998 the Philadelphia Stock Exchange, Inc. (“Phlx” or “Exchange”) submitted to the Securities and Exchange Commission (“SEC” or “Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Exchange Act” or “Act”)
The proposed rule change was published for comment in the
The Phlx proposed to amend Phlx Rule 1001A(a)(i)-(ii) by increasing market index option position limits on the VLE, the TPX, and the XOC.
Exchange exercise limits,
The Commission finds that the proposed rule change is consistent with the requirements of the Act and the rules and regulations thereunder applicable to a national securities exchange, and, in particular, with the requirements of Sections 6 of the Act.
Position limits serve as a regulatory tool designed to address potential manipulative schemes and adverse market impact surrounding the use of options. In the past, the Commission has stated that:
Since the inception of standardized options trading, the options exchanges have had rules imposing limits on the aggregate number of options contracts that a member or customer could hold or exercise. These rules are intended to prevent the establishment of options positions that can be used or might create incentives to manipulate or disrupt the underlying market so as to benefit the options position. In particular, position and exercise limits are designed to minimize the potential for mini-manipulations and for corners or squeezes of the underlying market. In addition such limits serve to reduce the possibility for disruption of the options market itself, especially in illiquid options classes.
In general, the Commission has taken a gradual, evolutionary approach toward expansion of position and exercise limits.
The Commission has carefully considered the Phlx's proposal. At the outset, the Commission notes that it still believes that the fundamental purposes of position and exercise limits are being served by their existence. Nevertheless, the Commission believes that the Phlx's current experience with the trading of market index options
The Commission believes that an increase in position and exercise limits for certain market index options is appropriate for several reasons. The Commission notes first that the proposal is limited to options on three market indexes, the VLE, TPX and XOC. The Commission believes that the capitalization of, and relatively deep, liquid markets for, the underlying securities contained in these indexes significantly reduces concerns regarding market manipulation or disruption in the underlying market.
Second, increasing position and exercise limits for these specific indexes should better serve the hedging needs of institutions that engage in trading strategies different from those covered under the index hedge exemption policy (
Third, the Commission believes that financial requirements imposed by Phlx and by the Commission adequately address concerns that a Phlx member or its customer may try to maintain an inordinately large unhedged position in a market index option. Current margin and risk-based haircut methodologies serve to limit the size of positions maintained by any one account by increasing the margin and/or capital that a member must maintain for a large position held by itself or by its customer.
Fourth, the Commission notes that the index options and other types of index-based derivatives (
Fifth, the Commission believes that Phlx's surveillance procedures will adequately allow it to detect and deter potential trading abuses arising from the increased position and exercise limits for VLE, TPX and XOC options. The absence of any discernible manipulative problems for broad-based index options at existing levels leads the Commission to conclude that the proposed increases are reasonable and that they can be safely implemented. The Commission believes that the Phlx's surveillance program is adequate to detect and deter violations of position and exercise limits, as well as to detect and deter attempted manipulation and other trading abuses through the use of such illegal positions by market participants.
Sixth, the Commission believes that the enhanced reporting requirements should allow Phlx to detect and deter trading abuses arising from the elimination of position and exercise limits for VLE, TPX, or XOC. These reports should also allow Phlx to monitor large positions in order to identify instances of potential risk and to assess additional margin and/or capital charges, if deemed necessary. Specifically, Phlx will subject VLE, TPX, and XOC to a 60,000 contract reporting requirement. Each member or member organization that maintains a position on the same side of the market in excess of these contract thresholds for its own account or for the account of a customer must file a report that includes, but is not limited to, data related to the option position, whether such position is hedged and if so, a description of the hedge. If applicable, the report must contain information concerning collateral used to carry the position. Exchange Registered Option Traders would be exempt from this reporting requirement.
Seventh, the Commission notes that it recently approved proposed rule changes from the Chicago Board Options Exchange (“CBOE”) and the American Stock Exchange (“Amex”), which were even less restrictive than the Phlx's current proposal. Specifically, those proposed rule changes eliminated position and exercise limits on a pilot basis for certain market index options traded on
Finally, the Commission believes it appropriate for the Exchange to eliminate language contained in Phlx Rule 1001A and 1101A, concerning the Big Cap Index (“MKT”) since MKT is no longer traded on the Exchange. The Commission also believes it is appropriate for the Exchange to delete all references to options on the Super Cap Index, as these options were delisted from the Exchange on September 29, 1999.
The Commission finds good cause to approve Amendment No. 1 to the proposed rule change prior to the 30th day after the date of publication of notice of filing thereof in the
Interested persons are invited to submit written data, views and arguments concerning Amendment No. 1, including whether the amendments are consistent with the Exchange Act. Persons making written submissions should file six copies thereof with the Secretary, Securities and Exchange Commission, 450 Fifth Street, N.W., Washington, D.C. 20549-0609. Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for inspection and copying in the Commission's Public Reference Room, located at the above address. Copies of such filing will also be available for inspection and copying at the principal office of the self-regulatory organization. All submissions should refer to File No. SR-Phlx-98-55 and should be submitted by March 2, 2000.
For the Commission, by the Division of Market Regulation, pursuant to delegated authority.
On August 5, 1999, the Philadelphia Stock Exchange, Inc. (“Phlx” or “Exchange”) filed with the Securities and Exchange Commission (“SEC” or “Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Commission published notice of the proposed rule change in the
The Exchange proposes to determine the add-on margin levels for all non-customized Cross-Rate FCOs using the methodology outlined in Commentary .16 to Phlx Rule 722, in lieu of the fixed four percent rate that the Exchange currently uses.
In 1991, the Commission approved the Exchange's proposal to list and trade three non-customized Cross-Rate FCOs—German mark/Japanese yen, British pound/German mark and British pound/Japanese yen options.
Based on the 1991 Order, the Exchange's customer margin
For foreign currency call options, “out-of-the-money-amounts” equal the product of units per foreign currency contract and the closing spot price minus the aggregate exercise price of the option.
Due to an oversight, the Exchange did not file the required analysis of the adequacy of the add-on margin nor the proposed rule change within nine months of the 1991 Order. Following this discovery, the Exchange in 1999 filed a proposed rule change to temporarily codify the four percent add-on margin level while it considered a method of determining add-on margin, on a permanent basis, for all non-customized Cross-Rate FCOs.
On August 5, 1999, the Exchange filed the current proposed rule change to determine the add-on margin levels for non-customized Cross-Rate FCOs using the methodology outlined in Commentary .16 to Phlx Rule 722, in lieu of the four percent rate that the Exchange currently uses.
The Exchange currently uses the Commentary .16 methodology to calculate the add-on margin for standardized FCOs (where the base currency is denominated in U.S. dollars). The Commentary .16 methodology bases the add-on margin percentage for a foreign currency option on the volatility of the foreign currency underlying the option (the “underlying currency”) relative to the “trading currency.”
In particular, the Exchange proposes to review five day price movements of the base currency relative to the underlying currency over the most recent three year period and would set the add-on margin level at a level sufficient to cover those price changes at least 97.5 percent of the time. If subsequent quarterly reviews show that the existing add-on margin level for any non-customized cross-rate FCO currency pair provides a confidence level below 97 percent, the Exchange would increase the add-on margin requirement for that currency pair to a level that would have covered those price movements at a 98 percent confidence level. If a subsequent quarterly review shows a confidence level between 97 percent and 97.5 percent, the add-on margin level would remain the same but would be subject to monthly follow-up reviews until the confidence level exceeds 97.5 percent for two consecutive months (then the Exchange would put it back on the quarterly review cycle). If a monthly follow-up review showed that the confidence level dropped below 97 percent, the Exchange would increase the add-on margin level to a 98 percent confidence level. Generally, if any review shows that the confidence level exceeds 98.5 percent, the Exchange would reduce the add-on margin level to a 98 percent confidence level. But to account for the possibility of unexpectedly large price movements, if any review show that a Cross-Rate FCO currency paid had a five-day price movement, either positive or negative, greater than two times the existing add-on margin level, the Exchange would set the add-on margin requirement for that currency pair to a 99 percent confidence level (“Extreme Outlier Test”). In addition to the routine reviews described above, the Exchange would continue to have authority to impose a higher margin level at any time, if market conditions so warrant.
The Exchange filed an amendment to the proposed rule change on October 26, 1999. The amendment requested that the Commission grant accelerated approval to the amendment so that the Exchange could continue to apply the four percent add-on margin for all Cross-Rate FCO products until February 4, 2000. This would provide additional time for the Commission to consider the proposed rule change, while ensuring that trading of these products would continue following November 4, 1999, when the existing four percent add-on margin would have expired.
Based on the data supplied by the Exchange on October 26, 1999 for the three-year period of July 16, 1996 through July 15, 1999, the Commentary .16 methodology would produce add-on margins for British pound/Deutsche mark and Deutsche mark/Japanese yen non-customized Cross-Rates (which are currently listed on the Exchange) of 3.5 percent and 4 percent, respectively, covering 99 percent and 97.5 percent confidence level, respectively. The British pound/Deutsche mark FCO contract would have been margined at a 99 percent confidence level because the extreme outlier test would have applied. The British pound/Japanese yen Cross-Rate contract, which is currently not listed on the Exchange, would have an add-on margin of 5 percent, covering 97.5 percent confidence level.
Upon careful review, the Commission finds that the proposed rule change is consistent with the requirements of the Act and the rules and regulations thereunder applicable to a national securities exchange.
The Exchange proposes to set the add-on margin based on the five-day price movements (excluding weekends) of the underlying currency relative to the base currency over the most recent three-year period, by setting the add-on margin percentage at a level that would cover those price movements at a specified confidence level, typically 97.5 percent.
The Commission finds that the use of the Commentary .16 methodology to set add-on margins for non-customized Cross-Rate FCOs, in lieu of the fixed four percent requirement the Exchange currently uses, potentially provides a more economically meaningful margin. The currencies involved in the non-customized Cross-Rate FCOs that the Exchange is authorized to list and trade—the British pound, Deutsche mark, and Japanese yen—are all relatively stable currencies and it is reasonable to assume that those currencies' future volatility will be linked to their past volatility. Also, the Exchange has the authority to apply a higher add-on margin than required by the Commentary .16 methodology, when appropriate.
The Commission finds good cause for approving Amendment No. 2 to the proposed rule change prior to the thirtieth day after the date of publication of notice of filing thereof in the
Interested persons are invited to submit written data, views and arguments concerning Amendment No. 2, including whether the amendment is consistent with the Act. Persons making written submissions should file six copies thereof with the Secretary, Securities and Exchange Commission, 450 Fifth Street, NW, Washington, DC 20549-0609. Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for inspection and copying in the Commission's Public Room. Copies of the filing will also be available for inspection and copying at the principal office of the Exchange. All submissions should refer to File No. SR-Phlx-99-30 and should be submitted by March 2, 2000.
For the Commission, by the Division of Market Regulation, pursuant to delegated authority.
In accordance with a notice received from the Federal Emergency Management Agency dated January 24, 2000, the above-numbered Declaration is hereby amended to include Hancock and Henderson Counties in the State of Kentucky as a disaster area due to damages caused by tornadoes, severe storms, torrential rains, and flash flooding that occurred on January 3-4, 2000.
In addition, applications for economic injury loans from small businesses located in the contiguous County of Breckinridge, Kentucky, and Perry, Posey, and Vanderburgh Counties in Indiana may be filed until the specified date at the previously designated location. Any counties contiguous to the above-named primary counties and not listed herein have been previously declared.
All other information remains the same,
In compliance with Public Law 104-13, the Paperwork Reduction Act of 1995, SSA is providing notice of its information collections that require submission to the Office of Management and Budget (OMB). SSA is soliciting comments on the accuracy of the agency's burden estimate; the need for the information; its practical utility; ways to enhance its quality, utility and clarity; and on ways to minimize burden on respondents, including the use of automated collection techniques or other forms of information technology.
I. The information collections listed below will be submitted to OMB within 60 days from the date of this notice. Therefore, comments and recommendations regarding the information collections would be most useful if received by the Agency within 60 days from the date of this publication. Comments should be directed to the SSA Reports Clearance Officer at the address listed at the end of this publication. You can obtain a copy of the collection instruments by calling the SSA Reports Clearance Officer on (410) 965-4145, or by writing to him at the address listed at the end of this publication.
1. Claimant's Medications—0960-0289. The Social Security Administration (SSA) uses Form HA-4632 to request that applicants for disability benefits provide information to facilitate processing their title II, Old-Age, Survivors and Disability Insurance (OASDI) and Title XVI, Supplemental Security Income (SSI) claims. The form elicits from the claimants an updated list of medications used by the claimants. It enables the Administrative Law Judge hearing the case to fully inquire into medical treatment the claimant is receiving and the effect of medications on the claimant's medical impairments. The respondents are applicants for OASDI and SSI benefits.
2. Statement of Employer—0960-0030. The information collected on Form SSA-7011 is needed by SSA to substantiate allegations of wages paid to workers when those wages do not appear in SSA's records of earnings and the worker does not have proof that payment was made. This information is
3. Request for SSI Benefit Estimate—0960-0492. SSA uses Form SSA-3716 for an SSI beneficiary who wishes to request a 5-month estimate of what their benefits would be if they should return to work in the future. The respondents are SSI recipients.
II. The information collections listed below have been submitted to OMB for clearance. Written comments and recommendations on the information collections would be most useful if received within 30 days from the date of this publication. Comments should be directed to the SSA Reports Clearance Officer and the OMB Desk Officer at the addresses listed at the end of this publication. You can obtain a copy of the OMB clearance packages by calling the SSA Reports Clearance Officer on (410) 965-4145, or by writing to him.
1. Vocational Rehabilitation “301” Program Development—0960-0282. The information on Form SSA-4290 is used by the Social Security Administration (SSA) to determine an individual's continued entitlement to disability benefits when that individual has medically recovered while allegedly participating in a State or alternate Vocational Rehabilitation (VR) program. The respondents are State or alternate VR agencies serving such beneficiaries.
2. Certificate of Election for Reduced Spouse's Benefits—0960-0398. SSA uses the information collected on Form SSA-25 to pay a qualified spouse who elects to receive a reduced benefit at an earlier age. The respondents are entitled spouses seeking reduced benefits.
3. Statement of Funds You Provided to Another, Statement of Funds You Received-0960-0481. Forms SSA-2854 & SSA-2855 are used by SSA to collect information in situations where the SSI claimant alleges that money was borrowed on an informal basis from a noncommercial lender,
The Department of State announces an open meeting for the purpose of forming the United States delegation to the 2000 International Telecommuication Union (ITU) World Radiocommunication Conference (WRC-2000). This meeting will solicit expressions of interest in participating as a member of the U.S. Delegation to WRC-2000 and convey information regarding planned U.S. preparatory activities in advance of the WRC. The meeting will be held from 9:30 to noon on February 16, 2000 in the Dean Acheson Auditorium at the Department of State. Members of the general public may attend these meetings and join in the discussions, subject to the instructions of the Chair. Admission of public members will be limited to seating available. Entrance to the Department of State is controlled; people intending to attend any of these meetings should send a fax to 202-647-7407 not later than 24 hours before the meeting. This fax should provide the name of the meeting, (WRC-2000 Preparatory Meeting) and date of the meeting, your name, social security number, date of birth, and organizational affiliation. One of the following valid photo identifications will be required for admittance: US driver's license, US passport, US Government identification card. Enter from the 23rd Street entrance lobby; in view of escorting requirements, non-Government attendees should plan to arrive not later than 15 minutes before the meeting begins.
United States Department of State.
Notice of meeting of the Cultural Property Advisory Committee.
The Cultural Property Advisory Committee will meet on Monday, March 13, 2000, from approximately 9 a.m. to 5 p.m., and on Tuesday, March 14, from approximately 9 a.m. to 2 p.m., at the Department of State, Annex 44, Room 840, 301 4th St., SW, Washington, DC. During its meeting the Committee will continue its review and investigation of a foreign government request submitted by the Government of the Republic of Bolivia to the Government of the United States of America filed under Article 9 of the 1970 Convention on the Means of Prohibiting and Preventing the Illicit Import, Export and Transfer of Ownership of Cultural Property. Notification of receipt of this request appeared in the
Bolivia believes its cultural patrimony to be in jeopardy from pillage. It seeks U.S. import restrictions on Pre-Columbian archaeological material such as artifacts made of stone, metal, ceramic, shell, bone, wood, textiles, featherwork, basketry, and Pre-Columbian human remains; and Colonial period and indigenous ethnological materials such as folklore costumes, textiles, featherwork, stonework, leatherwork, woodwork, metalwork, ceramics, religious imagery, musical instruments, and paintings.
The Committee's review of the request is carried out in accordance with provisions of the Convention on Cultural Property Implementation Act (19 U.S.C. 2601
During its meeting on March 13, the Committee will hold an open session, 1:30-3:30 p.m., to receive public comment on the Bolivia request. The Committee also invites written comment and requests that both oral and written comments address the determinations that must be made about the Bolivia request pursuant to 19 U.S.C. 2602, Convention on Cultural Property Implementation Act. Other portions of the meeting on March 13-14 will be closed pursuant to 5 U.S.C. 552b(c)(9)(B) and 19 U.S.C. 2605(h).
Written comments may be sent to Cultural Property, Department of State, Annex 44, 301 4th Street, SW, Rm. 247, Washington, DC 20547; or faxed to (202) 619-5177. Persons wishing to attend the open portion of the meeting on March 13, must notify the Cultural Property Office, (202) 619-6612, no later than 5 p.m., Thursday, March 9, 2000, to arrange for admission.
In accordance with 5 U.S.C. 552b(c)(9)(B), and 19 U.S.C. 2605(h), I hereby determine that portions of the meeting of the Cultural Property Advisory Committee on March 13-14, at which there will be deliberation of information the premature disclosure of which would be likely to significantly frustrate implementation of proposed actions, will be closed.
The following Agreements were filed with the Department of Transportation under the provisions of 49 U.S.C. Sections 412 and 414. Answers may be filed within 21 days of date of filing.
Pursuant to section 10(a)(2) of the Federal Advisory Committee Act (P.L. 92-463), (5 U.S.C., Appendix 2), notice is hereby given of an Industry Day to discuss Controller Pilot Data Link Communications (CPDLC), to be held February 29, 2000 from 8:30 a.m. to 3:30 p.m., at the Federal Aviation Administration, 800 Independence Avenue, SW., Washington, DC., in the third floor auditorium. This meeting is sponsored by the FAA Office of Communications, Navigation, and Surveillance Systems.
Presentations will include an overview of the CPDLC project from government and industry representatives. These presentations will provide the aviation community with current information about the status of CPDLC. There will be a panel discussion in the afternoon and time
Attendance is open to the interested public but limited to space availability. With the approval of the Product Lead for Aeronautical Data Link, members of the public may present oral statements at the meeting. Persons wishing to present statements or obtain information should contact Mr. James H. Williams, FAA, at (202) 493-4693. Members of the public may present a written statement to the Product Lead at any time.
Pursuant to section 10(a)(2) of the Federal Advisory Committee Act (Pub. L. 92-463, 5 U.S.C., Appendix 2), notice is hereby given for Special Committee 147 meeting to be held February 29-March 1, 2000, starting at 9 a.m. each day. The meeting will be held at RTCA, 1140 Connecticut Avenue, NW., Suite 1020, Washington, DC, 20036.
The agenda will include: February 29: (1) Requirements Working Group Meeting. March 1: 9 a.m.-1 p.m. (2) Requirements Working Group Meeting continues; 1 p.m.-5 p.m. (3) Plenary Session: (a) Welcome and Introductory Remarks: (b) Review and Approve Previous Meeting; (c) Report and Discuss Requirements Working Group Activities; (d) Discuss Future SC-147 Activities and Plans; (4) Other Business; (5) Date and Location of Next Meeting; (6) Closing.
Attendance is open to the interested public but limited to space availability. With the approval of the chairman, members of the public may present oral statements at the meeting. Persons wishing to present statements or obtain information should contact the RTCA Secretariat, 1140 Connecticut Avenue, NW., Suite 1020, Washington, DC, 20036; (202) 833-9339 (phone); (202) 833-9434 (fax); or http://www.rtca.org (web site). Members of the public may present a written statement to the committee at any time.
Pursuant to section 10(a) (2) of the Federal Advisory Committee Act (Pub. L. 92-463, 5 U.S.C., Appendix 2), notice is hereby given for Joint Special Committee (SC)-190 /EUROCAE Working Group (WG)-52 meeting to be held March 6-10, 2000, starting at 9:00 am. on Monday, March 6. The meeting will be held at The Boeing Long Beach Division, 3855 Lakewood Blvd., Long Beach, California.
The agenda will include the following: March 6: 9 a.m.-3 p.m. (1) Plenary Session; (a) Welcome and Introductory Remarks; (b) Review and Approve Minutes of Previous Meeting; (c) Review New Process; (d) Review Status of Certification Authorities Software Team (CAST) & FAA Notices; (e) Review Reports of Editorial and Executive Committees, Issue List and Matrix, Subgroup Executive Summaries, and CNS/ATM; (f) Preliminary Assessment of Papers (Stand-up Plenary Model); (g) Subgroup working sessions begin. March 7: 8:30 a.m. (2) Subgroup working sessions. March 8: 8:30 a.m. (3) Plenary Session reconvenes: (a) Plenary Approval Vote on Frequently Asked Questions (FAQ) & Discussion Papers (DP) seen Monday: (b) Plenary Assessment of New FAQs & DPs; 1 p.m. (4) Subgroup working sessions reconvene. March 9: (5) Subgroup working sessions continue. March 10: (6) Plenary Approval Process begins; (7) New Business; (8) Review Action Items and Plans; (9) Date and Location of Next Meeting; (10) Closing.
Attendance is open to the interested public but limited to space availability. With the approval of the chairman, members of the public may present oral statements at the meeting. Persons wishing to present statements or obtain information should contact the RTCA Secretariat, 1140 Connecticut Avenue, NW., Suite 1020, Washington, DC. 20036; (202) 833-9339 (phone); (202) 833-9434 (fax); or http://www.rtca.org (web site) or point of contact on-site: Mr. E.W. Piper at (562) 593-1029 (phone);
Wisconsin Chicago Link Ltd. (WCLL), a Class III rail carrier, has filed a notice of exemption under 49 CFR 1150.41 to lease from Pennsylvania Lines LLC (PRR) approximately 1.9 miles of rail line (the Panhandle Line) of the former Pittsburgh Cincinnati, Chicago & St. Louis Railroad Company (PCC&StL) in Chicago, Cook County, IL.
WCLL states that the Panhandle Line is currently out of service and that WCLL intends to reconstruct the line and add additional capacity. WCLL further states that, initially, operations on the line will be conducted by NS, CSXT, and Wisconsin Central Ltd. pursuant to trackage rights. WCLL indicates that it anticipates that CSXT will dispatch a portion of the Panhandle Line.
This transaction is related to STB Finance Docket No. 33811,
The transaction is scheduled to be consummated on or shortly after February 4, 2000.
If the notice contains false or misleading information, the exemption is void
An original and 10 copies of all pleadings, referring to STB Finance Docket No. 33831, must be filed with the Surface Transportation Board, Office of the Secretary, Case Control Unit, 1925 K Street, NW, Washington, DC 20423-0001. In addition, a copy of each pleading must be served on William C. Sippel, Esq., Oppenheimer Wolff & Donnelly (Illinois), 180 North Stetson Avenue, Two Prudential Plaza, 45th Floor, Chicago, IL 60601-6710.
Board decisions and notices are available on our website at “WWW.STB.DOT.GOV.”
U.S. Customs Service, Treasury.
General notice.
This document announces Customs conclusion of the National Customs Automation Program Prototype (NCAP/P). Prototype operations must be discontinued due to the cessation of funding for the NCAP/P automated system. Upon prototype conclusion, NCAP/P participants must cease entering goods and transmitting data under NCAP/P procedures. This document also provides instructions to participants on procedures for processing prototype entries using non-NCAP/P systems.
Termination of the NCAP/P will be effective as of March 13, 2000. No new applications for participation will be accepted as of February 10, 2000.
Comments and requests regarding NCAP/P termination may be directed to Keith Fleming, U.S. Customs Service at (202) 927-1049, or Virginia Noordewier, U.S. Customs Service at (202) 927-3296.
The vision of the Automated Commercial Environment (ACE) is to establish a Trade Compliance Process that achieves high levels of compliance and reduces the cycle time required for imports to clear Customs. NCAP/P is the prototype for the first implementation of this automated process.
Customs first announced its intention to implement the NCAP/P in the
The NCAP/P plan called for a four-stage implementation of new cargo processing features over a period of up to three years. The NCAP/P commenced on April 27, 1998 with the implementation of the cargo release stage. Customs implemented the second stage on October 13, 1998, which provided for cargo release with examination. At the time of this termination, the third and fourth stages—entry summary/periodic payment and reconciliation—have not been implemented.
Upon prototype conclusion, participants must immediately revert to non-NCAP/P processing for all cargo sAs of the date 30 days from the date of publication of this document in the
B. Cargo releases previously obtained through NCAP/P must be followed up by summary data and payments transmitted through existing non-NCAP/P systems,
Upon the conclusion of the NCAP/P, an evaluation of the entire test will be conducted and the results published in the
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Form 5498-MSA, MSA or Medicare+Choice MSA Information.
Written comments should be received on or before April 10, 2000 to be assured of consideration.
Direct all written comments to Garrick R. Shear, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the form and instructions should be directed to Faye Bruce, (202) 622-6665, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval. All comments will become a matter of public record. Comments are invited on: (a) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology; and (e) estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services to provide information.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13(44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Form 8281, Information Return for Publicly Offered Original Issue Discount Instruments.
Written comments should be received on or before April 10, 2000 to be assured of consideration.
Direct all written comments to Garrick R. Shear, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the form and instructions should be directed to Faye Bruce, (202) 622-6665, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval. All comments will become a matter of public record. Comments are invited on: (a) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology; and (e) estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services to provide information.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C.
Written comments should be received on or before April 10, 2000 to be assured of consideration.
Direct all written comments to Garrick R. Shear, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the form and instructions should be directed to Faye Bruce, (202) 622-6665, Internal Revenue Service, Room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval. All comments will become a matter of public record. Comments are invited on: (a) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology; and (e) estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services to provide information.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13(44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Form 1099-MSA, Distributions From an MSA or Medicare+Choice MSA.
Written comments should be received on or before April 10, 2000 to be assured of consideration.
Direct all written comments to Garrick R. Shear, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the form and instructions should be directed to Faye Bruce, (202) 622-6665, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval. All comments will become a matter of public record. Comments are invited on: (a) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology; and (e) estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services to provide information.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13(44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Form 2163(c), Employment—Reference Inquiry.
Written comments should be received on or before April 10, 2000 to be assured of consideration.
Direct all written comments to Garrick R. Shear, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the form and instructions should be directed to Faye Bruce, (202) 622-6665, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
Title: Employment—Reference Inquiry.
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval. All comments will become a matter of public record. Comments are invited on: (a) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology; and (e) estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services to provide information.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Form 6765, Credit for Increasing Research Activies.
Written comments should be received on or before April 10, 2000 to be assured of consideration.
Direct all written comments to Garrick R. Shear, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the form(s) and instructions should be directed to Carol Savage, (202) 622-3945, Internal Revenue Service, room 5242, 1111 Constitution Avenue NW., Washington, DC 20224.
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Form 5304-SIMPLE, Savings Incentive Match Plan for Employees of Small Employers (SIMPLE) (Not Subject to the Designated Financial Institution Rules), Form 5305-SIMPLE, Savings Incentive Match Plan for Employees of Small Employers (SIMPLE) (for Use With a Designated Financial Institution), and Notice 98-4, SIMPLE IRA Plan Guidance.
Written comments should be received on or before April 10, 2000 to be assured of consideration.
Direct all written comments to Garrick R. Shear, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the information collections should be directed to Martha R. Brinson, (202) 622-3869, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval. All comments will become a matter of public record. Comments are invited on: (a) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology; and (e) estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services to provide information.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Revenue Procedure 2000-16, Employee Plans Compliance Resolution System.
Written comments should be received on or before April 10, 2000 to be assured of consideration.
Direct all written comments to Garrick R. Shear, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the revenue procedure should be directed to Carol Savage, (202) 622-3945, Internal Revenue Service, room 5242, 1111 Constitution Avenue NW., Washington, DC 20224.
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval. All comments will become a matter of public record. Comments are invited on: (a) Whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology; and (e) estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services to provide information.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Revenue Procedure 2000-20, Master and Prototype Plans.
Written comments should be received on or before April 10, 2000 to be assured of consideration.
Direct all written comments to Garrick R. Shear, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the revenue procedure should be directed to Carol Savage, (202) 622-3945, Internal Revenue Service, room 5242, 1111 Constitution Avenue NW., Washington, DC 20224.
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort
Written comments should be received on or before April 10, 2000 to be assured of consideration.
Direct all written comments to Garrick R. Shear, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of this regulation should be directed to Faye Bruce, (202) 622-6665, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning an existing final regulation, INTL-485-89 (TD 8400), Taxation of Gain or Loss from Certain Nonfunctional Currency Transactions (Section 988 Transactions) (Sections 1.988-0 through 1.988-5).
Written comments should be received on or before April 10, 2000 to be assured of consideration.
Direct all written comments to Garrick R. Shear, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the regulation should be directed to Martha R. Brinson, (202) 622-3869, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval. All comments will become a matter of public record. Comments are invited on:
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Revenue Ruling 2000-8, Negative Elections in Section 401(k) Plans.
Written comments should be received on or before April 10, 2000 to be assured of consideration.
Direct all written comments to Garrick R. Shear, Internal Revenue Service, room 5244, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the revenue ruling should be directed to Carol Savage, (202) 622-3945, Internal Revenue Service, room 5242, 1111 Constitution Avenue NW., Washington, DC 20224.
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Environmental Protection Agency (EPA).
Final rule.
Today's action finalizes a major program designed to significantly reduce the emissions from new passenger cars and light trucks, including pickup trucks, vans, minivans, and sport-utility vehicles. These reductions will provide for cleaner air and greater public health protection, primarily by reducing ozone and PM pollution. The program is a comprehensive regulatory initiative that treats vehicles and fuels as a system, combining requirements for much cleaner vehicles with requirements for much lower levels of sulfur in gasoline. A list of major highlights of the program appears at the beginning of the
The program we are finalizing today will phase in a single set of tailpipe emission standards that will, for the first time, apply to all passenger cars, light trucks, and larger passenger vehicles operated on any fuel. This set of “Tier 2 standards” is feasible and the use of a single set of standards is appropriate because of the increased use of light trucks for personal transportation. The miles traveled in light trucks is increasing and the emissions from these vehicles are thus an increasing problem. This approach builds on the recent technology improvements resulting from the successful National Low-Emission Vehicles (NLEV) program.
To enable the very clean Tier 2 vehicle emission control technology to be introduced and to maintain its effectiveness, we are also requiring reduced gasoline sulfur levels nationwide. The reduction in sulfur levels will also contribute directly to cleaner air in addition to its beneficial effects on vehicle emission control systems. Refiners will generally install additional refining equipment to remove sulfur in their refining processes. Importers of gasoline will be required to import and market only gasoline meeting the sulfur standards. Today's action also introduces an averaging, banking, and trading program to provide flexibility for refiners and ease implementation of the gasoline sulfur control program.
The overall program focuses on reducing the passenger car and light truck emissions most responsible for causing ozone and particulate matter problems. Without today's action, we project that emissions of nitrogen oxides from these vehicles will represent as much as 40 percent of this ozone-forming pollutant in some cities, and almost 20 percent nationwide, by the year 2030.
Today's program will bring about major reductions in annual emissions of these pollutants and also reduce the emissions of sulfur compounds resulting from the sulfur in gasoline. For example, we project a reduction in oxides of nitrogen emissions of at least 856,000 tons per year by 2007 and 1,236,000 by 2010, the time frame when many states will have to demonstrate compliance with air quality standards. Emission reductions will continue increasing for many years, reaching at least 2,220,000 tons per year in 2020 and continuing to rise further in future years. In addition, the program will reduce the contribution of vehicles to other serious public health and environmental problems, including VOC, PM, and regional visibility problems, toxic air pollutants, acid rain, and nitrogen loading of estuaries.
Furthermore, we project that these reductions, and their resulting environmental benefits, will come at an average cost increase of less than $100 per passenger car, an average cost increase of less than $200 for light trucks, and an average cost increase of about $350 for medium-duty passenger vehicles, and an average increase of less than 2 cents per gallon of gasoline (or about $120 over the life of an average vehicle).
This rule is effective April 10, 2000.
The incorporation by reference of certain publications contained in this rule are approved by the Director of the Federal Register as of April 10, 2000.
Carol Connell, U.S. EPA, National Vehicle and Fuels Emission Laboratory, 2000 Traverwood, Ann Arbor MI 48105; Telephone (734) 214-4349, FAX (734) 214-4816, E-mail connell.carol@epa.gov.
• Starting in 2004, through a phase-in, apply for the first time the same set of emission standards covering passenger cars, light trucks, and large SUVs and passenger vehicles. These emission levels (“Tier 2 standards”) are feasible for these vehicles. The Tier 2 standards are also appropriate because of the increased use of light trucks for personal transportation—the miles traveled in light trucks is increasing and the emissions from these vehicles are thus an increasing problem.
• Introduce a new category of vehicles, “medium-duty passenger vehicles,” thus bringing larger passenger vans and SUVs into the Tier 2 program.
• During the phase-in, apply interim fleet emission average standards that match or are more stringent than current federal and California “LEV I” (Low-Emission Vehicle, Phase I) standards.
• Apply the same standards to vehicles operated on any fuel.
• Allow auto manufacturers to comply with the very stringent new standards in a flexible way while ensuring that the needed environmental benefits occur.
• Build on the recent technology improvements resulting from the successful National Low-Emission Vehicles (NLEV) program and improve the performance of these vehicles through lower sulfur gasoline.
• Set more stringent particulate matter standards.
• Set more stringent evaporative emission standards.
• Significantly reduce average gasoline sulfur levels nationwide as early as 2000, fully phased in in 2006. Refiners will generally add refining equipment to remove sulfur in their refining processes. Importers of gasoline will be required to import and market only gasoline meeting the sulfur limits.
• Provide for flexible implementation by refiners through an averaging, banking, and trading program.
• Encourage early introduction of cleaner fuel into the marketplace through an early sulfur credit and allotment program.
• Apply temporary gasoline sulfur standards to certain small refiners and gasoline marketed in a limited geographic area in the western U.S.
• Enable the new Tier 2 vehicles to meet the emission standards by greatly reducing the degradation of vehicle emission control performance from sulfur in gasoline. Lower sulfur gasoline also appears to be necessary for the introduction of advanced technologies that promise higher fuel economy but are very susceptible to sulfur poisoning (for example, gasoline direct injection engines).
• Reduce emissions from NLEV vehicles and other vehicles already on the road.
This action will affect you if you produce new motor vehicles, alter individual imported motor vehicles to address U.S. regulation, or convert motor vehicles to use alternative fuels. It will also affect you if you produce, distribute, or sell gasoline motor fuel.
The table below gives some examples of entities that may have to comply with the regulations. But because these are only examples, you should carefully examine these and existing regulations in 40 CFR parts 80 and 86. If you have questions, call the person listed in the
Today's action is available electronically on the day of publication from the Office of the Federal Register Internet Web site listed below. Electronic copies of this preamble and regulatory language as well as the Response to Comments document, the Regulatory Impact Analysis and other documents associated with today's final rule are available from the EPA Office of Mobile Sources Web site listed below shortly after the rule is signed by the Administrator. This service is free of charge, except any cost that you already incur for connecting to the Internet.
Please note that due to differences between the software used to develop the document and the software into which the document may be downloaded, changes in format, page length, etc., may occur.
Since the passage of the 1990 Clean Air Act Amendments, the U.S. has made significant progress in reducing emissions from passenger cars and light trucks. The National Low-Emission Vehicle (NLEV) and Reformulated Gasoline (RFG) programs are important examples of control programs that are in place and will continue to help reduce car and light-duty truck emissions into the near future.
Nonetheless, due to increasing vehicle population and vehicle miles traveled, passenger cars and light trucks will continue to be significant contributors to air pollution inventories well into the future. In fact, the emission contribution of light trucks and sport utility vehicles now matches that of passenger cars. (This is occurring because of the combination of growth in miles traveled by light trucks and the fact that their emission standards are currently less stringent than those of passenger cars). The program we describe below builds on the NLEV and RFG Phase II programs to develop a strong new national program to protect public health and the environment well into the next century. The program, while reducing VOC and other emissions, focuses especially on NO
We have followed several overarching principles in developing this final rule:
• Design a strong national program that will assist states in every region of the country to meet their air quality objectives and that will ensure that cars and trucks continue to contribute a fair share to our nation's overall air quality solutions;
• View vehicles and fuels as an integrated system, recognizing that only by addressing both can the best overall emission performance be achieved;
• Establish a single set of emission standards that apply regardless of the fuel used and whether the vehicle is a car, a light truck, or a larger passenger vehicle;
• Provide compliance flexibilities that allow vehicle manufacturers and oil refiners to adjust to future market trends and honor consumer preferences;
• Not preclude the development of advanced low emission or fuel efficient technologies such as lean-burn engines; and
• Ensure sufficient leadtime for phase-in of the Tier 2 and gasoline sulfur program.
With these principles as background, we turn now to an overview of the vehicle and fuel aspects of the program. Sections I and II of this preamble will give you a brief overview of our program and our rationale for implementing it. Subsequent sections will expand on the air quality need, technological feasibility, economic impacts, and provide a detailed description of the specifics of the program. A public participation section reviews the process we followed in soliciting and responding to public comment. The final sections deal with several administrative requirements. You may also want to review our Final Regulatory Impact Analysis (RIA) and our Response to Comments document, both of which are found in the docket and on the Internet. They provide additional analyses and discussions of many topics raised in this preamble.
The nation's air quality, while certainly better than in the past, will nevertheless continue to expose tens of millions of Americans to unhealthy levels of air pollution well into the future in the absence of significant new controls on emissions from motor vehicles. EPA is therefore finalizing a major, comprehensive program designed to reduce emission standards for passenger cars, light trucks, and large passenger vehicles (including sport-utility vehicles, minivans, vans, and pickup trucks) and to reduce the sulfur content of gasoline. Under the program, automakers will produce vehicles designed to have very low emissions when operated on low-sulfur gasoline, and oil refiners will provide that much cleaner gasoline nationwide. In this preamble, we refer to the comprehensive program as the “Tier 2/Gasoline Sulfur program.”
Today's action sets new federal emission standards (“Tier 2 standards”) for passenger cars, light trucks, and larger passenger vehicles. The program is designed to focus on reducing the emissions most responsible for the ozone and particulate matter (PM) impact from these vehicles—nitrogen oxides (NO
The Tier 2 standards finalized today will reduce new vehicle NO
During the phase-in period from 2004-2007, all passenger cars and light LDTs not certified to the primary Tier 2 standards will have to meet an interim average standard of 0.30 g/mi NO
We are also setting stringent particulate matter standards that will be especially important if there is substantial future growth in the sales of diesel vehicles. Before 2004, we are establishing more stringent interim PM standards for most light trucks than exist now under NLEV. With higher sales of diesel cars and light trucks, they could easily contribute between one-half and two percent of the PM10 concentration allowed by the NAAQS, with some possibility that the contribution could be as high as 5 to 40 percent in some roadside situations with heavy traffic. These increases would make attainment even more difficult for 8 counties which we already predict to need further emission reductions even without an increase in diesel sales, and would put at risk another 18 counties which are now within 10 percent of a NAAQS violation. Thus, by including a more stringent PM standard in the program finalized today, we help address environmental concerns about the potential growth in the numbers of light-duty diesels on the road—even if that growth is substantial. The new requirements also include more stringent hydrocarbon controls (exhaust NMOG and evaporative emissions standards). We will also monitor the progress of the development of advanced technologies and the role of fuels.
The other major part of today's action will significantly reduce average gasoline sulfur levels nationwide. We expect these reductions could begin to phase in as early as 2000, with full compliance for most refiners occurring by 2006. Refiners will generally install advanced refining equipment to remove sulfur during the production of gasoline. Importers of gasoline will be required to import and market only gasoline meeting the sulfur limits. Temporary, less stringent standards will apply to a few small refiners through 2007. In addition, temporary, less stringent standards will apply to a limited geographic area in the western U.S. for the 2004-2006 period.
This significant new control of gasoline sulfur content will have two important effects. The lower sulfur levels will enable the much-improved emission control technology necessary to meet the stringent vehicle standards of today's rule to operate effectively over the useful life of the new vehicles. In addition, as soon as the lower sulfur gasoline is available, all gasoline vehicles already on the road will have reduced emissions—from less degradation of their catalytic converters and from fewer sulfur compounds in the exhaust.
Today's action will encourage refiners to reduce sulfur in gasoline as early as 2000. The program requires that most refiners and importers meet a corporate average gasoline sulfur standard of 120 ppm and a cap of 300 ppm beginning in 2004. By 2006, the cap will be reduced to 80 ppm and most refineries must produce gasoline averaging no more than 30 ppm sulfur. The program builds upon the existing regulations covering gasoline composition as it relates to emissions performance. It includes provisions for trading of sulfur credits, increasing the flexibility available to refiners for complying with the new requirements. We intend for the credit program to ease compliance uncertainties by providing refiners the flexibility to phase in early controls in 2000-2003 and use credits gained in these years to delay some control until as late as 2006. As finalized today, the program will achieve the needed environmental benefits while providing substantial flexibility to refiners.
We are setting motor vehicle emission standards under the authority of section 202 of the Clean Air Act. Sections 202(a) and (b) of the Act provide EPA with general authority to prescribe vehicle standards, subject to any specific limitations otherwise included in the Act. Sections 202(g) and (h) specify the current standards for LDVs and LDTs, which became effective beginning in model year 1994 (“Tier 1 standards”).
Section 202(i) of the Act provides specific procedures that EPA must follow to determine whether standards more stringent than Tier 1 standards for LDVs and certain LDTs
After the study is completed and the results are reported to Congress, EPA is required to determine by rulemaking whether: (1) There is a need for further emission reductions; (2) the technology for more stringent emission standards from the affected classes is available; and (3) such standards are needed and cost-effective, taking into account alternatives. If EPA answers “yes” to these questions, then the Agency is to promulgate new, more stringent motor vehicle standards (“Tier 2 standards”).
EPA submitted its report to Congress on July 31, 1998. Today's final rule makes affirmative responses to the three questions above (see Section II below) and sets new standards that are more stringent than the default standards in the Act.
EPA is also setting standards for larger light-duty trucks and MDPVs under the general authority of Section 202(a)(1) and 202(b) and under Section 202(a)(3) of the Act, which requires that standards applicable to emissions of hydrocarbons, NO
We are adopting gasoline sulfur controls pursuant to our authority under Section 211(c)(1) of the Clean Air Act.
We are adopting gasoline sulfur controls based on both of these criteria. Under the first criterion, we believe that sulfur in gasoline used in Tier 1 and LEV technology vehicles contributes to ozone pollution, air toxics, and PM. Under the second criterion, we believe that gasoline sulfur in fuel will significantly impair the emissions control systems expected to be used in Tier 2 technology vehicles, as well as emissions control systems currently used in LEVs. Please refer to Section IV.C. below and to the Final Regulatory Impact Analysis (RIA) for more details of our analysis and findings. The RIA includes a more detailed discussion of EPA's authority to set gasoline sulfur standards, including a discussion of our conclusions relating to the factors required to be considered under Section 211(c).
On July 31, 1998, EPA submitted its report to Congress containing the results of the Tier 2 study.
In addition, on May 1, 1998, EPA released a staff paper presenting EPA's understanding of the impact of gasoline sulfur on emissions from motor vehicles and exploring what gasoline producers and automobile manufacturers could do to reduce sulfur's impact on emissions. The staff paper noted that gasoline sulfur degrades the effectiveness of catalytic converters and that high sulfur levels in commercial gasoline could affect the ability of future automobiles—especially those designed for very low emissions—to meet more stringent standards in use. It also pointed out that sulfur control will provide additional benefits by lowering emissions from the current fleet of vehicles.
In the NPRM, we raised the question of what if any changes to diesel fuel may be needed to enable diesel vehicles to meet the Tier 2 standards or any future heavy-duty diesel engine standards. Specifically, we raised the question of whether diesel sulfur levels need to be controlled. Since diesel fuel controls of any kind would have an impact on the refinery as a whole, and since in some cases (including potential diesel sulfur limits) could have implications for gasoline sulfur control, we requested comment on this issue in our proposal. We also indicated that we planned to release an Advance Notice of Proposed Rulemaking to solicit more information on this subject.
We published the ANPRM on May 13, 1999 (64 FR 26142). We are in the process of considering all of the comments received in response to the ANPRM and plan to issue a Notice of Proposed Rulemaking (NPRM) in early spring of 2000. We received many comments on the subject of diesel fuel control along with the comments submitted on the proposed Tier 2/Gasoline Sulfur regulations. We have prepared brief responses to some of these comments in the Response to Comments document, and will deal fully with these comments as part of the forthcoming NPRM on diesel fuel. We are taking no action on diesel fuel as part of today's action.
Based on the statutory requirements described above and the evidence provided in the Tier 2 Study and since its release, as described elsewhere in this preamble, EPA has determined that new, more stringent emission standards are indeed needed, technologically feasible, and cost effective.
EPA finds that there is a clear air quality need for new emission standards, based on the continuing air quality problems predicted to exist in future years. As the discussion in Section III.B. illustrates, 26 metropolitan areas are each certain or highly likely to need additional reductions. These areas are distributed across most regions of the U.S., and have a combined population of over 86 million. Section III.B. also shows that an additional 12 areas each has a moderate to significant probability of needing additional reductions, representing another 25 million people. This provides ample evidence that further emission reductions are needed to meet the 1-hour ozone NAAQS.
In addition to these ozone concerns, our analysis of PM
We find that emission standards significantly more stringent than current Tier 1 and National Low Emission Vehicle (NLEV) levels are technologically feasible. This is true both for the LDVs and LDTs specifically covered in section 202(i) and for the medium-duty passenger vehicles also included in today's final rule. Manufacturers are currently producing NLEV vehicles that meet more stringent standards than similar Tier 1 models. Our analysis shows that mainly through improvements in engine control software and catalytic converter technology, manufacturers can build and are building durable vehicles and trucks, including heavy light-duty trucks, which have very low emission levels.
Many current production vehicles are already certified at or near the Tier 2 standards. For year 2000 certification (although not yet complete), over 50 vehicle models have emissions at or below Tier 2 levels. In addition, we performed a demonstration program at our EPA laboratory that showed that even large vehicles, which would be expected to face the toughest challenges reaching Tier 2 emission levels, can do so with conventional technology. Others, including the Manufacturers of Emission Controls Association (MECA) and the State of California, have also performed demonstration programs, with similar results. Manufacturers have also certified LDVs and LDTs to NMOG and CO levels as much as 80 percent below Tier 1 standards. Furthermore, for passenger vehicles greater than 8500 lbs GVWR, we believe that by using technologies and control strategies similar to what will be used on lighter vehicles, manufacturers will be able to meet the Tier 2 emission standards.
Thus, we believe that, by the 2004-2009 time frame, manufacturers will be fully able to comply with the new Tier 2 emission standard levels. In addition, to facilitate manufacturers' efforts to meet these new standards, the Tier 2 regulations include a phase-in over several years and a corporate fleet average NO
In this action, we also find that more stringent motor vehicle standards are both necessary and cost effective. As discussed above, substantial further reductions in emissions are needed to help reduce the levels of unhealthy air pollution to which millions of people are being exposed; in particular, we expect that a number of areas will not attain or maintain compliance with the National Ambient Air Quality Standards for ozone and PM
Furthermore, mobile sources are important contributors to the air quality problem. As we will explain more fully later in this preamble, in the year 2030, the cars and light trucks that are the subject of today's final rule are projected to contribute as much as 40 percent of the total NO
These emission reductions are clearly necessary to meet and maintain the 1-hour ozone NAAQS. We project that while the emission reductions of this program will lead to substantial progress in meeting and maintaining the NAAQS, many areas will still not come into attainment even with this magnitude of reductions.
We find that the Tier 2/Gasoline Sulfur program is a reasonable, cost-effective method of providing substantial progress towards attainment and maintenance of the NAAQS, costing about $2000 per ton of NO
In addition, the magnitude of emission reductions that can be achieved by a comprehensive national Tier 2/Gasoline Sulfur program will be difficult to achieve from any other source category. Given the large contribution that light-duty mobile source emissions make to the national emissions inventory and the range of control programs ozone-affected areas
Furthermore, we project that the Tier 2/Gasoline Sulfur program will significantly reduce direct and secondary particulate matter coming from LDVs, LDTs, and MDPVs—by about 36,000 tons per year of direct PM alone by 2030; large secondary PM reductions from significantly lower NO
Finally, the Tier 2/Gasoline Sulfur program will significantly reduce CO emissions from LDVs, LDTs, and MDPVs. (See Chapter III of the RIA for an analysis of these reductions.) The technical changes needed to meet the NMOG standards will also result in CO reductions sufficient to meet the CO standards. Thus, these CO reductions will be very cost-effective since they will not require any new emission control devices beyond what manufacturers are expected to install to meet the NO
We conclude, then, that today's final rule is a major source of ozone precursor, PM, and CO emission reductions when compared to other available options. The discussions of cost and cost effectiveness later in this preamble and in the RIA explain the derivation of cost effectiveness estimates and compares them to the cost effectiveness of other alternatives. That discussion indicates that this program will have a cost effectiveness comparable to both the Tier 1 and NLEV standards and will also be cost effective when compared to non-mobile source programs.
In the absence of significant new controls on emission, tens of millions of Americans would continue to be exposed to unhealthy levels of air pollution. Emissions from passenger cars and light trucks are a significant contributor to a number of air pollution problems. Today's action will significantly reduce emissions from cars and light trucks and hence will significantly reduce the health risks posed by air pollution. This section summarizes the results of the analyses we performed to arrive at our determination that continuing air quality problems are likely to exist, that these air quality problems would be in part due to emissions from cars and light trucks, and that the new standards promulgated by today's final rule will improve air quality and mitigate other environmental problems.
Air quality in the United States continues to improve. Nationally, the 1997 air quality levels were the best on record for all six criteria pollutants.
Ambient ozone is formed in the lower atmosphere through a complex interaction of VOC and NO
The health effects of high ozone and PM levels are not the only reason for concern about continuing air pollution. Ozone and PM also harm plants and damage materials. PM reduces visibility and contributes to significant visibility impairment in our national parks and monuments and in many urban areas. In addition, air pollution from motor vehicles contributes to cancer and other health risks, acidification of lakes and streams, eutrophication of coastal and inland waters, and elevated drinking water nitrate levels. These problems impose a substantial burden on public health, our economy, and our ecosystems.
In recognition of this burden, Congress has passed and subsequently amended the Clean Air Act. The Clean Air Act requires each state to have an approved State Implementation Plan (SIP) that shows how an area plans to meet its air quality obligations, including achieving and then maintaining attainment of all of the National Ambient Air Quality Standards (NAAQS), such as those for ozone and PM. The Clean Air Act also requires EPA to periodically re-evaluate the NAAQS in light of new scientific information. Our most recent re-evaluation of the ozone and PM NAAQS led us to revise both standards (62 FR 38856, July 18, 1997 and 62 FR 38652, July 18, 1997). These revised standards reflected additional information that had become available since the previous revision of the ozone and PM standards, respectively.
On May 14, 1999, a panel of the United States Court of Appeals for the District of Columbia Circuit reviewed EPA's revisions to the ozone and PM NAAQS and found, by a 2-1 vote, that sections 108 and 109 of the Clean Air Act, as interpreted by EPA, represent unconstitutional delegations of Congressional power.
As a result of the Court's decision, requirements on the States to implement the new 8-hour ozone standard have been suspended although the standard itself is still in force and the science behind it has generally not been contradicted. The court also did not question EPA's findings regarding the health effects of PM
Carbon monoxide (CO) can cause serious health effects for those who suffer from cardiovascular disease, such as angina pectoris. There has been considerable progress in attaining the longstanding NAAQS for carbon monoxide, largely through more stringent standards for CO from motor vehicles. This progress has been made despite large increases in travel by vehicle. In 1997, there were about 9 million people living in three counties with CO concentrations above the level of the CO NAAQS. In the recent past, this figure has fluctuated up and down. At the present time there are 15 counties classified as serious CO nonattainment areas, all with a recent history of NAAQS violations. At this time, prospects for these areas attaining by the serious CO area attainment deadline of December 31, 2000 are uncertain. While violations of the NAAQS have not occurred recently in most of the other 33 counties still classified as nonattainment, even these must demonstrate that they will remain safely below the NAAQS for ten years despite expected growth in vehicle travel and other sources of CO emissions before they can be reclassified to attainment. Because of the large role of motor vehicles in causing high ambient CO concentrations, where there is reason to be concerned about CO attainment and maintenance, local areas look to national emission standards for most of the solution.
As discussed below, EPA has also finalized regulations that regions and states implement plans for protecting and improving visibility in the 156 mandatory Federal Class I areas as defined in Section 162(a) of the Clean Air Act. These areas are primarily national parks and wilderness areas.
To accomplish the goal of full attainment in all areas according to the schedules for the various NAAQS, and to achieve the goals of the visibility program, the federal government must assist the states by reducing emissions from sources that are not as practical to control at the state level as at the federal level. Vehicles and fuels move freely among the states, and they are produced by national or global scale industries. Most individual states are not in a position to regulate these industries effectively and efficiently. The Clean Air Act therefore gives EPA primary authority to regulate emissions from the various types of highway vehicles and their fuels. Our actions to reduce emissions from these and other national sources are a crucial and essential complement to actions by states to reduce emissions from more localized sources.
If we were not to adopt new standards to reduce emissions from cars and light trucks, emissions from these vehicles would remain a large portion of the emissions burden that causes elevated ozone and continued nonattainment with the ozone NAAQS, which in turn would affect tens of millions of Americans. Because the contribution of cars and light trucks to both local emissions and transported pollution would be so great, and the expected emission reduction shortfall in many areas is so large, further reductions from cars and light trucks will be an important element of many attainment strategies, especially for ozone in the 2007 to 2010 time frame. The contribution of these vehicles to PM exposure and PM nonattainment would also remain significant, and would increase considerably if diesel engines are used in more cars or light trucks. Furthermore, without new standards, steady annual increases in fleet size and miles of travel would outstrip the benefits of current emission controls, and would cause ozone-forming emissions from cars and trucks to grow each year starting about 2013.
The standards being promulgated by today's actions will reduce emissions of ozone precursors and PM precursors from cars and light trucks greatly. However, even with this decrease, many areas will likely still find it necessary to obtain additional reductions from other sources in order to fully attain the ozone and PM NAAQS. Their task will be easier and the economic impact on their industries and citizens will be lighter as a result of the standards promulgated by today's actions. Following implementation of the Regional Ozone Transport Rule, states will have already adopted emission reduction requirements for nearly all large sources of VOC and NO
We project that today's actions will also have important benefits for carbon monoxide, regional visibility, acid rain, and coastal water quality.
For these and other reasons discussed in this document, we have determined that significant emission reductions will still be needed by the middle of the next decade and beyond to achieve and maintain further improvements in air quality in many, geographically dispersed areas. We also believe that a significant portion of these emission reductions will be obtained by reducing emissions from cars and light trucks as a result of today's actions. We believe that such reductions are necessary (since cars and light trucks are such large contributors to current and projected ozone problems) and reasonable (since these reductions can be achieved at a reasonable cost compared to other alternative reductions).
The remainder of this section describes the health and environmental problems that today's actions will help mitigate and the expected health and environmental benefits of these actions. Ozone is discussed first, followed by PM, other criteria pollutants, visibility, air toxics, and other environmental impacts. The emission inventories and air quality analyses are explained more fully in the Regulatory Impact Analysis for today's actions.
Ground-level ozone is the main harmful ingredient in smog.
Short-term (1-3 hours) and prolonged (6-8 hours) exposures to ambient ozone at levels common in many cities have been linked to a number of health effects of concerns. For example, increased hospital admissions and emergency room visits for respiratory causes have been associated with ambient ozone exposures at such levels. Repeated exposures to ozone can make people more susceptible to respiratory infection, result in lung inflammation, and aggravate pre-existing respiratory diseases such as asthma. Other health effects attributed to ozone exposures include significant decreases in lung function and increased respiratory symptoms such as chest pain and cough. These effects generally occur while individuals are engaged in moderate or heavy exertion.
Children active outdoors during the summer when ozone levels are at their highest are most at risk of experiencing such effects. Other at-risk groups include adults who are active outdoors (
Ozone also affects vegetation and ecosystems, leading to reductions in agricultural and commercial forest yields, reduced growth and survivability of tree seedlings, and increased plant susceptibility to disease, pests, and other environmental stresses (
Many areas which were classified as nonattainment when classifications were made under the 1990 Clean Air Act Amendments have not experienced violations more recently. However, 50 metropolitan areas had ozone design values above the NAAQS in either or both of the 1995-1997 and the 1996-1998 monitoring periods. In many urban areas, the downward trend in ozone that prevailed earlier has become less strong or stopped in the last few years, even when adjustments are made for meteorological conditions. We believe that one factor that has worked against ozone improvement in the last few years has been the growing use of light trucks with higher emissions than the cars used formerly. The predictions of future ozone concentrations used in developing today's action take account of this growing use of light trucks.
We have determined that additional emission reductions are needed to attain and maintain the 1-hour ozone NAAQS. This overall conclusion is based on our prediction that 26 metropolitan areas are each certain or highly likely to need additional reductions, and that an additional 12 areas each have a moderate to significant probability of needing them.
To determine whether additional reductions are needed in order to attain and maintain the ozone NAAQS, we used ozone modeling to predict what areas would not attain the NAAQS in the future. We accounted for the emission reductions that have already been achieved, those that will be achieved in the future by actions already underway, and increases in emissions expected from increased use of sources of pollution.
In our May 13, 1999 proposal, we presented information from photochemical modeling we performed to predict what areas would meet the ozone NAAQS in 2007. The year 2007 falls after the expected date of most emission reductions which states are required to achieve or have otherwise committed to achieve, and near the attainment deadline for many ozone nonattainment areas. We presented additional information from the same photochemical modeling work in two supplemental notices, on June 30, 1999 (to better explain the basis for our proposal in light of the Court's ruling on the 8-hour ozone NAAQS), and October 25, 1999 (to explain the implications for our Tier 2/Gasoline Sulfur proposal from our more recent proposal, which we expect to make final shortly, to re-instate the 1-hour ozone NAAQS in many areas). In Response to Comments on these Federal Register notices, we made revisions to our own ozone modeling. We also obtained ozone modeling results from a number of state air planning agencies and from members of the automobile manufacturing industry. We have considered all of this information as part of our determination that the regulations promulgated in this rule are needed and appropriate.
Based on the available ozone modeling and other information, we project that there are 26 metropolitan areas which will be unable to attain and maintain the NAAQS, in the absence of additional reductions. These areas had a combined population of over 86 million in 1996, and are distributed across most regions of the U.S. We have concluded that each is certain or very likely to require additional reductions to attain the NAAQS. Taken together and considering their number, size, and geographic distribution, these areas establish the case that additional reductions are needed in order to attain and maintain the 1-hour standard.
In addition, our analysis suggests there will be other areas that will have problems attaining and maintaining compliance with the one-hour ozone standard in the future. There are 12 additional metropolitan areas with a total 1996 population of over 25 million people in this category. EPA's ozone modeling for 2007 predicts exceedances for each of these areas. However, for six of them local recent monitoring information is not indicating nonattainment. Given how close to nonattainment these areas are, EPA believes it is likely that at least a significant subset of this group of areas will face compliance problems by 2007 or beyond if additional actions to lower air emissions are not taken. This belief is based on historical experience with areas that will undergo economic and population growth over time and that are in larger regions that are also experiencing growth. The other six areas in this group are nonattainment now, and local modeling shows them reaching attainment by 2005 or 2007. Modeling uncertainties and growth beyond the attainment date make it likely that at least some of these areas will also face compliance problems if additional actions to lower air emissions are not taken. This situation further supports our determination that additional reductions in mobile source emissions are needed for attainment and maintenance.
We would like to emphasize that the advantages of the Tier 2/Gasoline Sulfur program will be enjoyed by the whole country. There are important advantages for approximately 30 more metropolitan
In every area of the country, the new standards will give transportation planning bodies and industrial development leaders more options within the area's overall emissions constraints. This will allow local and state officials to better accommodate local needs and growth opportunities. With these new standards for vehicles and gasoline, unusually adverse weather or strong local economic growth will be less likely to cause ozone levels high enough to trigger the planning requirements of the Clean Air Act. In addition, by reducing emissions and ozone levels across the nation as a whole, there will be less transport of ozone between areas, reducing the amount of ozone entering downwind areas. This will give the downwind areas a better opportunity to maintain and attain the NAAQS through local efforts.
All of our determinations presented here about the need for the Tier 2/Gasoline Sulfur program take into account the prior NO
The ozone modeling we presented in our proposal and the two supplemental notices was originally conducted as part of our development of the Regional Ozone Transport Rule. The “revised budget” emission control scenario we modeled for the Regional Ozone Transport Rule contained the right set of existing and committed emission controls for it to serve as the starting point for making our determination on the need for additional emission reductions. We added a new “control case” to represent the effects of our proposed vehicle and gasoline standards.
This ozone modeling provided predictions of ozone concentrations in 2007 across the eastern U.S., under certain meteorological conditions. Predictions of attainment or nonattainment are based on these predicted ozone concentrations. Two approaches to making attainment predictions have been used or advocated in the past: a rollback approach and an exceedance approach. In the NPRM of May 13, 1999, we presented predictions of attainment and nonattainment using a rollback approach. For the 1-hour standard, we reported that 8 metropolitan areas and two rural counties were predicted to be in nonattainment in 2007 under the rollback method. In the first supplemental notice of June 30, 1999 we presented a prediction that 17 areas would be nonattainment based on the exceedance method, and invited comment on all aspects of the modeling and its interpretation. Our second and last notice on October 27, 1999, presented predictions of violations using the exceedance method for additional areas which we had previously excluded because the 1-hour standard did not apply to them. This was in anticipation of the reinstatement of the 1-hour standard to these areas, which we proposed on October 25, 1999 and expect to complete very soon. 64 FR 57524. We also announced that we were conducting another round of modeling, described below. See the Response to Comments document for more discussion of the rollback and exceedance approaches.
We have updated and expanded our ozone modeling. We updated the ozone modeling so that it is now based on estimates of vehicle emissions that reflect the most recent data and our best understanding of several aspects of emissions estimation.
While we considered these improvements necessary and appropriate in light of comments and other information available to us, the actual results of the two rounds of modeling with regard to the need for additional reductions have turned out to be similar. The latest round of modeling provided us ozone predictions for 2007 and 2030 in the eastern U.S., and for 2030 in the western U.S. There are some differences in specific results, where and when the two models can be directly compared. However, the same conclusion would be reached from either, namely that there is a broad set of areas with predicted ozone concentrations in 2007 above 0.124 ppm, in the baseline scenario without additional emission reductions.
We have compared and supplemented our own ozone modeling with other modeling studies, either submitted to us as comments to this rulemaking, as state implementation plan (SIP) revisions, or brought to our attention through our consultations with states on SIP revisions that are in development. The ozone modeling in the SIP revisions has the advantage of using emission inventories that are more specific to the area being modeled, and of using meteorological conditions selected specifically for each area. Also, the SIP revisions included other evidence and analysis, such as analysis of air quality and emissions trends, observation based models that make use of data on concentrations of ozone precursors, alternative rollback analyses, and information on the responsiveness of the air quality model. For some areas, we decided that the predictions of attainment or nonattainment from our
As discussed in detail below, it is clear that the NO
Based on our ozone modeling, we have analyzed ozone predictions for 52 metropolitan areas for 1996, 2007, and 2030. In addition, we reviewed ozone attainment modeling and other evidence covering 15 of these areas, from SIP submittals or from modeling underway to support SIP revisions. This local modeling addressed only the current or requested attainment date in each area. We then made attainment and nonattainment predictions from this information.
The general pattern we observed with the baseline scenario, i.e., without new emission reductions, is a broad reduction between 1996 and 2007 in the geographic extent of ozone concentrations above the NAAQS, and in the frequency and severity of exceedances. This is consistent with the national emissions inventory trend between these two years. At the same time, we also found that peak ozone concentrations and the frequency of exceedances in 2030 were generally somewhat higher than in 2007 for most areas analyzed. This too is consistent with our analysis of emission inventory trends, which shows that the total NO
Within this general pattern of ozone attainment changes between 1996 and 2030, we have determined that 26 metropolitan areas are certain or highly likely to need additional reductions to attain and maintain the 1-hour ozone NAAQS. These 26 areas are those that have current violations of the 1-hour ozone NAAQS and are predicted by the best ozone modeling we have available to still be in violation without a new federal vehicle program in 2007.
As indicated above, in reaching this conclusion about these 26 areas, we examined local ozone modeling in SIP submittals. These local analyses are considered to be more extensive than our own modeling for estimating whether there would be NAAQS nonattainment without further emission reductions, when interpreted by a weight of evidence method which meets our guidance for such modeling. One of the areas which submitted a SIP revision was a special case. We have recently proposed to approve the 1-hour ozone attainment demonstration for the nonattainment area of Washington, D.C. (but not Baltimore). We have nevertheless included this area on the list of 26 that are certain or highly likely to require further reductions to attain and maintain, because its SIP attainment demonstration assumed emission reductions from vehicles meeting the National Low Emissions Vehicle (NLEV) standards.
However, by its own terms, the NLEV standards would not extend beyond the 2003 model year if we did not promulgate Tier 2 vehicle standards at least as stringent as the NLEV standards. See 40 CFR 86.1701-99(c). Thus, the emission reductions relied upon from 2004 and later model year NLEV vehicles are themselves “further reductions” for the purposes of CAA section 202(i).
The 1-hour ozone NAAQS presently does not apply in 12 of the 26 areas listed in Table III.B-1, but we have proposed to re-instate it and expect to complete that action shortly. These areas are indicated in the table. Our decision to include these areas on this list is based on the contingency that we will re-instate the 1-hour standard in these areas. However, even if we considered only the 14 areas where the 1-hour standard applies as of the signature date of this notice, we have concluded that our determination would be the same.
There are 12 additional metropolitan areas, with another 25.3 million people in 1996, for which the available ozone modeling suggests significant risk of failing to attain and maintain the 1-hour ozone NAAQS without additional emission reductions. Table III.B-2 lists the areas we put in this second category. Our own ozone modeling predicted these 12 areas to need further reductions to avoid violations in 2007. For six of these areas, recent air quality monitoring data indicate violation, but we have reviewed local ozone modeling and other evidence indicating attainment in 2007.
For the other six of the 12 areas, the air quality monitoring data shows current attainment but with less than a 10 percent margin below the NAAQS. This suggests these areas may remain without violations for some time, but we believe there is still a moderate risk of future violation of the NAAQS because meteorological conditions may be more severe in the future.
It is highly likely that at least some of these 12 areas will violate the NAAQS without additional reductions, and it is a distinct possibility that many of them will do so. We consider the situation in these areas to support our determination that, overall, additional reductions are needed for attainment and maintenance. However, we reiterate that our predictions for the 26 areas listed in Table III.B-1, and even our predictions for only the 14 of those 26 for which the 1-hour standard now applies, are a sufficient basis for our determination of an overall need for additional reductions and for our actions today.
We received detailed comments from the automobile industry related to ozone modeling and the need for additional emission reductions in order to attain and maintain. These were of three types.
As explained in the final RIA, our very latest estimates of car and light truck emissions without the benefits of our new standards are actually somewhat higher than the estimates used in the final round of ozone modeling, because the most recent data indicate even more serious adverse emissions effects from sulfur in
The auto industry commenters recommended the use of rollback as the single method for making attainment and nonattainment predictions from predicted ozone concentrations. They stated that the rollback method would be more consistent than the exceedance method with the NAAQS's allowance of three exceedances in a three year period. They also believed that the rollback method would compensate for what they considered to be model over predictions of ozone concentrations. We believe that the rollback method is not appropriate for use as the sole, or even a primary, test of 1-hour ozone attainment or nonattainment. A rollback analysis may overlook violations that occur away from ozone monitors, and it may inappropriately project the effect of a recent period of favorable weather into the prediction of future attainment. In determining the attainment and maintenance prospects of numerous areas, as here, it is not possible to assemble and consider the full set of local evidence that should accompany any consideration of a rollback analysis. In such a situation, we believe that the exceedance method is the appropriate choice. A fuller explanation of our reasons for considering the exceedance method more appropriate than rollback is given in our Response to Comments document.
We have not completely excluded the rollback approach from the determinations in this rulemaking. We have considered it for those areas for which we had enough information to allow us to consider it in its proper context, i.e., for those areas covered by recent 1-hour SIP submissions. Of these areas, we concluded that some will not attain without additional reductions and some will.
While we disagree with the use of the rollback method, we have conducted a hypothetical analysis of 2007 attainment in all areas based only on our own ozone modeling, applying the rollback method recommended by the commenters. We calculated in this analysis that 15 metropolitan areas and three other counties with nearly 56 million in population in 1996 would violate the NAAQS in 2007. Moreover, these 15 metro areas are geographically spread out
The main difference between the automobile industry's ozone modeling and ours is in the emission estimates. We have reviewed the emissions estimates used in the industry studies. We concluded that the industry's emissions estimates employ inappropriate analytical steps in the calculation. Among the problems are that the adjustments for the benefits of inspection and maintenance programs were not consistent with the base estimate of in-use emissions, and the sales trend towards light trucks and SUVs was not properly captured. Also, as stated, we disagree with the use of the rollback approach as the sole test of attainment. As a consequence, we conclude that the industry's ozone modeling is not an appropriate basis for making predictions of future attainment or nonattainment. The final RIA explains in detail how we have addressed these and other emissions modeling issues in a manner which is more technically consistent and correct,
The material on ozone modeling submitted by the commenters, having been prepared by the rollback method, was difficult to re-interpret according to our preferred exceedance method. However, it appears that if this modeling were interpreted by the exceedance method, it would indicate 2007 nonattainment in Baltimore and Washington, D.C. in addition to New York City, Chicago, Milwaukee, western Michigan, Baton-Rouge, and Houston. Overall, we conclude that the material submitted by the automobile industry does not contradict the facts we have used to make our determinations or the actions we are taking today.
The predictions of ozone concentrations from the ozone modeling
Emissions of VOCs and NO
We have made significant improvements in the analysis used to estimate the emission inventory impacts of this action, including improving the emission factor modeling, using more detailed local modeling input, and using a more conservative (lower) estimate of VMT growth. These changes are detailed in the Regulatory Impact Analysis for this rule. The following discussion is based on this improved analysis.
In addition to the improvements which are incorporated in this analysis, we also made further improvements in the emission factor modeling after analyzing comments which we did not have time to incorporate into the detailed inventory analysis described here. The most notable change is related to data which indicates that NO
Motor vehicle emission controls have led to significant improvements in emissions released to the air (the “emission inventory”) and will continue to do so in the near term
Figure III-1 illustrates this expected trend in car and light truck NO
Today's action will significantly decrease NO
The lower sulfur levels in today's action will produce large emission reductions on pre-Tier 2 vehicles as soon as low-sulfur gasoline is introduced, in addition to enabling Tier 2 vehicles to achieve lower emission levels. Among the pre-Tier 2 vehicles, the largest per vehicle emission reductions from lower sulfur in gasoline will be achieved from vehicles which automobile manufacturers will have sold under the voluntary National Low Emission Vehicle program. These vehicles are capable of substantially lower emissions when operated on low sulfur fuel. Older technology vehicles experience a smaller but significant effect.
In 2007, when all gasoline will meet the new sulfur limit and when large numbers of 2004 and newer vehicles meeting these standards will be in use, the combined NO
VOC emissions will also be reduced by today's action, with reductions increasing as the fleet turns over. We estimate that the reductions as a percent of emissions from cars and light trucks will be 7 percent in 2007 and grow to 17 percent in 2020.
As discussed earlier, in California, smaller but still substantial reductions in both NO
These estimates of emission reductions reflect a mixture of urban, suburban, and rural areas. However, cars and light trucks generally make up a larger fraction of the emission inventory for urban and suburban areas, where human population and personal vehicle travel is more concentrated than emissions from other sources such as heavy-duty highway vehicles, power plants, and industrial boilers. We have estimated emission inventories for three cities using the same methods as were used to project the nationwide inventories, and we present the results for 2007 below in Table III.B-4.
These results confirm that light-duty vehicles make up a greater share of the NO
Another useful perspective from which to view the magnitude of the emission reductions from today's proposal is in terms of the additional emission reductions from all human sources that areas will need to attain the 1-hour ozone standard. For this analysis, we reviewed our proposals for action on the 1-hour attainment demonstrations submitted by the states. With these proposals, EPA identified estimates of additional emission reductions (measures in addition to those submitted by the state in their plans) necessary for attainment for some
EPA and the States already have significant efforts underway to lower ozone precursor emissions through national regulations and State Implementation Plans. Table III.B-5 shows the contribution of Tier 2 to the substantial State-led efforts to provide attainment with the ozone NAAQS. Since the Tier 2 program has evolved in the past year after much of the States' efforts were completed, many of the States were unable to estimate the benefits of Tier 2 in their areas. EPA's proposal actions on these SIPs for the ozone NAAQS addresses the need for Tier 2 in many areas. More specifically, Tier 2 is being used to help States identify additional measures, in addition to those in their plans, necessary for attainment.
These estimates are subject to change as the states review and comment on our proposed action on the SIPs. These figures show that today's proposal would make a very substantial contribution to these cities' attainment programs, but that there will still be a need for additional reductions from other sources. The emission reductions from today's proposal would clearly not exceed the reductions needed from an air quality perspective for these areas.
The large reductions in emissions of ozone precursors from today's standards will be very beneficial to federal and state efforts to lower ozone levels and bring about attainment with the current one-hour ozone standard. The air quality modeling for the final rule shows that improvements in ozone levels are expected to occur throughout the country because of the Tier 2/Gasoline Sulfur program.
During the public comment period on the proposed rule, EPA received several comments that expressed concern about potential increases in ozone that might occur as a result of this rule. As indicated above, the air quality modeling results indicate an overall reduction in ozone levels in 2007 and 2030 during the various episodes modeled. In addition to ozone reductions, a few areas had predicted ozone increases in portions of the area during parts of the episodes modeled. In most of these cases, we observed a net reduction in ozone levels in these areas due to the program. In the very small number of exceptions to this, the Agency did find benefit from reduction of peak ozone levels. Based upon a careful examination of this issue, including EPA's modeling results as well as consideration of the modeling and analyses submitted by commenters, it is clear that the significant ozone reductions from this rule outweigh the limited ozone increases that may occur. Additional details on this issue are provided in the Response to Comments document and in the Tier 2 Air Quality Modeling Technical Support Document.
Taken together, EPA believes these results indicate that it will be much easier for States to develop State Implementation Plans which will attain and maintain compliance with the one-hour ozone standard. EPA will work with States conducting more detailed local modeling of their specific ozone situation, to ensure that their SIPs will provide attainment. Notably, there are also other upcoming federal measures to lower ozone precursors that will aid these efforts. If the State modeling of local programs shows a need, the Agency will work with states to plan further actions to produce attainment with the NAAQS in order to protect the public's health and the environment. Further details on EPA's modeling results can be found in the Agency's Response to Comments and technical support documents.
The need to control the contribution of cars and light trucks to ambient concentrations of particulate matter (PM) is the basis for our adoption of the new PM emission standards for vehicles. PM is also a supplemental consideration in our promulgation of
For cars and for light trucks under 3750 pounds loaded vehicle weight, we are establishing new emission standards under the provisions of CAA section 202(i), which ties our action to the need for additional emission reductions in order to attain and maintain the NAAQS. The NAAQS relevant to the PM emission standards is the PM
For the vehicles not subject to CAA 202(i), and for the gasoline sulfur limits, our actions are tied to determinations regarding public health and welfare risks more broadly, under CAA sections 202(a), 202(b), and 211(c). The role of NO
PM also poses risks to public health not fully reflected in the PM
Particulate matter (PM) represents a broad class of chemically and physically diverse substances that exist as discrete particles (liquid droplets or solids) over a wide range of sizes. The NAAQS that regulates PM addresses only PM with a diameter less than or equal to 10 microns, or PM
Natural sources of particles in the coarse fraction of PM
Most of the emission sources listed for coarse particles also have a substantial fine particle fraction. Their share of the PM
Secondary PM is dominated by sulfate particles in the eastern U.S. and parts of the western U.S., with nitrate particles and carbonaceous particles dominant in some western areas. Mobile sources can reasonably be estimated to contribute to ambient secondary nitrate and sulfate PM in proportion to their contribution to total NO
The sources, ambient concentration, and chemical and physical properties of PM
Particulate matter, like ozone, has been linked to a range of serious respiratory health problems. Scientific studies suggest a likely causal role of ambient particulate matter in contributing to a series of health effects. The key health effects categories associated with particulate matter include premature mortality, aggravation of respiratory and cardiovascular disease (as indicated by increased hospital admissions and emergency room visits, school absences, work loss days, and restricted activity days), changes in lung function and increased respiratory symptoms, changes to lung tissues and structure, and altered respiratory defense
Motor vehicle particle emissions and the particles formed by the transformation of motor vehicle gaseous emissions tend to be in the fine particle range. Fine particles are a special health concern because they easily reach the deepest recesses of the lungs. Scientific studies have linked fine particles (alone or in combination with other air pollutants), with a series of significant health problems, including premature death; respiratory related hospital admissions and emergency room visits; aggravated asthma; acute respiratory symptoms, including aggravated coughing and difficult or painful breathing; chronic bronchitis; and decreased lung function that can be experienced as shortness of breath.
These effects are discussed further in EPA's “Staff Paper” and “Air Quality Criteria Document” for particulate matter.
EPA first established primary (health-based) and secondary (welfare-based) National Ambient Air Quality Standards for PM
On May 14, 1999, a panel of the U.S. Court of Appeals for the District of Columbia Circuit reviewed EPA's revisions to the ozone and PM NAAQS and found, by a 2-1 vote, that sections 108 and 109 of the Clean Air Act, as interpreted by EPA, represent unconstitutional delegations of Congressional power.
The pre-existing PM
There is additional concern regarding the health effects of PM from diesel vehicles, apart from the health effects which were considered in setting the NAAQS for PM
The most recent PM
Because the types and sources of PM
In the RIA for the establishment of the PM NAAQS, we projected that in 2010 there will be 45 counties not in attainment with the original PM
Table III.C-2 is limited to designated PM
Taken together and considering their number, size, and geographic distribution, these 13 areas are sufficient to establish the case that additional reductions are needed in order to attain and maintain the PM
We are also establishing the new PM emissions standard today to avoid the possibility that PM
In order to assess the potential impact of increased diesel sales penetration on PM emissions, we analyzed the increase in PM
The A.D. Little scenario of increased diesels, and even more so the scenario described in our proposal, would result in dramatic increases in direct PM
The added PM
Fortunately, the standards included in today's actions will result in a steady decrease in total direct PM
We are establishing tighter PM standards for cars and light trucks to help avoid the adverse impact of greater diesel PM emissions on PM
We are not basing our promulgation of the Tier 2 vehicle standards on a finding on the need for additional emission reductions in order to attain and maintain the NAAQS for PM
The annual and 24-hour PM
Therefore, if we considered it appropriate to proceed with implementing the PM
Moreover, gasoline and diesel cars and light trucks have a more important contributing role for ambient PM
The NO
Because virtually all of the PM reduction from the Tier 2/Gasoline
The standards being promulgated today will help reduce levels of three other pollutants for which NAAQSs have been established: carbon monoxide (CO), nitrogen dioxide (NO
The reductions in SO
Visibility impairment occurs as a result of the scattering and absorption of light by particles and gases in the atmosphere. It is most simply described as the haze that obscures the clarity, color, texture, and form of what we see. The principal cause of visibility reduction is fine particles between 0.1 and 1 μm in size. Of the pollutant gases, only NO
The CAA requires EPA to protect visibility, or visual air quality, through a number of programs. These programs include the national visibility program under Sections 169a and 169b of the Act, the Prevention of Significant Deterioration program for the review of potential impacts from new and modified sources, and the secondary NAAQS for PM
There has been improvement in visibility in the western part of the country over the last ten years. However, visibility impairment remains a serious problem in Class I areas. Visibility in the East does not seem to have improved. As one part of addressing this national problem, EPA has required states to adopt and implement effective plans for protecting and improving visibility in Class I federal areas (64 FR 35714, July 1, 1999).
Today's actions will result in visibility improvements due to the reduction in local and upwind PM and PM precursor emissions. Since mobile source emissions contribute to the formation of visibility-reducing PM, control programs that reduce the mobile source emissions of direct and secondary PM would have the effect of improving visibility. The Grand Canyon Visibility Transport Commission's final recommendations report
The recent Northern Front Range Air Quality Study provides another indication of how important car and light truck emissions can be to fine PM and visibility. This study reported findings that indicate that cars and light trucks are responsible for 39 percent of fine PM at a site within the metropolitan Denver area, and for 40 percent at a downwind rural site. This contribution includes both direct PM and indirect PM formed from sulfur dioxide and NO
The analysis of economic benefits and costs found in Section IV.D.5. accounts for the economic benefits of the visibility improvements expected to result from today's actions.
Section 202(a) provides that EPA may promulgate standards regulating any air pollutants that in the Administrator's judgment, cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare. Section 202(l) provides specific provisions for regulation of hazardous air pollutants from motor vehicles and fuels, and states that at a minimum such regulations should apply to emissions of benzene and formaldehyde.
Emissions from cars and light trucks include a number of air pollutants that are known or suspected human or animal carcinogens or that are known or suspected to have other, non-cancer health impacts. These pollutants include benzene, formaldehyde, acetaldehyde, 1,3-butadiene, and diesel particulate matter. For several of these pollutants, motor vehicle emissions are believed to account for a significant proportion of total nation-wide emissions. All of these compounds are present in exhaust emissions; benzene is also found in evaporative emissions from gasoline-fueled vehicles.
The health effects of diesel particulate matter are of particular relevance to today's actions, because of the possibility for increased diesel-powered truck sales and the more stringent PM standard that will apply to these trucks as a result of today's actions. While we have not finalized our decision about the carcinogenicity of diesel exhaust, we are in the process of addressing this question. The Agency's recently released draft assessment
International Agency for Research on Cancer (1989) Diesel and gasoline engine exhausts and some nitroarenes, Vol. 46. Monographs on the evaluation of carcinogenic risks to humans. World Health Organization, International Agency for Research on Cancer, Lyon, France.
World Health Organization (1996) Diesel fuel and exhaust emissions: International program on chemical safety. World Health Organization, Geneva, Switzerland.
California Environmental Protection Agency, Office of Environmental Health Hazard Assessment: Proposed Identification of Diesel Exhaust as a Toxic Air Contaminant, Part B Health Risk Assessment for Diesel Exhaust. April 22, 1998.
Because our assessment for diesel exhaust is not complete, we are not presenting absolute estimates of how potential cancer risks from diesel particulate matter could be affected by today's rule. However, we can offer a qualitative or relative discussion of these risks. Diesel engines used in nonroad equipment and heavy-duty highway vehicles currently constitute a far larger source of diesel PM than cars and light-duty trucks, since diesel engines are used in a very small portion of the cars and light-duty trucks in service today. However, engine and vehicle manufacturers have projected that diesel engines are likely to be used in an increasing share of cars and light trucks, and some manufacturers have announced capital investments to build such engines.
If these projections are valid, then the proportion of cars and light trucks powered by diesel engines, and the associated potential health risks from diesel PM, could increase substantially. We modeled the most likely level of increase in light duty diesel engine sales developed for the American Petroleum Institute.
Today's rule would limit the increase in the potential cancer risks from cars and light trucks associated with any potential increase in light-duty diesel engines. Using the same sales projections discussed above, we have estimated that today's rule would limit the increase in total highway diesel PM emissions in 2020 due to growth in light duty diesels to under 10 percent, in contrast to the 80 percent increase projected to occur without the Tier 2 PM standards. An analogous analysis that accounted for exposure patterns, but that assumed even more widespread use of diesels in the car and light truck fleet, found that today's rule would limit the increase in total highway diesel PM exposure to about 8 percent. This analysis is discussed more fully in Chapter III.F.2 of the Regulatory Impact Analysis. In addition, the VOC emission reductions resulting from today's rule would reduce the potential cancer risk posed by air pollutants other than diesel PM emitted by cars and light trucks, since many of these pollutants are themselves VOCs. Furthermore, the rule would align the formaldehyde standards for all Tier 2 LDVs and LDTs with the formaldehyde standards for LDVs and LDT1s from the NLEV program, thereby helping to harmonize the Federal and California formaldehyde standards.
The analysis of economic benefits and costs found in Section IV.D.5. does not account for the economic benefits of the reduction in cancer risk from air toxics that could result from today's rule. Although we have completed a peer reviewed assessment of the impact of today's rule on exposure to toxic emissions, we have not engaged in a peer-reviewed assessment of the baseline air toxics risks (including a final quantitative risk assessment of the diesel particulate risks) or of the reductions that would be achieved by today's rule.
We plan to complete our analysis of air toxics risks as part of our responsibilities under section 202(l)(2) of the Clean Air Act, which requires EPA to establish regulations for the control of hazardous air pollutants from motor vehicles. The regulations may address vehicle emissions or fuel properties that influence emissions, or both. We plan to issue a proposal to address this requirement in April 2000, and a final rule in December 2000.
Acid deposition, or acid rain as it is commonly known, occurs when SO
Acid deposition primarily affects bodies of water that rest atop soil with a limited ability to neutralize acidic compounds. The National Surface Water Survey (NSWS) investigated the effects of acidic deposition in over 1,000 lakes larger than 10 acres and in thousands of miles of streams. It found that acid deposition was the primary cause of acidity in 75 percent of the acidic lakes and about 50 percent of the acidic streams, and that the areas most sensitive to acid rain were the Adirondacks, the mid-Appalachian highlands, the upper Midwest and the high elevation West. The NSWS found that approximately 580 streams in the Mid-Atlantic Coastal Plain are acidic primarily due to acidic deposition. Hundreds of the lakes in the Adirondacks surveyed in the NSWS have acidity levels incompatible with the survival of sensitive fish species. Many of the over 1,350 acidic streams in the Mid-Atlantic Highlands (mid-Appalachia) region have already experienced trout losses due to increased stream acidity. Emissions from U.S. sources contribute to acidic deposition in eastern Canada, where the Canadian government has estimated that 14,000 lakes are acidic. Acid deposition also has been implicated in contributing to degradation of high-elevation spruce forests that populate the ridges of the Appalachian Mountains from Maine to Georgia. This area includes national parks such as the Shenandoah and Great Smoky Mountain National Parks.
The SO
While the reduction in sulfur and nitrogen acid deposition will be roughly proportional to the reduction in SO
The analysis of economic benefits and costs found in Section IV.D.5. did not account for the economic benefits of the reduction in acid deposition expected to result from today's actions.
Nitrogen deposition into bodies of water can cause problems beyond those associated with acid rain. The Ecological Society of America has included discussion of the contribution of air emissions to increasing nitrogen levels in surface waters in a recent major review of causes and consequences of human alteration of the global nitrogen cycle in its Issues in Ecology series
Human activity can increase the flow of nutrients into those waters and result in excess algae and plant growth. This increased growth can cause numerous adverse ecological effects and economic impacts, including nuisance algal blooms, dieback of underwater plants due to reduced light penetration, and toxic plankton blooms. Algal and plankton blooms can also reduce the level of dissolved oxygen, which can also adversely affect fish and shellfish populations. This problem is of particular concern in coastal areas with poor or stratified circulation patterns, such as the Chesapeake Bay, Long Island Sound, or the Gulf of Mexico. In such areas, the “overproduced” algae tends to sink to the bottom and decay, using all or most of the available oxygen and thereby reducing or eliminating populations of bottom-feeder fish and shellfish, distorting the normal population balance between different aquatic organisms, and in extreme cases causing dramatic fish kills.
Collectively, these effects are referred to as eutrophication, which the National Research Council recently identified as the most serious pollution problem facing the estuarine waters of the United States (NRC, 1993). Nitrogen is the primary cause of eutrophication in most coastal waters and estuaries
Excessive fertilization with nitrogen-containing compounds can also affect terrestrial ecosystems
Deposition of nitrogen from cars and light trucks contributes to these problems. As discussed in Section III.B. above, today's actions will reduce total NO
The analysis of economic benefits and costs found in Section IV.D.5. does not account for the economic benefits of reduced eutrophication or reduced terrestrial nitrogen deposition expected to result from today's actions.
Despite continued progress in reducing ozone and PM levels, tens of millions of Americans are still exposed to levels of these pollutants that exceed the National Ambient Air Quality Standards. Our projections show that without further action to reduce these pollutants, tens of millions of Americans will continue to breathe unhealthy air for decades to come. Our projections also show that emissions from cars and light trucks will continue to contribute a substantial share of the ozone and PM precursors in current and projected nonattainment areas, and in upwind areas whose emissions contribute to downwind nonattainment, unless additional measures are taken to reduce their emissions. Cars and light trucks also contribute substantially to ambient concentrations of CO. These vehicles will also continue to contribute to the ambient PM that affects visibility in Class I federal areas and some urban areas. Emissions from cars and light trucks also play a significant role in a wide range of health and environmental problems, including known and potential cancer risks from inhalation of air pollutants (a problem that could become more significant if sales of diesel-powered cars and light trucks were to increase), health risks from elevated drinking water nitrate levels, acidification of lakes and streams, and eutrophication of inland and coastal waters.
Today's actions will reduce NO
We believe that the standards being promulgated today for gasoline-fueled vehicles are well within the reach of existing control technology. Our determination of feasibility is based on the use of catalyst-based strategies that are already in use and are well proven on the existing fleet of vehicles. In fact, as you will see below, many current engine families are already certified to levels at or below the new final Tier 2 requirements. All of the certification and research testing discussed below was performed on low-sulfur test fuel (nominally 30 ppm).
Certainly, larger vehicles and trucks, which are heavier and have larger frontal areas, will face the biggest challenges in meeting the final Tier 2 standards. However, conventional technology will be sufficient for even these vehicles, especially in light of the extra leadtime we have provided before LDT3s and LDT4s have to meet Tier 2 levels. We are also changing the test conditions for these trucks from “adjusted loaded vehicle weight” to “loaded vehicle weight.” Adjusted loaded vehicle weight, suitable for commercial truck operation, loads the truck to half of its full payload. Loaded vehicle weight, on the other hand, represents curb weight plus 300 pounds. This change more accurately reflects how these vehicles are used and makes heavy LDT testing consistent with passenger car and light LDT testing. This change is consistent with treating these vehicles as they were designed,
Emission control technology has evolved rapidly in recent years. Emission standards applicable to 1990 model year vehicles required roughly 90 percent reductions in exhaust HC and CO emissions and a 75 percent reduction in NO
The types of changes being seen on current vehicles have not yet reached their technological limits, and continuing improvement will allow both LDVs and LDTs to meet the final standards. The RIA describes a range of specific techniques that we believe could be used. These range from improved computer software and engine air-fuel controls to increases in precious metal loading and other exhaust system/catalyst system improvements. All of these technologies are currently used on one or more production vehicle models. There is no need to invent new approaches or technologies. The focus of the effort is primarily development,
We can gain significant insight into the difficulty of meeting the final new standards by looking at current full-life certification data. There are at least 48 engine family-control systems combinations, out of approximately 400, certified in 1999 at levels below the Tier 2 NO
All of the above vehicles are already able, or close to being able, to certify to our final standards. The further reductions needed are those to provide a compliance margin, or cushion, between the certified level and the emission standard. The degree of compliance margin required is a function of a variety of factors designed to provide the manufacturer a high confidence that production vehicles will meet the standards in-use over their useful life. Historically, these determinations are manufacturer specific, with cushions generally growing smaller as standards decline (reflecting more precision and repeatability in vehicle performance as more sophisticated controls are developed). The certification data reflects compliance cushions from as little as 20 percent below the standard to as high as 80 percent below the standard.
The manufacturers commented that the most difficult vehicles to bring into compliance with the Tier 2 standards would be the larger light-duty trucks, specifically those trucks currently certified under the LDT3 and LDT4 weight categories. Because of this, we undertook a technology demonstration program aimed at lowering the emissions of several large 1999 light-duty trucks. Two LDT3 Chevrolet Silverado pick-up trucks were tested, one internally and one under contract. Two LDT4 Ford Expedition sport-utility vehicles were also tested, also with one tested internally and one under contract. Both types of vehicles were tested with optional high horsepower engines (270 hp for the Silverado and 230 hp for the Expedition) and were equipped with four-wheel drive. The vehicles had curb weights of 4,500 pounds (GVWR of 6,100 lbs) for the Silverados and 5,800 pounds (GVWR of 7,200 lbs) for the Expeditions.
Figures IV.A.-1 and IV.A.-2 show the results to date of the emissions tests performed during this demonstration program at our National Vehicle and Fuel Emissions Laboratory (NVFEL) and also for emissions tests conducted in parallel by and under contract at Southwest Research Institute (SwRI) using similar Ford Expeditions and GM Chevrolet Silverados. During the evaluation, the trucks were equipped with a variety of catalysts that typically featured higher volume, higher precious metal loading, and higher cell-densities than the original hardware used by the vehicles to meet California LEV-I standards. Details of the catalysts tested are included in the RIA. Different exhaust manifolds featuring an insulating air-gap and low thermal mass were also evaluated. Finally, calibration changes were made to the powertrain control modules
As can be seen in the charts, the emissions of the vehicles tested clearly show the feasibility of the Tier 2 standards on the most difficult to certify vehicle categories. All vehicles reached emission levels well below the Tier 2 full-life NOx and NMOG standards. At the same time, there were no significant impacts on either fuel economy or performance of the vehicles.
Compared to the intermediate (50,000 mile) standards, the Ford Expedition tested at NVFEL consistently emitted NOx at less than one-third of the intermediate useful life standard.
The above results point out that not only are the Tier 2 standards feasible for larger trucks, but there are multiple means that can be taken in order to achieve the necessary emissions levels. All of those paths involve fairly simple enhancements to current technology systems. Furthermore, the testing was conducted with a very limited budget over a limited amount of time. With the interim program for heavy trucks under Tier 2, the manufacturers will have 9 years from the publishing of the Tier 2 rule to bring the largest trucks into compliance with the Tier 2 standards. Manufacturers will also have considerably more resources with respect to calibration changes and hardware design to bring trucks of this type within compliance than were available within this limited, but successful, demonstration.
The Manufacturers of Emission Controls Association (MECA) sponsored a program that took two LDVs (a Crown Victoria and a Buick LeSabre) and one LDT2 (a Toyota T100) certified to the federal Tier 1 standards and replaced the original catalytic converter systems with more advanced catalytic converters, thermally aged to approximately 50,000 miles. With these systems and some related emission control modifications, the LeSabre and T100 emissions were well below our intermediate (50,000 mile) useful life standards, and the Crown Victoria was well below the NMOG standard and very close to the NO
Finally, the California Air Resources Board (ARB) tested five different production LEV light-duty vehicle models. Three of the five models met the Tier 2 standards for NMOG and NO
A more expanded analysis of the feasibility of the Tier 2 standards for gasoline fueled vehicles can be found in the RIA, considering the types of changes that will allow manufacturers to extend effective new controls to the entire fleet of affected vehicles. That analysis includes discussion of gasoline direct-injection engines, as well as the feasibility of the CO, formaldehyde and evaporative emission standards. The conclusion of all of our analyses is that the standards are feasible for gasoline-fueled vehicles. As gasoline-fueled vehicles represent the overwhelming majority of the LDV and LDT population (
The technologies and emission control strategies that will be used for LDT3 and LDT4 vehicles with a GVWR less than 8,500 pounds should apply directly to MDPV vehicles that have a GVWR greater than 8,500 pounds. In our LDT technology demonstration program discussed above, we found that a combination of calibration changes and improvements to the catalyst system resulted in emission levels for NO
The most significant difference between LDT4s less than 8,500 pounds GVWR and MDPVs greater than 8,500 pounds GVWR is that MDPVs have a vehicle weight up to 800 pounds more than LDT4s. MDPVs will also be typically equipped with larger displacement engines. The potential impact of these differences is higher engine-out emissions than LDT4s due to the larger engine displacement and
We are currently testing a Ford Excursion as part of our LDT technology demonstration program. Preliminary baseline results with a ‘green” (
As discussed above, the Tier 2 standards are intended to be “fuel neutral.” In today's document, we establish that the Tier 2 standards are technologically feasible and cost-effective for LDVs and LDTs overall, based on the discussion in Section IV.A.1.a. above. Under the principle of fuel neutrality, all cars and light trucks, including those using diesel engines, will be required to meet the Tier 2 standards. Contrary to some of the comments received on our proposal, given that the overwhelming majority of vehicles in these classes are gasoline-fueled, we do not believe it is appropriate to provide less stringent standards for diesel-fueled vehicles. Manufacturers of LDVs and LDTs today provide consumers with a wide choice of vehicles that are overwhelmingly gasoline-fueled. Less stringent standards for diesels would create provisions that could undermine the emission reductions expected from this program, especially given the expectation that some manufacturers may intend to greatly increase their diesel sales.
As with gasoline engines, manufacturers of diesels have made abundant progress over the past 10 years in reducing engine-out emissions from diesel engines. In heavy trucks and buses, PM emission standards, which were projected to require the use of exhaust aftertreatment devices, were actually met with only engine modifications. Indeed, emissions and performance of lighter diesel engine are rapidly approaching the characteristics of gasoline engines, while retaining the durability and fuel economy advantages that diesels enjoy. Against this background of continuing progress, we believe that the technological improvements that would be needed could be made in the time that would be available before diesels would have to meet the new Tier 2 standards.
Manufacturers may take advantage of the flexibilities in today's rulemaking to delay the need for diesel LDVs and LDTs to meet the final Tier 2 levels until late in the phase-in period (as late as 2007 for LDVs/LLDTs and 2009 for HLDTs), giving manufacturers a relatively large amount of leadtime. In a recent public statement, Cummins Engine Company has indicated that the interim Tier 2 standards in effect for vehicles and trucks in the early years of the Tier 2 program are feasible for diesel equipped models through further development of currently available engine and exhaust aftertreatment technology.
While reductions in “engine-out” emissions, including incorporation of EGR strategies, may continue to be made, increasing emphasis is being placed on various aftertreatment devices for diesels. We believe that the use of aftertreatment devices will allow diesels to comply with the Tier 2 standards for NO
For NO
NO
There is currently a substantial amount of development work being directed at NO
One serious concern with current NO
SCR has been demonstrated commercially on stationary diesel engines and can reduce NO
Regarding PM, applicable aftertreatment devices tend to fall into two categories: Oxidation catalysts and traps. Diesel oxidation catalysts can reduce total PM emissions by roughly 15-30%. They would need to be used in conjunction with further reductions in PM engine-out emissions in order to meet the proposed Tier 2 standards. Diesel particulate traps, on the other hand, can eliminate up to 90% of diesel PM emissions. However, some of the means of accomplishing the regeneration of particulate traps involve catalytic processes that also convert sulfur dioxide in the exhaust to sulfate. These techniques, if used, would also require a low sulfur fuel.
In summary, we believe that the structure of our final program, including the available bins and phase-in periods, will allow the orderly development of clean diesel engine technologies. We believe that the interim standards are feasible for diesel LDV/LDTs, within the bin structure of this rule and without further reductions in diesel fuel sulfur levels. And, as indicated earlier, at least one major diesel engine manufacturer (Cummins) has publicly agreed with this assessment. We further believe that in the long-term, the final standards will be within reach for diesel-fueled vehicles in combination with appropriate changes to diesel fuel to facilitate aftertreatment technologies. Manufacturers have argued that low sulfur diesel fuel will be required to permit diesels to meet the final Tier 2 standards, and we agree. At least one major manufacturer (Navistar) has indicated its belief that the final Tier 2 standards may be achievable for diesel engines with low sulfur diesel fuel.
As we discussed in the previous section, we believe that the stringent standards in this final rule are needed to meet air quality goals and are feasible for LDVs and LDTs. At the same time, we believe that for these standards to be feasible for gasoline LDVs and LDTs, low sulfur gasoline must be made available. The following paragraphs explain why we think gasoline sulfur control must accompany Tier 2 vehicle standards.
Catalyst manufacturers generally use low sulfur gasoline in the development of their catalyst designs. Vehicle manufacturers then equip their vehicles with these catalysts and EPA certifies them to the exhaust emission standards, usually based on testing the manufacturer does using low sulfur gasoline. However, fundamental chemical and physical characteristics of exhaust catalytic converter technology generally result in a significant degradation of emission performance when these vehicles use gasoline with sulfur levels common in most of the country today. This sensitivity of catalytic converters to gasoline sulfur varies somewhat depending on a number of factors, some better understood than others. Clearly, however, as we discuss in the following paragraphs, gasoline sulfur's impact is large, especially in vehicles designed to meet very low emission standards.
This is the reason EPA has decided to adopt a comprehensive approach to addressing emissions from cars and light trucks, including provisions to get low sulfur gasoline into the field in the same time frame needed for Tier 2 vehicles.
We know that gasoline sulfur has a negative impact on vehicle emission controls. Vehicles depend on the catalytic converter to reduce emissions of HC, CO, and NO
Sulfur sensitivity is impacted not only by the catalyst formulation (the types and amounts of precious metals used in the catalyst) but also by factors including the following:
• The materials used to provide oxygen storage capacity in the catalyst, as well as the general design of the catalyst,
• The location of the catalyst relative to the engine, which impacts the temperatures inside the catalyst,
• The mix of air and fuel entering the engine over the course of operation, which is varied by the engine's computer in response to the driving situation and affects the mix of gases entering the catalyst from the engine, and
• The speeds the car is driven at and the load the vehicle is carrying, which also impact the temperatures experienced by the catalyst.
Since these factors vary for every vehicle, the sulfur impact varies for every vehicle to some degree. There is no single factor that guarantees that a vehicle will be very sensitive or very insensitive to sulfur. We now believe that there are not (and will not be in the foreseeable future) emission control devices available for gasoline-powered vehicles that can meet the proposed Tier 2 emission standards that would not be significantly impaired by gasoline with sulfur levels common today.
High sulfur levels have been shown to significantly impair the emission control systems of cleaner, later technology vehicles. The California LEV standards and Federal NLEV standards, as well as California's new LEV-II standards and our Tier 2 standards, require catalysts to be extremely efficient to adequately reduce emissions over the full useful life of the vehicle. In the NPRM we estimated that, based on data from test programs conducted by EPA and the automotive and oil industries, LEV and ULEV vehicles could experience, on average, a 40 percent increase in NMHC and 134 percent increase in NO
This level of emissions increase is significant enough on its own to cause a vehicle to exceed the full useful life emission standards when operated on sulfur levels that are substantially higher than the levels required by today's rule, even with the margin of
For older vehicles designed to meet Tier 0 and Tier 1 emission standards, the effect of sulfur contamination is somewhat less. Still, testing shows that gasoline sulfur increases emissions of NMHC and NO
As discussed in the RIA, NLEV and Tier 2 vehicles are significantly more sensitive to sulfur poisoning than Tier 1 and Tier 0 vehicles. Because of this, even in the absence of Tier 2 standards, gasoline sulfur control to 30 ppm would achieve about 700,000 tons of NO
Sulfur reductions will result in reductions of other pollutants as well. For example, the increase in CO emissions at 330 ppm compared to 30 ppm were very similar to the results above for NMHC. Thus, sulfur reductions would greatly reduce CO emissions. Another example is sulfur reductions will help reduce emissions of particulate matter, providing some benefit to PM nonattainment areas (which may or may not coincide with ozone nonattainment areas) as well as with visibility problems. Sulfur reductions will also have benefits for areas across the country with acid deposition problems. Furthermore, sulfur reduction, by enabling tighter Tier 2 standards and by improving emissions performance of the vehicles already on the road, will lead to fewer NMOG emissions, since, as explained in the RIA, NMOG emissions are also impacted by gasoline sulfur (although to a lesser extent than NO
As we discussed in the last section, sulfur contaminates the catalyst. In addition, essentially all vehicles that have been tested show that this effect is not reversible for one or more pollutants. The ability to reverse sulfur's negative effect on catalyst performance is dependent on a number of factors. The same factors that impact sulfur sensitivity also impact the irreversibility of the sulfur effect. For example, the location of the catalyst relative to the engine, the materials used to provide oxygen storage capacity in the catalyst, and the general design of the catalyst and the mix of air and fuel (A/F) entering the engine over the course of operation affect irreversibility, to name a few.
Perhaps the most significant factors for reversibility are the mixture of air and fuel entering the engine and catalyst temperature. The results of numerous studies and test programs show that rich exhaust (absence of oxygen) mixtures in addition to high catalyst temperatures (in excess of 700°C) can remove sulfur from the catalyst. Rich exhaust mixtures can occur intentionally and unintentionally, depending on the level of sophistication of the fuel control system. An intentional rich exhaust mixture is known as fuel “enrichment.” There are different types of enrichment. For example, there is “commanded” enrichment, which is used to provide extra power when the engine is under a load (
While the amount of fuel enrichment is critical in the removal of sulfur from the catalyst, high catalyst temperature is equally as important. In order to meet strict Tier 2 standards, manufacturers are going to have to balance tight A/F control with improved catalyst performance, with an eye towards better catalyst thermal management. Many manufacturers are going to have to depend more on the precious metal palladium for oxidation of NMOG and CO emissions, as well as the reduction of NO
As discussed above, manufacturers will need to make modifications to their emission system calibrations by optimizing fuel control, spark timing, EGR and other parameters in conjunction with improvements to catalyst systems, in order to meet Tier 2 emission standards. This combination of emission control strategies can result in significant trade-offs between NMOG and NO
Our federal supplemental federal test procedure (SFTP) standards, as well as California's SFTP standards, both of which take effect in the 2001 model year, can further exacerbate this problem. The SFTP standards are intended to better address and control emissions under driving conditions not captured when compliance with our FTP-based exhaust emissions standards is demonstrated, such as operation with the air conditioning turned on or driving at very high rates of acceleration and vehicle speeds (hereafter referred to simply as aggressive driving). This is an important factor in assessing sulfur irreversibility, because Tier 2 vehicles will have to meet more stringent exhaust emission standards and will have to meet these standards over the wider variety of operating conditions
Since wide variations in the A/F ratio help to remove sulfur from the catalytic surface, there is concern that vehicles which meet the SFTP standards, when driven aggressively, will experience insufficient enrichment to purge sulfur from the catalyst. Currently, when driven aggressively, the A/F ratio for most vehicles (those not certified to SFTP standards) is quite variable. Meeting the SFTP standards will ensure that manufacturers carefully control the A/F ratio over essentially all in-use driving conditions. This absence of widely varying A/F could therefore inhibit the removal of sulfur from the catalyst once operation on high sulfur fuel ceased.
In order to quantify how irreversible the sulfur effect would be when catalysts exposed to high sulfur fuel are then exposed to lower sulfur fuel, several test programs were developed by EPA and industry. The vehicles in these test programs consisted of LDVs and LDTs that met either EPA Tier 1 or California LEV and ULEV emission standards. All of the vehicles were first tested at a low sulfur level (
The vehicles tested exhibited a wide range of irreversibility, for reasons that are not fully understood. The data published in the NPRM, showed that the effect of operation on high sulfur fuel was irreversible on one or more pollutants after operation on low sulfur fuel. NO
The sulfur irreversibility test programs that followed the NPRM focused on vehicles that had emission levels that met or were close to Tier 2 emission standards and also met the US06 or aggressive driving portion of the SFTP emission standards. Although numerous vehicles were tested, only four met both of the above criteria. (We had tried to supplement the data base, but we were only able to add a limited number of vehicles.) We also decided to quantify irreversibility for NMHC and NO
The new data exhibited a range of variability among vehicles and pollutants, similar to the data presented in the NPRM. The most important distinction between the new FRM data and the old NPRM data was that the new data showed that, on average, NMHC+NO
As discussed above, the combination of calibration changes and emission system hardware modifications needed to meet our stringent Tier 2 emissions standards, can result in significant trade-offs between NMHC/NMOG and NO
The preceding discussion focused on the irreversibility of the sulfur impact on emissions from current gasoline engine technologies. There are new technologies under development, which could be sold in the U.S. in the middle of the next decade (the same time that Tier 2 vehicles are being introduced), which also appear to be very sensitive to sulfur and largely unable to reverse this sulfur impact. One of these technologies is the direct injection gasoline (GDI) engine. These engines utilize much more air than is needed to burn the fuel, unlike conventional gasoline engines that operate under conditions where only just enough air to completely burn the fuel is introduced into the engine. This GDI technology allows these engines to be up to 25% more fuel efficient than current gasoline engines and to emit up to 20% less carbon dioxide. GDI engines are currently being introduced in both Japan and Europe (which have or will soon require low sulfur gasolines). Because of the significant operating differences with GDI engines, these vehicles will likely require emission control technology substantially different from that used on conventional gasoline engines. For example, a GDI engine may require a NO
The fuel cell is another promising propulsion system that is being developed for possible introduction to
As discussed in more detail in the RIA, EPA believes that sulfur in gasoline can adversely impact the onboard diagnostic (OBD) systems of current vehicles as well as vehicles meeting the Tier 2 standards. This is an important factor supporting the need for a national sulfur control program. EPA's onboard diagnostics (OBD) regulations require that all vehicles be equipped with a system that monitors, among other things, the performance of the catalyst and warns the owner if the catalyst is not functioning properly. The OBD catalyst monitor is designed to identify those catalysts with pollutant conversion efficiencies that have been reduced to the extent that tailpipe emissions would exceed a specified multiple of the applicable hydrocarbon emissions standard. For California LEV and federal NLEV vehicles, that multiple is 1.75 times the applicable hydrocarbon emissions standard; for federal Tier 1 vehicles, that multiple is 1.5 times the applicable hydrocarbon standard added to the 4,000 mile emission level.
We want to ensure that OBD systems operate correctly, and thus the possibility that gasoline sulfur may interfere with these systems was another consideration when evaluating the need for a national sulfur program. Our evaluation of sulfur's effect on OBD systems was summarized in a staff paper in 1997.
The reduction of sulfur levels for gasoline should resolve any concerns over the ability of the OBD system to make proper decisions. The use of low sulfur fuel should ensure that the OBD warning light goes on when it is supposed to and is not influenced by sulfur contamination of the catalyst and/or OBD system.
The program we are establishing today for cars, light trucks, and large passenger vehicles will achieve the same large NO
We have seriously considered the input of all stakeholders in developing our final rule and believe the program finalized below balances the concerns of all stakeholders while achieving the needed air quality benefits. In general, the adjustments we have made are aimed at improving the implementation efficiency of the program by better aligning the federal Tier 2 program with the NLEV program and with California's program especially during the interim program.
Our final rule also includes provisions to regulate complete heavy-duty passenger vehicles (primarily SUVs and passenger vans) of less than 10,000 pounds GVWR within the Tier 2 program. Standards for these vehicles were not included in the Tier 2 NPRM, but were proposed in a subsequent NPRM on October 29, 1999 (64 FR 58472). The final provisions for these vehicles are addressed in section IV.B.4.g. These heavier vehicles have been recategorized as medium duty passenger vehicles (MDPVs). They are included in the Tier 2 program starting with model year 2004 and will be treated similarly to HLDTs, unless otherwise noted.
The next sections of the preamble describe our final program in detail and include changes and adjustments from the NPRM that we believe address many concerns raised by the Alliance and others. While these changes ease the burden on manufacturers, they have little or no impact on the air quality benefits of the Tier 2 program.
In a number of places in the following text, we mention that changes are being made “in response to comments”. For a full summary of the comments and for our responses to those comments, we refer you to the Response to Comments document contained in the docket for this rulemaking or available from the Office of Mobile Sources web site (see web address at the beginning of this document).
The vehicle-related part of today's final rule covers a wide range of standards, concepts, and provisions that affect how vehicle manufacturers will develop, certify, produce, and market Tier 2 vehicles. This Overview subsection provides readers with a broad summary of the major vehicle-related aspects of the rule. Readers for whom this Overview is sufficient may want to move on to the discussion of the key gasoline sulfur control provisions (Section IV.C.). Readers wishing a more detailed understanding of the vehicle provisions can continue beyond the Overview to deeper discussions of key issues and provisions (Sections IV.B.-2, 3, and 4) as well as discussions of additional provisions (Section V.A.). Readers should refer to the regulatory language found at the end of this preamble for a complete compilation of the requirements.
To understand how the program will work, it is useful to review EPA's classification system for light-duty vehicles and trucks. The light-duty category of motor vehicles includes all vehicles and trucks at or below 8500 pounds gross vehicle weight rating, or GVWR (
Today's final rule incorporates concepts from the federal NLEV program which began phase-in in the 1999 model year for LDV/LLDTs.
The Tier 2 corporate average NO
As proposed in the NPRM and finalized in today's document, the Tier 2 program will take effect in 2004, with full phase in occurring by 2007 for LDV/LLDTs and 2009 for HLDTs. During the phase-in years of 2004-2008, vehicles not certified to Tier 2 requirements will meet interim requirements also using a bins system, but with less stringent corporate average NO
In the discussions below, we set forth different Tier 2 phase-in schedules for the two different groups of vehicles (LDV/LLDTs and HLDTs) as well as two different interim fleet average NO
In the NPRM, we set forth separate tables of full life standard bins for the interim programs and the final Tier 2 program, but we proposed that manufacturers could use all bins for interim or Tier 2 vehicles during the phase-in years.
Throughout this preamble, we make reference to California's LEV II program and its requirements. The LEV II program was approved by the California ARB at a hearing of November 5, 1998. Numerous draft documents were prepared by ARB staff in advance of that hearing and made available to the public. Those documents were referenced in our NPRM and included in the docket. Some of those documents were modified as a result of changes to the proposed program made at the hearing and due to comments received after the hearing. ARB prepared final documents without significant change. The final program was approved by California's Office of Administrative Law on October 28, 1999 and filed with the Secretary of State to become effective on November 27, 1999.
We have placed copies of the latest available documents, some of which we used in the preparation of this final rule, in the docket. You may also obtain these documents and other information about California's LEV II program from ARB's web site: (www.arb.ca.gov/regact/levii/levii.htm).
In the regulatory text that follows this preamble, we incorporate by reference a number of documents related to LEVII and California test procedures under
The program we are finalizing today will ultimately require each manufacturer's average full life NO
A corporate average standard enables the program's air quality goals to be met while allowing manufacturers the flexibility to certify some models above and some models below the standard. Manufacturers can apply technology to different vehicles in a more cost-effective manner than under a single set of standards that all vehicles have to meet.
Each manufacturer will determine its year-end corporate average NO
We are finalizing a Tier 2 bin structure having eight emission standards bins (bins 1-8), each one a set of standards to which manufacturers can certify their vehicles. Table IV.B.-2a shows the full useful life standards that will apply for each bin in our final Tier 2 program, i.e. after full phase-in occurs for all LDVs and LDTs. Two additional bins, bins 9 and 10, will be available only during the interim program and will be deleted before final phase-in of the Tier 2 program. Table IV.B.-2b shows all the bins from Table IV.B.-2a and also shows extra bins and higher available standards for certain pollutants that are available prior to full Tier 2 phase-in. An eleventh bin, only for MDPVs is discussed in section IV.B.4.g.
Many bins have the same values as bins in the California LEV II program as a means to increase the economic efficiency of the transition to as well as model availability. Further, we added bins that are not a part of the California program to modestly increase the flexibility of the program for manufacturers without compromising air quality goals. As discussed in Section IV.B.4. below, we believe these extra bins will help provide incentives for manufacturers to produce vehicles with emissions below 0.07 g/mi NO
The NPRM full life standards contained seven Tier 2 bins as well as two separate tables of bins for interim vehicles. We proposed that manufacturers would be able to use all the bins during the phase in years regardless of whether they were certifying Tier 2 vehicles or interim vehicles.
The program we are finalizing today:
• Combines the bins from the NPRM;
• Omits two bins that were included in the NPRM for harmony with California but which are unlikely to be used;
• Adds 2 bins to increase compliance flexibility without reducing environmental benefits;
• Adds a temporary bin only for MDPVs that expires after 2008. This bin is in addition to the 10 bins shown in tables of bins in this preamble;
• Establishes a PM value for the highest bin available during the interim program (bin 10) that is more stringent than the corresponding standard in the NLEV program;
• Provides temporary higher NMOG standards that expire after 2006 for certain interim LDT2s and LDT4s produced by qualifying manufacturers.
Tables IV.B.-2a and 2b show the bins for full life standards. Table IV.B.-2b is repeated later in the text where intermediate life standards are also shown. These tables omit the temporary bin for MDPVs. This bin is usable only by MDPVs and is addressed separately in section IV.B.4.g.
The corporate average concept using bins will provide a program that gets essentially the same emission reductions we would expect from a straight 0.07 g/mi standard for all vehicles because all NO
We recognize that the Tier 2 standards pose greater technological challenges for larger light duty trucks ( HLDTs) than for LDVs and smaller trucks (LDT1s and LDT2s). We believe that additional leadtime is appropriate for HLDTs. HLDTs have historically been subject to less stringent vehicle-based standards than lighter trucks and LDVs. Also, HLDTs were not subject to the voluntary emission reductions implemented for LDVs, LDT1s and LDT2s in the NLEV program. Consequently we are finalizing as proposed, separate phase-in programs for HLDTs and LDV/LLDTs . Our phase-in approach will provide HLDTs with extra time before they need to begin phase-in to the final Tier 2 standards and will also provide two additional years for them to fully comply. Table IV.B-3 provides a graphical representation of how the phase-in of the Tier 2 program will work for all vehicles. This table shows several aspects of the program:
• Phase-in of the Tier 2 standards;
• Phase-in/phase-out requirements of the interim programs;
• Phase-in requirements of new evaporative standards;
• Years that can be included in alternative phase-in schedules;
• Years in which manufacturers can bank NO
• “Boundaries” on averaging sets in the Tier 2 and interim programs.
• Averaging provisions for MDPVs (see section IV.B.4.g. for discussion)
We discuss each of these topics in detail below and make numerous references to Table IV.B-3.
As described in detail in the Response to Comments document, the Alliance proposal would have delayed final implementation of Tier 2 standards until 2011. We are not adopting the Alliance's time schedule, because we believe the shorter schedule we proposed is feasible and that there is no reason to delay the final benefits of the Tier 2 standards. In fact, numerous commenters representing state, environmental and health groups argued that our original proposal gave manufacturers too much time to bring the HLDTs into line with LDVs and LLDTs. We believe the two extra years proposed in the NPRM remain appropriate. HLDTs will face greater challenges than LDVs/LLDTs because their emission control systems will need to be durable under potentially heavier loads and tougher operating conditions than LDV/LLDTs. Their sales are small relative to the rest of the light duty fleet (they will comprise about 14% of the light duty fleet in 2004), and they will benefit from industry experience with the lighter vehicles. In addition, HLDTs will not remain at high Tier 1 levels until they phase-in to Tier 2. Rather, they will have to meet interim standards that impose a NO
We are finalizing the implementation schedule for the Tier 2 standards as proposed in the NPRM. Thus, the standards will take effect beginning with the 2004 model year for light duty vehicles and trucks at or below 6000 pounds GVWR (LDV/LLDTs). Manufacturers will phase their vehicles into the Tier 2 standards beginning with 25 percent of LDV/LLDT sales that year, 50 percent in 2005, 75 percent in 2006, and 100 percent in 2007. Manufacturers will be free to choose which vehicles are phased-in each year. However, in each year during (and after) the phase-in, the manufacturer's average NO
To increase manufacturer flexibility and provide incentives for early introduction of Tier 2 vehicles, we are also finalizing provisions from the NPRM that permit manufacturers to use alternative phase-in schedules that will still require 100 percent phase-in by 2007, but recognize the benefits of early introduction of Tier 2 vehicles, and allow manufacturers to adjust their phase-in to better fit their own production plans. (See section IV.B.4.b.ii. below.)
The Tier 2 phase-in schedule for HLDTs is also being finalized as proposed. The phase-in for final Tier 2 standards for HLDTs will start later and end later than that for LDVs and LLDTs. Fifty percent of each manufacturer's HLDTs must meet Tier 2 standards in 2008, and 100 percent must meet Tier 2 standards in 2009. As with the LDV/LLDTs, the Tier 2 HLDTs must meet a corporate average NO
• Provides significant interim emission reductions starting in 2004 (discussed separately below);
• Recognizes the relatively high emission standards that currently apply to HLDTs;
• Provides manufacturers with adequate lead time before they must bring HLDTs into compliance with final Tier 2 standards;
• Provides manufacturers the opportunity to apply and evaluate Tier 2 technology on LDV/LLDTs before having to apply it to HLDTs; and
• Provides manufacturers the opportunity to apply and evaluate Tier 2 technology on HLDTs on a relatively small scale to meet California LEV II requirements before having to apply it to HLDTs nationwide.
As with the LDV/LLDTs above, to encourage early introduction of Tier 2 HLDTs and to provide manufacturers with greater flexibility, we are finalizing provisions to permit manufacturers to generate early Tier 2 NO
The interim standards discussed below are a major source of emission reductions in the early years of the vehicle control program. The NO
The two groups of vehicles (LDV/LLDTs and HLDTs) will be approaching the Tier 2 standards from quite different emission “backgrounds”. LDV/LLDTs will be at NLEV levels, which require NO
Interim vehicles will certify to the same bins as Tier 2 vehicles. As described earlier in this preamble, we have merged the tables of bins from the NPRM for simplicity and added a few bins. Bins 9 and 10 were drawn from the tables of interim bins in the NPRM, and are intended only for use during the phase-in years. Therefore, these two bins will be discontinued after 2006 (2008 for HLDTs).
Beginning with the 2004 model year, all new LDVs, LDT1s and LDT2s not incorporated under the Tier 2 phase-in will be subject to an interim corporate average NO
Because the Tier 2 standards are phased-in beginning in the 2004 model year, the interim standards for LDVs and LLDTs apply to fewer vehicles each year,
As mentioned above, the interim program for LDV/LLDTs is designed to hold these vehicles to the NLEV NO
Our interim standards for HLDTs will begin in the 2004 model year similar to our proposal in the NPRM. The Interim Program for HLDTs will require compliance with a corporate average NO
As shown in Table IV.B.-3, the phase-in schedule for HLDTs to the 0.20 g/mi corporate average NO
This approach will allow more time for manufacturers to bring the more difficult HLDTs to Tier 2 levels while achieving real reductions from those HLDTs that may present less of a challenge.
Due to statutory leadtime considerations, we were not able to finalize the HLDT standards to be in effect by the time the 2004 model year begins. For this reason, we are providing incentives for HLDTs to comply with the Tier 2 standards for all 2004 model year HLDTs. This change and the leadtime issue are discussed further under section IV.B.4.e. below and also in the Response to Comments document.
As is the case with the primary Tier 2 standard structure, the interim programs will focus on NO
As proposed in the NPRM and finalized in this notice, manufacturers will be permitted to average the NO
A manufacturer with an average NO
Manufacturers will be free to retain any credits they generate for future use or to trade (sell) those credits to other manufacturers. Credits retained or purchased can be used by manufacturers with corporate average Tier 2 NO
Banking and trading of NO
Banking and trading of NO
Before we provide a more detailed description of the vehicle program, we want to review two overarching principles of today's rule. The first is our goal to bring all LDVs and LDTs under the same set of emission standards. Historically, LDTs—and especially the heavier trucks in the LDT3 and LDT4 categories—have been subject to less stringent emission standards than LDVs (passenger cars). In recent years the proportion of light truck sales has grown to approximately 50 percent. Many of these LDTs are minivans, passenger vans, sport utility vehicles and pick-up trucks that are used primarily or solely for personal transportation;
As vehicle preferences have increasingly shifted from passenger cars to light trucks there has been an
Once the phase in periods end for all vehicles in 2009, manufacturers will include all LDVs and LDTs together in calculating their corporate average NO
Some manufacturers have suggested that a program with different requirements is needed for heavy LDTs. Recognizing that compliance will be most challenging for HLDTs, the delay in the start of the phase-in and the additional phase-in years for those vehicles will allow manufacturers to delay the initial impact of the Tier 2 standards until the 2008 model year. This represents four additional model years of leadtime beyond the time when passenger cars and LDT1s and LDT2s will achieve Tier 2 standards in substantial numbers. We believe this phase-in and other provisions of this rule respond to these concerns. Note that in the NPRM, we requested comments on the need for different hydrocarbon standards for these vehicles recognizing that a tradeoff often exists between HC and NO
We are not adopting the Alliance's proposed phase-in schedule which would have provided a phase-in lasting until 2011. At the end of the Alliance's proposed phase-in, all vehicles would comply with an average NO
We are not promulgating the fixed NMHC standards suggested by the Alliance, but are sticking with the concept of bins containing lower NMOG standards connected to lower NO
The second overarching principle of our vehicle program is the use of the same Tier 2 standards for all LDVs and LDTs, regardless of the fuel they are designed to use. The same exhaust emission standards and useful life periods we are finalizing today will apply whether the vehicle is built to operate on gasoline or diesel fuel or on an alternative fuel such as methanol or natural gas. Diesel powered LDVs and LDTs tend to be used in the same applications as their gasoline counterparts, and thus we believe they should meet the same standards. Less stringent standards for diesels could create incentives for manufacturers to build more diesel vehicles, thus endangering the emission reductions expected by this program.
Manufacturers have expressed concerns that diesel-fueled vehicles would have difficulty meeting NO
Today, diesels comprise less than one-half of one percent of all LDV/LDT sales. While this is a small fraction, the potential exists for diesels to gain a considerable market share in the future. All one need do is review the dramatic increase in recent years of diesel engine use in the lightest category of heavy duty vehicles (8500-10,000 pounds GVWR) to see the potential for significant diesel engine use in LDTs, and perhaps LDVs, in the future. Just ten years ago, diesels made up less than 10 percent of this class of vehicles. In 1998, this fraction approached 50 percent.
The potential impact of large-scale diesel use in the light-duty fleet underscores the need for the same standards to apply to diesels as other vehicles. Given the health concerns associated with diesel PM emissions (see Section III. above), we believe that it is prudent to address PM emissions from diesel LDVs and LDTs while their numbers are relatively small. In this way the program can minimize the PM impact that would accompany significant growth in this market segment while allowing manufacturers to incorporate low-emission technology into new light-duty diesel engine designs.
The previous subsections IV.B.-1.2. and 3. provide an overview of the Tier 2 vehicle program and the two key principles it is built on. This subsection elaborates on the major vehicle-related elements of today's rule. Later in this preamble, Section V.A. discusses the rest of the vehicle provisions.
Our final Tier 2 program contains a basic requirement that each manufacturer meet, on average, a full useful life NO
In the NPRM, we proposed that interim vehicles and Tier 2 vehicles (except for those Tier 2 vehicles in the lowest bins) would also have to meet intermediate useful life standards,
Under a “bins” approach, a manufacturer may select a set of emission standards (a bin) to comply with, and a test group must meet all standards within that bin. Ultimately, the manufacturer must also ensure that the emissions of a targeted pollutant—NO
In addition to the Tier 2 standards described above, we are also finalizing an interim average NO
Compared to the CalLEV II program, our Tier 2 proposal included additional bins. The California program contains no bins that will allow NO
In our NPRM we proposed that during the Tier 2 phase-in years (through 2006 for LDV/LLDTs and 2008 for HLDTs), bins from the applicable interim program would be available to enhance the flexibility of the program by providing manufacturers with additional bins having NO
While some commenters were concerned about the existence of bins above NO
We are finalizing a bins approach with the bins shown in Tables IV.B.4 and 5 to provide adequate and appropriate emission reductions and manufacturer flexibility. This structure will help to accelerate technological innovation. We requested comment on whether we should include up to two additional bins between NO
We requested comment on whether our Tier 2 bin in the NPRM with NO
We are finalizing as proposed our plan to phase in the Tier 2 standards for LDV/LLDTs over a four year period beginning in 2004 and we are also finalizing as proposed a delayed two year phase-in beginning in 2008 for HLDTs. These phase-in schedules are shown in Table IV.B.-2 and are also shown separately in Tables IV.B.-6 and 7. We believe the flexibility of this dual phase-in approach is appropriate because the Tier 2 program will encompass all light-duty vehicles and trucks and will result in widespread applications of upgraded and improved technology across the fleet. The program will require research, development, proveout, and certification of all light-duty models, and manufacturers may need longer lead time for some vehicles, especially HLDTs. Also, manufacturers may wish to time compliance with the Tier 2 standards to coincide with other changes such as the roll out of new engines or new models. In order to begin the introduction of very clean vehicles as soon as possible while avoiding imposing unnecessary inefficiencies on vehicle manufacturers, we believe this practical but aggressive phase-in schedule effectively balances air quality, technology, and cost considerations.
In each year, manufacturers will have to ensure that the specified fraction of their U.S. sales:
• Meets Tier 2 standards for exhaust emissions, including Supplemental Federal Test Procedure (SFTP) standards (discussed in Section V.A.-3. below);
• Meets Tier 2 standards for evaporative emissions (discussed in Section IV.B.-4.f. below); and
• Meets the corporate average Tier 2 NO
Manufacturers will have to meet the Tier 2 exhaust requirements (i.e., all the standards of a particular bin plus the SFTP standards) using the same vehicles. Vehicles not covered by the Tier 2 standards during the phase-in years (2004-2008) will have to meet interim standards described in Section IV.B.4.e. below and the existing evaporative emission as well as the applicable SFTP standards.
Manufacturers can elect to meet the percentage phase-in requirements for evaporative and exhaust emissions using two different sets of vehicles. We believe that because of interactions between evaporative and exhaust control strategies, manufacturers will generally address the Tier 2 evaporative phase-in with the same vehicles that they use to meet the exhaust phase-in. However, the primary focus of today's proposal is on exhaust emissions, and the flexibility for manufacturers to use different sets of vehicles in complying with the phase-in schedule for evaporative standards and for the exhaust standards will have no environmental down side that we are aware of. It is possible that some exhaust emission improvements might even occur sooner than they otherwise would if a manufacturer is able to move ahead with the roll-out of a model with cleaner exhaust emissions without having to wait for the development of suitable evaporative controls to be completed for that model.
We are finalizing our proposed phase-in approach, in which vehicle sales will be determined according to the “point of first sale” method outlined in the NLEV rule. Vehicles with points of first sale in California or a state that has adopted the California LEV II program (if any) will be excluded from the calculation. The “point of first sale” method recognizes that most vehicle sales will be to dealers and that the dealers' sales will generally be to customers in the same geographic area. While some sales to California residents (or residents of states that adopt California standards) may occur from other states and vice-versa, we believe these sales will be far too small to have any significant impact on the air quality benefits of the Tier 2 program or the manufacturers' ability to demonstrate compliance.
We are finalizing, as proposed, that manufacturers may introduce vehicles earlier than required to earn the flexibility to make offsetting adjustments, on a one-for one basis, to the phase-in percentages in later years. However, they will still need to reach 100% of sales in the 2007 model year (2009 for HLDTs). Manufacturers will have the option to use this alternative to meet phase-in requirements for LDV/LLDTs and/or HLDTs. They can use separate alternative phase-in schedules for exhaust and evaporative emissions, or an alternative phase-in schedule for one set of standards and the primary (25/50/75/100% or 50%/100%) schedule for the other.
Under these alternative schedules, manufacturers will have to introduce vehicles that meet or surpass the 0.07 g/mi Tier 2 NO
As outlined in the NPRM, an alternative phase-in schedule will be acceptable if it passes a specific mathematical test. We have designed the test to provide manufacturers benefit from certifying to the Tier 2 standards early while ensuring that significant numbers of Tier 2 vehicles are introduced during each year of the alternative phase-in schedule. To test an alternative schedule, a manufacturer
For LDV/LLDTs, the final sum of percentages must equal or exceed 250—the sum that results from a 25/50/75/100 percent phase-in. For example, a 10/25/50/65/100 percent phase-in that begins in 2003 will have a sum of 250 percent and is acceptable. In this example, assuming constant levels of production, each Tier 2 vehicle sold early (
To ensure that significant numbers of Tier 2 vehicles are introduced in the 2004 time frame, manufacturers will not be permitted to use alternative phase-in schedules that delay the implementation of the Tier 2 LDV/LLDT requirements, even if the sum of the phase-in percentages meets or exceeds 250. Such a situation could occur if a manufacturer delayed implementation of its Tier 2 production until 2005 and began a 75/85/100 percent phase-in that year. To protect against this possibility, we are finalizing the proposed requirement that for any alternative phase-in schedule, a manufacturer's phase-in percentages from the 2004 and earlier model years sum to at least 25%. In the final rule we are including an additional measure of flexibility to the requirements for alternative phase-in schedules. We will permit manufacturers to achieve a 2004 phase-in of less than 25%, but no less than 20%, provided that in 2005 they make up the shortfall in a two-for-one manner. So, as an example, a manufacturer that phased in 5% in 2003 and 15% in 2004 would achieve a total of 20% through the 2004 model year and would need to comply with Tier 2 requirements for at least 60% of its LDV/LLDTs in 2005. We believe that this flexibility is appropriate because the required response for 2005 model year vehicles more than makes up for the environmental loss from the 2004 model year vehicles.
We requested comment on whether alternative phase-in schedules should be structured to permit manufacturers to extend phase in past the final year of the primary phase-in schedule (2007 or 2009). While the Alliance proposal and comments clearly support phase-ins that run past 2007 and 2009, other commenters were opposed to any extensions of the phase-in period. In fact most commenters who addressed the length of the phase-in indicated, as previously discussed, that the phase-in for HLDTs should be moved ahead to 2007 to coincide with LDV/LLDTs. We are not finalizing any provisions that will permit alternative phase-in schedules to provide additional time for manufacturers to meet any final 100% compliance year.
In the NPRM, we pointed out that phase-in schedules, in general, add little flexibility for manufacturers with limited product offerings because a manufacturer with only one or two test groups can not take full advantage of a 25/50/75/100 percent or similar phase-in. For manufacturers meeting EPA's definition of “small volume manufacturer,” we proposed to exempt those manufacturers from the phase-in schedules and require them to simply comply with the final 100% compliance requirement. We are finalizing this provision for small volume manufacturers. This provision is only intended to apply to small volume manufacturers and not to small test groups of larger manufacturers.
For larger manufacturers having a limited product line, we recognize that our phase-in schedule may lack flexibility, however, we are not including any provisions to address this issue as we are for small volume manufacturers because we do not believe these manufacturers need the relief and we do not want to sacrifice any air quality benefits of the program.
While the manufacturer will be free to certify a test group to any applicable bin of standards in Table IV.B.-2, it will have to ensure that the sales-weighted average of NO
The corporate average NO
Given the corporate average NO
As mentioned in the Overview above, we are finalizing our proposal that manufacturers with year-end corporate average NO
As proposed, the Tier 2 standards will apply regardless of the fuel the vehicle is designed for, and there will be no restrictions on averaging, banking or trading of credits across vehicles of different fuel types. Consequently, a gasoline fueled LDV might help a manufacturer generate NOx credits in one year that could be banked for the next year when they could be used to average against NO
Because of the split phase-in and the different interim programs we are finalizing for the two different groups of vehicles (LDV/LLDTs and HLDTs), we are also finalizing the proposed requirement that manufacturers compute their corporate Tier 2 NO
We explained in the NPRM why we believe the provisions for averaging, banking, and trading of NO
• An ABT program is an important factor that EPA takes into consideration in setting emission standards that are appropriate under section 202 of the Clean Air Act. ABT allows us to consider a more stringent emission standard than might otherwise be appropriate under the CAA, since ABT reduces the cost and improves the technological feasibility of achieving the standard;
• ABT enhances the technological feasibility and cost effectiveness of the proposed standard and allows the standard to be attainable earlier than might otherwise be possible;
• ABT provides manufacturers with additional product planning flexibility and the opportunity for a more cost effective introduction of product lines;
• ABT creates incentive for early introduction of new technology, allowing certain engine families to act as trail blazers for new technology;
We view the ABT provisions in today's rule as environmentally neutral because the use of credits by some vehicles is offset by credits generated by other vehicles. However, when coupled with the new standards, ABT will have environmental benefits because it allows the new standards to be implemented earlier than would otherwise be appropriate.
Manufacturers will determine their year-end corporate average NO
The manufacturer can use these NO
The enforcement of the NO
In the NPRM, we proposed that to the extent a manufacturer's corporate average NO
Thus, we are finalizing our provision for early NO
Early Tier 2 credits will have all the same properties as credits generated by vehicles subject to the primary phase-in schedule. We proposed that these credits could not be used in the NLEV, Tier 1 or interim program for non-Tier 2 vehicles in any way. We are finalizing this restriction as proposed. We are also finalizing as proposed that the NMOG emissions of these vehicles (LDVs and LLDTs only) can be used in the
To provide manufacturers with maximum flexibility in the period prior to 2004, when LDV/LLDT useful lives will still be at 100,000 miles, we proposed and are finalizing that manufacturers may choose between the Tier 2 120,000 mile useful life or the current 100,000 mile useful life requirement for early Tier 2 LDV/LLDTs. (HLDTs already have a 120,000 mile useful life.) Early LDV/LLDT NO
We proposed to restrict early banking of HLDT Tier 2 NO
We recognize that vehicles generating early Tier 2 NO
We discussed in the preamble to the NPRM why we did not propose to apply the California schedule of discounting unused credits adopted for NMOG credits in the NLEV program. This schedule serves to limit credit life throughout the program by reducing unused credits to 50, 25 and 0 percent of their original number at the end of the second, third and fourth year, respectively, following the year in which they were generated. We agree that such a scheme may be appropriate in the California program with its declining NMOG average standard, but in the federal program, once the phase-in period ends in model year 2009, all LDVs and LDTs will comply on average with a fixed Tier 2 NO
Credits allow manufacturers flexibility to meet standards cost effectively and to address unexpected shifts in sales mix. When matched with a NO
We requested comment in the NPRM on the need for discounting of credits or limits on credit life and what those discount rates or limits, if any, should be. The 0.07 NO
When a manufacturer has a NO
Manufacturers made the persuasive case that by the time they can tabulate their average NO
We note that under our modified final approach, manufacturers will have the flexibility to carry deficits from the interim program forward into the final Tier 2 program. This feature is likely to be used only in an extreme situation since the Tier 2 credits needed to offset the interim credit deficit will be more difficult to generate. Consequently, we do not believe this provision is inconsistent with our approach of segregating interim and Tier 2 credits. In fact, manufacturers electing to cover an interim credit deficit with Tier 2 credits will likely have to accelerate the introduction of Tier 2 vehicles to get the necessary credits to cover the deficit.
We are finalizing that small volume manufacturers may not use the credit deficit carryforward provision until they have been in compliance with the relevant average NO
We requested comment in the NPRM as to whether we should provide additional NO
We are finalizing provisions to permit manufacturers, at the beginning of the program, to weight LDV/Ts certified to the lowest two bins more heavily when calculating their fleet average NO
The multipliers that manufacturers may use are found in Table IV.B.-8 below:
The NLEV program referenced throughout this discussion is a voluntary program in which all major manufacturers have opted to produce LDVs and LLDTs to tighter standards than those required by EPA's Tier 1 regulations. Under the NLEV program, manufacturers must meet an NMOG average outside of California that is equivalent to California's current intermediate-life LEV requirement—0.075 g/mi for LDVs and LDT1s (0.10 g/mi for LDT2s). NLEV requirements apply only to LDVs and LLDTs, not to HLDTs.
The NLEV program is effective beginning in the northeastern states in 1999 and in the remaining states in 2001, except that the program does not apply to vehicles sold in California or in states that adopted California's LEV program. The program runs at least through model year 2003 and can run through model year 2005.
Under the Tier 2 phase-in we are finalizing today, not all LDV/LLDTs covered under NLEV will be subject to Tier 2 standards in the 2004 to 2006 period. Without a program for full Tier 2 compliance in 2004 (
In the NPRM, we included separate sets of bins for the interim program and Tier 2 program. However, we indicated that manufacturers could use either set for interim vehicles. In today's final rule we have combined all bins into one table for simplicity. We have also added two new bins having NO
In the NPRM, we proposed that, for LDV/LLDTs, all bins with NO
We proposed to align the useful life periods for interim standards with those of the Tier 2 standards (full useful life of 120,000 miles), as discussed in Section V.B. below. The end result of this proposal would have been that all LDV/LLDTs—whether in the Tier 2 program or interim program—would go from 100,000 mile useful lives to 120,000 mile useful lives in 2004. However, manufacturers were extremely concerned about the certification workload burden for 2004. They commented that they would be unable to carry any of their LDV/LLDTs over from 2003 and that they would have to recertify all of their vehicles in 2004 and then likely recertify them again as they were phased into the Tier 2 standards. Therefore, based upon comments, we are finalizing that useful lives of the interim LDV/LLDTs may remain at 100,000 miles. Our reasons for this change are discussed in greater detail in Section V.B.
We are finalizing as proposed a corporate average full useful life NO
The 0.30 g/mi corporate average NO
NMOG credits from the NLEV program can not be used in this interim program in any way. NO
For the reasons cited above, we believe it is appropriate to extend interim, NLEV-like standards beyond 2003 as a mandatory program and to bring all LDVs and LLDTs within its scope. Manufacturers have already demonstrated their ability to make LDVs and LLDTs that comply at levels well below these standards. As the interim standards for LDV/LLDTs are essentially ‘phase-out” standards, we did not propose and are not finalizing early banking provisions for the interim LDV/LLDTs.
We believe these interim standards are necessary and reasonable for HLDTs. While these trucks make up a fairly small portion of the light-duty fleet (about 14%), their current standards under Tier 1 are far less stringent than the NLEV standards that apply to current model year LDVs and LLDTs. Given the delayed phase-in we are finalizing for HLDTs, we believe it is appropriate to require some interim reductions from these vehicles. Further, manufacturers have already demonstrated their ability to meet these interim standards with HLDTs. These standards are a reasonable first step toward the Tier 2 program and will provide meaningful reductions in the near term relative to current certification levels under the Tier 1 emission standards.
We also proposed interim standards to begin in 2004 for HLDTs. These vehicles are not included in the NLEV program and will be subject only to the Tier 1 standards prior to today's rule taking effect. Tier 1 standards permit NO
(Option 1) Like we proposed in the NPRM, manufacturers must bring their entire production of 2004 model year HLDTs under the interim requirements and phase 25% of them into the 0.20 g/mi fleet average NO
(Option 2) We are including this option to address statutory lead time requirements for HLDTs. In the case of 2004 model year test groups whose model years commence
Our final rule is consistent with the requirements of the Act because manufacturers won't have to phase-in HLDTs until the model year that commences four years from the signature of this rule if they don't want to. However, to provide incentive for manufacturers to comply with the interim requirements for all of their HLDTs beginning with the 2004 model year,
• Use a full useful life NMOG value, through the 2008 model year, of 0.280 g/mi for LDT4s certified to bin 10 (0.195 g/mi at intermediate life); and
• Use a full useful life NMOG value, through the 2006 model year, of 0.130 g/mi for LDT2s certified to bin 9 (0.100 g/mi at intermediate life).
In the case of the LDT4s, the optional NMOG standard will enable manufacturers to more easily meet our interim HLDT NO
Except for the application of the new option described above, the interim standards for HLDTs will apply as proposed, and will phase-in through the 2007 model year, as shown in Table IV.B.-2. We are finalizing the proposed corporate average full-life NO
At the end of each model year, manufacturers will determine their compliance with the 0.20 NO
For HLDT test groups that are not subject to the phase-in in model year 2004 under Option 2 above, the same requirements as described above apply except that there are no new standards for these vehicles in the 2004 model year. Also, the optional higher NMOG values for LDT2s and LDT4s do not apply for any manufacturer that uses Option 2.
Given that the interim HLDT standards are “phase-in” standards through 2007 (as opposed to the interim LDV/LLDT standards, which are “phase-out” standards), we are including provisions that manufacturers may employ alternative phase-in schedules as proposed for the Tier 2 standards and described in detail in section IV.B.4.b.ii. of this preamble. These schedules provide manufacturers with greater flexibility and we believe they also provide incentive for manufacturers to introduce advanced emission control technology at an earlier date. Alternative phase-in schedules will have to provide 100% phase-in by the same year as the primary phase-in schedule (2007). Manufacturers will be eligible for alternate phase-in schedules to the extent that they produce HLDTs that meet or surpass the NO
Where manufacturers elect not to meet the phase-in requirements for all of their 2004 model year HLDTs, as discussed above under Option 2, they may still employ alternate phase-in schedules, but the sum of 225 percent is required rather than the 250 percent required for alternate phase-ins described in section IV.B.4.b.ii. In this case, the sum of phase-in percentages up through the 2005 model year must total to at least 50%. Also, manufacturers must raise the 225% value to the extent that any of their 2004 HLDTs' model years commence on or after the fourth anniversary of the signature date of this rule and are brought into compliance with the 0.20 g/mi average NO
Lastly, note that for bin 10, which is only usable during the interim program, we have established a PM standard of 0.08 g/mi, which is more stringent than the Tier 1 standard previously in effect for these vehicles. We do not expect low sulfur diesel fuel to be widely available during the time frame of the interim program but we expect that bin 10 levels can be reached by diesel technology on current diesel fuel. As a part of this overall approach, we are making the intermediate life standards optional for diesels for this bin.
We are finalizing as proposed a set of more stringent evaporative emission standards for all Tier 2 light-duty vehicles and light-duty trucks. The standards we are finalizing are shown in Table IV.B.-9 and represent, for most vehicles, more than a 50% reduction in diurnal plus hot soak standards from those that will be in effect in the years immediately preceding Tier 2 implementation. The higher standards for HLDTs provide allowance for greater non-fuel emissions related to larger vehicle size.
Evaporative emissions from LDVs and LDTs represent nearly half of the light duty VOC inventory projected for the 2007-2010 time frame, according to MOBILE5 projections. Manufacturers are currently certifying to levels that are, on average, about half of the current standards, and in many cases, much less than half the standards. Thus, meeting these standards appears readily feasible. Even though manufacturers are already certifying at levels much below the current standard, we believe that reducing the standards will result in emission reductions as all manufacturers seek to certify with adequate margins to allow for in-use deterioration. Further, we believe that tighter standards will prevent “backsliding” toward the current standards as manufacturers pursue cost reductions.
As mentioned in section IV.B.-4.b above, we will phase in the Tier 2 evaporative standards by the same mechanism as the Tier 2 exhaust standards;
The evaporative emission standards we proposed and are finalizing today are the same as those that manufacturers' associations proposed during the development of California's LEV II proposal. California ultimately opted for more stringent standards; we believe that our standards are appropriate for federal vehicles certified on higher-volatility federal test fuel.
Historically, we have categorized all vehicles above 8,500 pounds GVWR as heavy-duty vehicles regardless of their application and they have been subject to standards and test procedures designed for vehicles used in heavier work applications.
On October 29, 1999, after carefully considering all of the comments on this issue, we proposed to include all personal use passenger vehicles (both gasoline and diesel fueled) between 8,500 and 10,000 pounds GVWR in the Tier 2 program. This group of vehicles would include large SUVs and passenger vans and may include other types of “crossover” multipurpose vehicles in the future, depending on new vehicle designs. We proposed this Tier 2 program change in our NPRM concerning emissions standards for 2004 and later heavy-duty vehicles and engines, (64 FR 58472).
Specifically, we proposed to revise the definition of light-duty truck to include any complete vehicle between 8,500 and 10,000 pounds GVWR that is designed primarily for the transportation of persons and has a capacity of not more than 12 persons. We expected that this definition would exclude vehicles that have been designed for a legitimate work function as their primary use, such as the largest pick-up trucks, the largest passenger vans, and cargo vans; these vehicles would continue to be categorized as heavy-duty and would be subject to applicable heavy-duty standards. We requested comment on whether the proposed definition would adequately exclude these vehicles, or whether additional criteria may be needed and how that criteria might be used.
Today, we are finalizing Tier 2 standards for passenger vehicles above 8,500 pounds GVWR. These vehicles are included in the Tier 2 program beginning in 2004 and are required to meet the final Tier 2 standards in 2009 and later. As we intended in the proposal, these vehicles will generally be subject to the same requirements as HLDTs. We have made modifications to the program, primarily in response to comments we received in two areas: (1) Changing the definition of light-duty truck and (2) the interim program requirements.
The mechanism we proposed to bring the passenger vehicles over 8,500 pounds into the Tier 2 program, was to modify the definition of light-duty truck to include those vehicles. The objective of this proposal was to have these vehicles treated as HLDTs within Tier 2. We are finalizing requirements which remain consistent with our objective of including these vehicles in Tier 2 beginning in 2004. However, the approach we are finalizing is somewhat different than that proposed.
Rather than finalizing the revised definitions for light-duty truck as we proposed, we are creating a new category of heavy-duty vehicles termed “medium-duty passenger vehicles” (MDPVs). These vehicles will generally be grouped with and treated as HLDTs in the Tier 2 program. The MDPV category is defined along the lines of the proposed definition change for the LDT category, with some modification, as described below. Our decision to create a new sub-category of heavy-duty vehicles rather than modify the existing LDT definition does not, in and of itself, change the way in which Tier 2 standards are applied to the vehicles.
We decided upon the above approach because section 216 of the CAA establishes the definition for LDT as having the meaning contained in the CFR as of 1990. We received several comments that EPA may not change the definition and must instead devise a way to categorize the vehicles for purposes of Tier 2 which does not change the definition of light-duty truck. Rather than adopt a change to the LDT definition that would be questionable from a legal perspective, we are adopting an approach that we believe is clearly legally acceptable. Under this approach (as with the proposed approach), the standards for these vehicles are promulgated under
We are defining medium-duty passenger vehicles as any complete heavy duty vehicle less than10,000 pounds GVWR designed primarily for the transportation of persons including conversion vans (
We have added the pick-up bed length criterion to the definition to clearly distinguish standard pick-ups from other vehicles meeting the GVWR and seating capacity criteria. We received several comments that although the proposal clearly states our intention not to include heavy-duty pick-up trucks in the Tier 2 program, the proposed regulatory definition was unclear. Currently, heavy-duty pick-ups have beds in excess of six feet. Any future offerings of vehicles that are equipped with significantly shorter beds would be included in the MDPV category, if the vehicle also met the weight and seating capacity criteria. EPA is making a distinction based on bed length because a vehicle introduced with a shorter bed would have reduced cargo capacity and would likely have increased seating capacity relative to current pick-ups, making it more likely to be used primarily as a passenger vehicle.
As noted above, the MDPVs and HLDTs must meet the final Tier 2 standards by 2009 at the latest. Prior to 2009, HLDTs and MDPVs are required to meet interim standards. The interim standards, as described earlier in section IV.B.4, are based on a corporate average full life NO
We received several comments from manufacturers that requiring these larger vehicles to meet a new, unique standard prior to phase-in to the interim program would worsen the workload burden created by the Tier 2 program. Manufacturers do not currently have facilities available for chassis-testing diesel vehicles and there is not enough time to fold diesel vehicles into a chassis-based program by 2004.
To address this situation, we are providing the following temporary additional flexibilities for MDPVs. We are finalizing an additional upper bin for MDPVs for the interim program (effective in model years 2004 through 2008). This bin would only be available for MDPVs. The bin, shown in Table IV.B-10, is equivalent to the California LEV I standards that are applicable to these vehicles prior to 2004. Vehicles certified to this bin must be tested at adjusted loaded vehicle weight (ALVW), consistent with California program testing requirements.
We proposed that HLDTs not needed to meet the phase-in percentages for the interim program during model years 2004—2006 would be required to meet one of the interim bins. Such vehicles, however, would not be included in the calculation to demonstrate compliance with the 0.20 g/mile average. Thus, we proposed that the emissions of all interim HLDTs would be capped at a NO
In addition, for diesel MDPVs prior to 2008, we are allowing manufacturers the option of meeting the heavy-duty engine standards in place for the coinciding model year. Diesels meeting the engine-based standards would be excluded from the interim program averaging pool. In 2008, the manufacturers must chassis certify diesel vehicles and include them either in the interim program or in the final Tier 2 program. In 2009 and later, all MDPVs, including diesels, must be brought into the final Tier 2 program. As with the higher bin of chassis-based standards, the purpose of this diesel provision is to provide the option of carry-over of vehicles until they are brought into the Tier 2 program. We believe these modifications to the program will substantially ease the workload concerns of manufacturers in the interim years by allowing them to carry-over vehicle models and engine families. The provisions also remain consistent with EPA's goal of including the vehicles in the overall Tier 2 program structure.
For diesel engines that are engine certified and used in MDPVs, as allowed through model year 2007, we are requiring those engines to comprise a separate averaging set under the averaging, banking and trading requirements applicable to heavy-duty diesel engines. We are permitting engine-based certification for these diesel vehicles to provide time and flexibility for manufacturers who may have limited experience with chassis certifying vehicles containing such engines. However, we do not want to create a situation where engines above applicable engine standards could be used in these vehicles, when other MDPVs are being brought under stringent standards. Therefore we believe it is appropriate to constrain the application of credits to these engines. We note that we are not permitting credits from other programs (like NLEV) to be applied in any way to Tier 2 or interim vehicles.
For LDT4s, we have finalized an optional higher NMOG level of 0.280 g/mile for bin 10 (0.6 g/mile NO
As described in section IV. B.4.e.ii., manufacturers have two options for the start of the program requirements. In Option 1, the program begins with the 2004 model year for 25 percent all vehicles. In Option 2, manufacturers can exempt 2004 model year vehicle test groups whose model years begin on or after the fourth anniversary of this rule's signature. These options are also available for MDPVs for the same reasons we are providing them for HLDTs. However, the additional 0.9 g bin contained in Table IV.B.-10, the optional higher NMOG standard of 0.280 g/mile for bin 10, and the option of certifying to the engine-based standards for diesels are available only with Option 1.
We are requiring all non-diesel MDPVs to be OBDII compliant beginning in 2004. California requires OBDII for their LEV I program and therefore, the new OBDII requirements are consistent with the approach of allowing vehicles to be carried over from California.
As proposed, we are applying Tier 2 evaporative emissions standards and existing HLDT ORVR requirements to MDPVs. MDPVs must be grouped with HLDTs for purposes of phasing in to the Tier 2 evaporative emission standards contained in this rule. We have added somewhat higher standards for the MDPVs to account for their larger fuel tanks and vehicle sizes.
For those manufacturers electing option 2, OBD is required when the vehicle family is covered under these new requirements (
We are finalizing Cold CO and Certification Short Test requirements for Tier 2 MDPVs. However, we are not finalizing SFTP standards for MDPVs in today's rulemaking. Currently, SFTP standards do not apply to any vehicles above 8,500 pounds GVWR, including those in the California LEV I and LEV II programs. We are concerned, therefore, that finalizing SFTP requirements in today's rulemaking would prevent manufacturers from carrying over vehicle models during the phase-in years of the program. We are currently contemplating a new SFTP rulemaking which would consider “Tier 2” SFTP standards for all vehicles, including MDPVs. California is also interested in developing more stringent SFTP standards within the context of their LEV II program and we are coordinating with California on these new SFTP standards.
While we are confident that MDPVs can comply in-use with the standards we are finalizing, manufacturers are concerned about in-use liability for MDPVs that are in sustained severe-use. In our in-use emission testing program, we generally screen vehicles for proper maintenance and use and delete vehicles that we believe may have been misused or malmaintained. Also, in the regulations for manufacturer in-use testing, we permit manufacturers to delete vehicles from samples if they have been used for “severe duty (trailer towing for passenger cars, snow plowing, racing)”, and we provide that vehicles may be deleted for other reasons upon EPA approval.
We recognize that MDPVs will be marketed and used for carrying many passengers, carrying heavy loads and trailer towing. While it is not our intention to exempt vehicles from in-use liability that have been used for their intended purposes, we understand that some MDPVs may be subject to sustained severe service applications, such as frequent overloading or frequent towing beyond manufacturer's advertised capacity and could not be considered to be representative of properly maintained and used vehicles. Furthermore, we would not necessarily consider to be representative MDPVs which are routinely or regularly used in heavy-load hauling application or towing even within the manufacturers limits. Thus, for example, an SUV MDPV used on a daily basis to haul a work crew and tow equipment to a distant work site may not be representative while the same SUV used to haul the family and tow a boat to the lake on weekend excursions would be representative. MDPVs in sustained severe operations should not be included in manufacturer or EPA in-use test programs, while those that see less frequent severe operation should be included.
As with our program for vehicles, the program we are establishing today for reducing sulfur levels in commercial gasoline will achieve the same large NO
With today's action, we are requiring substantial reductions in gasoline sulfur levels nationwide. As we explained in Section IV.A, because sulfur significantly inhibits the ability of automotive catalysts to control emissions, we had to consider sulfur's impact in setting the Tier 2 standards. We knew at the time of proposal that newer catalysts were more sensitive to sulfur than older technologies, and projected that Tier 2 catalysts would be as or even more sensitive than those used in today's NLEV vehicles. Furthermore, we believed that the sulfur build-up on Tier 2 catalysts may be irreversible. Since the proposal, additional data we've collected have confirmed and strengthened our concerns. It now appears that the catalysts expected to be used in Tier 2 vehicles will be even more sensitive to sulfur than we originally estimated, and that this sulfur impact will be approximately 45 percent irreversible under typical driving conditions. Thus, the gasoline sulfur standards we finalize today will enable the stringent tailpipe emission standards we're implementing for Tier 2 vehicles and will help to ensure that these low emission levels will be realized throughout the life of the vehicle. Furthermore, since vehicles already on the road, including NLEV vehicles, are in many cases quite sensitive to sulfur, gasoline sulfur control will also help to reduce emissions of pollutants that endanger public health and welfare from these vehicles.
In developing this gasoline sulfur control program, we gave substantial consideration to the ability of the refining industry to meet these requirements. We proposed a set of standards applying to refiners and to individual refineries combined with a sulfur averaging, banking, and trading (ABT) program intended to provide flexibility in meeting the standards. We concluded that our proposal was reasonable and cost-effective based on our projections regarding the number of refineries that would (1) need to reduce sulfur levels each year as the standards tightened, (2) need sulfur ABT credits to meet the 30 ppm refinery average standard in 2004 and/or 2005 to defer installation of desulfurization equipment, and (3) install desulfurization equipment prior to 2004, generating the needed sulfur credits. This analysis formed our picture of the industry's investment stream—a year-by-year estimate of how many refineries would be constructing new equipment and what technologies these refineries would choose. We assumed that any investments would be in the new, lower cost technologies, and that these technologies would be available and adequately demonstrated to allow refiners to select them as early as the year 2000 to begin operation (and thus, credit generation) as early as 2002. Based on these assumptions, our analysis showed that sufficient credits would be generated before 2004 to enable a number of refineries to delay construction and use credits to meet the 30 ppm standard in 2004, and in some cases, even in 2005. Overall, we believed our analysis represented a reasonable and balanced rate of investment by the industry over a several year time period.
In response to our proposal, we received many comments which raised concerns about the feasibility of our program. Some comments suggested that our proposed declining cap (300 ppm cap for 2004 and a reduced cap of 180 ppm for 2005) could be an additional and burdensome expense for most refiners to meet. Specifically, these commenters believed that the declining cap would be more constraining than compliance with the corporate average or even the refinery average standards (as long as the ABT program produced sufficient credits). Because refiners probably would not make multiple investments in such a short time, the 180 ppm cap could force some refiners to install the equipment needed to get to the 80 ppm cap earlier than otherwise needed. The commenters argued that this would force all of the industry's investments into the first years of the program rather than allowing for a smoother transition over several years as we had originally envisioned. Many comments also suggested that since there have not been long-term commercial demonstrations of the newer gasoline desulfurization technologies, refiners would not consider these technologies to be viable and, if faced with our proposed 30 ppm standard in 2004, may select the more traditional, higher cost sulfur reduction processes. Some of these commenters suggested that we should delay the 30 ppm standard, and recommended a range of suggested deadlines (2005-2007).
We also received many comments which suggested that the ABT program restricted the generation of credits, and provided no certainty that credits would be generated prior to 2004. Commenters stated that two features in particular—the delay in establishing each refinery's sulfur baseline due to 1997-98 data review and the strict 150 ppm “trigger” for generating credits—caused them to question whether adequate sulfur credits would be available. If credits could not be guaranteed early enough to forestall investment decisions, refiners would be forced to begin construction earlier than we had projected. Under such a scenario, the costs of the program would be substantially greater, and many commenters suggested that, regardless of cost, it would be impossible for the entire industry to meet the deadline (due to limitations on engineering design and construction resources as well as the time required to obtain permits).
Finally, we received many comments which argued that not all refineries would be able to concurrently comply with the proposed standards in the time period provided, given the competition for engineering resources and the time needed for construction of desulfurization equipment. These comments focused specifically on small refineries (owned by both small and large corporations) and refineries that were relatively isolated geographically (such as many refineries in the Rocky Mountain region) which had little access to other sources of gasoline should they have difficulty in complying with our requirements. The commenters generally argued that these refiners needed more time than the rest of the industry to meet our proposed standards. Some of the commenters also argued that the standards applicable to many of these refiners should be less stringent because of their belief that the environmental needs of the states where these refineries were located and/or marketed gasoline were small relative to the needs of other states. Suggestions for temporary and permanent regional programs which provided less stringent control in the Western half of the country were included with many of these comments.
Based on what we've learned from the comments received and additional information we've gathered, we have revised our analysis of when refiners will invest in desulfurization equipment and how the sulfur ABT program can
About 15 percent of current domestic gasoline production already meets the gasoline sulfur standard, or can do so with very little additional capital investment, and at most a small increase in operating cost. The remainder of the industry—the majority of U.S. refineries—will have to install at least one desulfurization processing unit to lower gasoline sulfur to the required levels. Furthermore, many of these refineries will need to make changes to their operations in advance of 2004 simply to comply with the 300 ppm cap standard, even if they can obtain sufficient ABT credits to delay compliance with the 30 ppm refinery average standard. Refiners facing this situation will need to make their decisions within a year or at most two from today's action. From the comments we received and discussions we've had with refiners and technology vendors, we acknowledge that some of the newer, more promising processes may not be in operation for sufficient time to gain valuable operating experience (one to two years of operation) until 2002 or later. Hence, we now believe that some refiners may choose from one of the traditional, commercially-demonstrated desulfurization processes, even though these technologies may be more costly, to meet our standards.
However, we continue to believe that the majority of refiners will delay construction (taking advantage of the sulfur ABT program and perhaps making modest operational changes in the interim) and will have a wide range of technological options to choose from, at reduced capital investment and operating costs compared to the more traditional approaches. Examples of these technologies are CDHydro and CDHDS (licensed by the company CDTECH), Octgain 125 and Octgain 220 (licensed by Mobil Oil), S Zorb (licensed by Phillips), IRVAD (licensed by Black & Veatch), and others. These technologies generally use conventional refining processes combined in new ways, with improved catalysts and other design changes that minimize the undesirable impacts (such as a substantial loss in octane) and maximize the effectiveness of the desulfurization approach. Since these processes provide less costly ways to reduce gasoline sulfur, we have based our economic assessment (summarized in Section IV.D. below) on the presumption that the majority of refiners will elect to use one of these processes to meet the 30 ppm standard, even if it requires delaying compliance (through the purchase of ABT program credits) until 2006.
However, after considering the data available to us about current refinery sulfur levels and the ability of refiners to reduce sulfur levels to meet the standards, we have made several modest changes to the program. These changes will not affect the environmental performance of the proposed program. We agree that the declining cap had the unintended consequence of forcing investments earlier than desired for an orderly transition to the 80 ppm cap. Thus, we have changed the program from the proposal, establishing a 300 ppm per-gallon cap in 2004 and 2005. We do not expect this change to have an impact on the environment (or on the Tier 2 vehicles that will be introduced in this interim period) since average sulfur levels will be required to decrease due to the declining corporate average, which begins in 2004. We kept the corporate average standards proposed for 2004 and 2005, but are permitting inter-company trading around these standards. We believe this change will provide further flexibility to the industry in allowing some refineries to delay construction and encourage others to move forward sooner. Having now concluded that many refiners would benefit from an additional year to evaluate and consider the technological options before having to install equipment to meet the 30 ppm standard, we have delayed this standard for one year. In acknowledgment that some areas of the country have less urgent environmental needs for the emissions reductions that this program will bring, and that many of the refiners that supply gasoline to these areas are ones which will have the most difficulty in meeting the standards, we have finalized a geographic phase-in of the standards to complement the temporal phase-in applicable to the rest of the industry. Thus, in certain states in the West, refiners have the option of meeting interim standards while delaying compliance with the 30 ppm average until 2007. Finally, we have made changes to the sulfur baseline requirements and the credit trigger to help ensure that the sulfur ABT program functions as we originally envisioned it would.
These changes will encourage reductions in gasoline sulfur levels beginning as early as 2000, while providing enough flexibility to require the majority of refineries to meet a 30 ppm average sulfur standard by 2006. Overall, the industry will be able to spread the needed investments over several years rather than having to comply as a whole by 2004, and will be able to maximize the use of the most efficient and lowest cost technologies. While we have provided additional flexibility for the industry, we have done so without compromising the environmental benefits of the program in 2004 and beyond when compared to our proposal.
The following sections summarize the requirements for gasoline refiners and importers, including our geographic phase-in requirements; special provisions for small refiners, and our plans to facilitate the construction permitting process to enable refiners to install gasoline desulfurization technology in a timely manner. Section VI provides additional information about the compliance and enforcement provisions that will accompany these requirements. More detailed information in support of the conclusions presented here is found in the RIA and in our RTC document.
This section explains who must comply with the gasoline sulfur control requirements, the standards and deadlines for compliance, and how refiners can use the ABT program to meet the standards. The last section discusses how individual state gasoline sulfur programs are affected by today's action. Standards specific to eligible small refiners are presented in Section IV.C.2.
Anyone who produces gasoline for sale in the U.S. must comply with these regulations. This includes anyone meeting our definition of a refiner (including blenders, in most instances) and importers. Certain refiners may qualify for temporarily less stringent standards and deadlines because these companies either (1) market gasoline in the temporary geographic phase-in area (explained in section b below), or (2) they qualify under our definition of small refiner (explained in section IV.C.2 below). Foreign refiners may also have separate requirements, if they qualify as small refiners.
These requirements will apply to all gasoline sold in the U.S., including Alaska, Hawaii, Puerto Rico, American Samoa, the Virgin Islands, Guam, and
Table IV.C.-1. summarizes the standards for gasoline refiners and importers. There are three standards which refiners and importers must meet. In 2004 and beyond, every gallon of gasoline produced is limited by a per-gallon maximum or “cap.” The cap standard becomes effective January 1, 2004 (and January 1 of subsequent years as the cap standard changes). Also, in 2004 and 2005, each refiner must meet an annual-average standard for its entire corporate gasoline pool. Finally, each individual refinery is subject to a refinery average standard, beginning in 2005. Refineries that do not take advantage of the sulfur ABT program will have actual sulfur levels averaging 30 ppm beginning in 2005. Additional details about the requirements for meeting these standards is found in the following sections.
To reduce the potential for permanent damage to the emission controls of Tier 2 vehicles and later NLEV vehicles, we are implementing caps on the sulfur content of every batch of gasoline produced or imported into the country beginning in 2004. As shown in Table IV.C.-1, a cap of 300 ppm is first implemented in 2004. This cap remains in 2005. In 2006 and beyond, the cap is lowered to 80 ppm. These caps apply at the refinery gate. Sulfur caps are also applied to gasoline downstream of the refinery; see Section VI for additional discussion of downstream cap standards. These downstream caps will facilitate compliance and enforcement without changing the way the distribution system currently functions.
Several commenters suggested the rule should also include a provision to address the occasions when refiners must temporarily take processing units out of operation so that planned, recurring maintenance can be performed, commonly termed “turnarounds,” or if processing units are unexpectedly taken out of operation due to accident or malfunction, commonly termed “upsets.” These commenters expressed particular concern that the gasoline produced at a refinery may not meet the sulfur cap standards when a refinery's desulfurization unit is not operating. These commenters contended that the regulations should allow refiners to produce gasoline that exceeds the cap standard for a limited time where the excess sulfur is due to a turnaround or upset. However, they also suggested that the refiner should be required to meet the refinery average standard with the high sulfur gasoline included in its average calculation in order to create an incentive for refiners to limit the volume and sulfur content of high sulfur gasoline.
Today's rule does not grant relief to refiners because of turnarounds or upsets. While the concern raised by the commenters is reasonable, the solution they suggested would nevertheless result in distribution of gasoline exceeding the cap standards. The cap standards are necessary because gasoline with higher sulfur levels will significantly harm or destroy the emission controls used in Tier 2 vehicles.
We believe there are strategies refiners can use to mitigate or eliminate the difficulties associated with turnarounds and upsets. For example, some refiners schedule turnarounds for a number of refinery processing units at the same time when the refinery largely stops producing gasoline, thereby avoiding the need to produce any high sulfur gasoline. In other situations it may be possible for a refiner to store high sulfur products until the desulfurization unit is operating or to transfer high sulfur products to a neighboring refinery for desulfurization.
We commit to continue evaluating the turnaround issue especially as new technologies are introduced. Based on our evaluation, if a problem is evident and if an appropriate solution can be devised, we will act at that time.
In 2004, if any batch of gasoline
Refiners and importers must meet annual-average, volume-weighted sulfur standards for their entire corporate gasoline pool in 2004 and 2005. In 2004, this standard is 120 ppm; in 2005, it is reduced to 90 ppm. In 2006 and beyond, there will no longer be a corporate pool average standard, since each refinery and importer will be held to its own single refinery average standard, as discussed in the next section.
These standards represent the maximum allowable sulfur levels, on an annual average basis, for each refiner/importer, volume-weighted across all refineries owned and operated by that refiner (or all gasoline imported by the importer in the calendar year), rather than at each individual refinery or by each batch of gasoline. Thus, a refiner's gasoline may exceed the average standard of 120 ppm at one refinery, if sufficient gasoline below that standard is produced at its other refinery(ies), such that its corporate, volume-weighted average sulfur level does not exceed 120 ppm. Alternatively, allotments may be used to meet this requirement. This requirement does not apply to small entities or to corporations that do not have to meet the pool average standard in the GPA program. For compliance with this corporate averaging requirement, as well as with the other requirements of this subpart, we consider a parent corporation owning wholly-owned subsidiaries that also own refineries to be the refiner of these facilities. Thus, the parent corporation must comply with refiner corporate average requirements. In its compliance calculations, the refiner must include the gasoline produced at the refineries it owns, plus the gasoline produced at the refineries owned by its wholly-owned subsidiaries.
For purposes of compliance, we proposed that a joint venture, in which two or more refiners collectively own and operate one or more refineries, be treated as a separate refining corporation under the gasoline sulfur requirements. Hence, a refinery owned by a joint venture would have been included in the corporate pool calculations of the joint venture, and could not have been included in calculations with other refineries solely owned by one of the parties to the joint venture. Based on comments we received on this issue which argued that a company with majority ownership in the joint venture should be allowed to count the jointly held refinery in its corporate average, we have revised our treatment of refineries owned by joint ventures. Each joint venture must separately meet the corporate pool average standard, whether the joint venture owns one or multiple refineries. If a joint venture fails to meet the corporate pool average standard, then each partner in the joint venture is jointly and severally liable for the violation. However, if one partner to a joint venture refinery includes the joint venture refinery in its corporate pool, and that corporate pool meets the corporate pool average standard, then the joint venture will be considered by EPA to be in compliance (if the joint venture owns only the one refinery). If the joint venture owns multiple refineries and only one or some of the refineries is included in the corporate pool calculations of one partner, compliance by the joint venture with the corporate pool average standard will be judged based on the average sulfur levels of the remaining refinery(ies) owned by the joint venture.
In meeting the corporate average stds in 2004 and 2005, refiners and importers may use allotments as discussed in IV.C.1.c below.
Beginning in 2005, every refinery must meet an average standard of 30 ppm sulfur at the refinery gate on an annual, volume-weighted basis. Similarly, every importer must meet the 30 ppm average standard beginning in 2005. (These requirements do not apply to small entities or to GPA gasoline). In meeting this standard, individual refineries and importers may use credits generated or purchased under the provisions of the sulfur ABT program discussed below in Section IV.C.1.c, and/or, in 2005 (only), sulfur allotments (as described in the previous section) obtained from a refiner who has excess allotments to sell, if they are unable to comply based on their actual gasoline sulfur levels. Hence, the actual average sulfur levels for gasoline produced at some refineries can be higher than 30 ppm in 2005, but only if refiners use (1) credits generated from cleaner gasoline produced early and/or (2) allotments generated by a refiner which produces gasoline averaging, on a corporate basis, lower than 90 ppm in 2005. However, the corporate pool average standards and per-gallon caps will limit the degree to which gasoline can exceed 30 ppm on average.
We allow refiners to use either sulfur allotments or ABT credits to meet the 30 ppm standard in 2005 for several reasons. First, this is an environmentally neutral approach because the national pool in 2005 will still average no greater than 90 ppm, since every refiner must meet the corporate average standard before applying allotments to the compliance of any refineries with the 30 ppm standard. Second, it provides refiners who have excess allotments in 2005 an additional market for those allotments, thus giving refiners an incentive to exceed the 90 ppm corporate average standard in 2005. In either case, the reductions will have occurred and thus the allotments and credits have very similar purposes and thus should be interchangeable.
In 2006 and beyond, the 30 ppm refinery average standard continues to be a requirement for every refinery or importer. The sulfur credits generated in the ABT program may be used by refineries or importers to comply with this requirement. However, because of the 80 ppm cap in these years, we expect that the majority of refiners/importers will average 30 ppm, although some individual refineries/importers could average slightly more or less (if the refineries/importers bank, sell, or purchase credits to meet this standard, as explained in the ABT discussion below). Furthermore, the majority of credits will expire at the end of 2006.
As indicated above, certain refiners may qualify for temporarily less stringent standards and deadlines for some or all of their gasoline because these companies either (1) produce gasoline to be sold in the temporary geographic phase-in area (GPA) or (2) qualify under our definition of small refiner. In this section, we explain the geographic phase-in area of our program and the interim standards and deadlines for compliance in that area. The provisions that apply to qualifying small refiners are described in section IV.C.2., below.
In addition to phasing in our national gasoline sulfur program temporally from 2004-2006, we are phasing in our program geographically. In response to our proposal, we received many comments from the refining industry regarding timely implementation of our proposed gasoline sulfur program. Commenters argued that not all refineries would be able to concurrently comply with the proposed standards in the time period provided, given the competition for engineering resources and the time needed for construction of
As part of our assessment we also examined other phase-in approaches which might enhance the orderly introduction of refining technology without jeopardizing the environmental benefits of our program. As a result of this assessment, we have concluded that many states in the Great Plains and Rocky Mountain areas of the United States have a somewhat less urgent environmental need for ozone precursor reductions in the near term. Moreover, their gasoline supply is dominated by that produced by small capacity, geographically-isolated refineries located therein. As a general rule, refineries in this area will have the most difficult time of all refineries nationwide in competing for the vendor, supply, engineering, and construction resources needed to modify their refineries to comply with the standards. Based on 1998 Department of Energy data, over 80 percent of the gasoline sold in this area is produced by the relatively small refineries located within the region.
A more orderly and cost-efficient phase-in of the 30 ppm standard could be achieved if all gasoline sold in this area was subject to somewhat less stringent standards than those in the rest of the country for a short time. This approach will allow the refineries producing gasoline for use in this area more compliance flexibility, more time to install and prove out the equipment needed for compliance, and thus a greater opportunity to reduce their overall costs. As described below, this approach results in only a minimal loss in emission reduction benefits. By stretching out demand for design, engineering, construction and other related services during the 2000-06 period, these provisions should also help to reduce the overall costs of the gasoline sulfur program.
The remainder of this section is divided into two parts. The first describes the rationale for development of this approach and how we identified the appropriate area, and the second provides a description of the requirements for refiners and importers that produce fuel for sale in the area.
As we considered the geographic phase-in approach, we aimed to minimize the environmental losses which could occur from exposing Tier 2, NLEV, (and other) vehicles to higher gasoline sulfur levels when the gasoline sulfur standards are being phased in nationwide. We used two criteria to develop and evaluate this approach: (1) relative environmental need and (2) the ability of U.S. refiners and the distribution system to provide compliant gasoline.
The states we have identified for the GPA are shown in Figure IV.C-1.
The first and primary criterion we considered in defining this area was environmental need. In defining the GPA, we identified those states that have somewhat less urgent environmental need in the near term for reductions in ozone precursors and whose emissions are less important in terms of ozone transport concerns. This area includes some states that are located in the Great Plains and the Rocky Mountains, as well as Alaska. Most states within the Rocky Mountains and Great Plains do not have a compliance problem with the 1-hour ozone standard in the near term, although they do have concerns in terms of maintaining compliance with the particulate matter standard. However, there are two states (Arizona and Nevada) in the Rocky Mountain vicinity that do have ozone air quality concerns. These states have instituted local fuel quality programs (in Phoenix, AZ and Las Vegas, NV) to reduce ozone precursor emissions. In addition, as shown in Table III.C-2, Arizona and Nevada are projected to have concerns with PM10 compliance in the future. Given these factors, we excluded them
We also defined the phase-in area based on the relative difficulty of producing or obtaining complying gasoline. The refining industry in the GPA is dominated by relatively low capacity, geographically-isolated refineries many of which are owned by independent companies. Such refineries face special challenges in complying with the requirements of the national program by 2004 because their crude capacity, corporate size, and location make it difficult for them to compete for the design, engineering, and construction resources needed to comply by 2004.
Furthermore, an assessment of 1998 gasoline production and use data and information on the products pipeline system shows that states in the GPA and portions of several adjoining states are solely or predominantly dependent on gasoline produced by these refineries and have limited or no access to gasoline from other parts of the country. Based on this analysis, we concluded that several states and portions of other states meeting our first criterion (less urgent environmental need for ozone precursor emission reductions) also face the likelihood of a supply shortage of low sulfur gasoline. Providing low sulfur gasoline to these states and adjoining areas is expected to be more difficult and costly in the near term. Section IV.C.1.b.vii below, discusses how the adjoining areas (counties/tribal lands) will be identified.
Thus, we believe it is appropriate to phase in the 30 ppm average, 80 ppm cap standards in these areas by allowing an additional year compared to the rest of the country, rather than delaying implementation of the standards nationwide to accommodate these states. Under this approach, the areas with the most urgent need for the ozone reduction benefits associated with low sulfur gasoline will realize them as soon as is feasible, and other areas will experience them shortly thereafter.
On the other hand, much of the area in the adjoining states has significant pipeline, rail, barge, and truck access to gasoline which will be capable of meeting the standards in Table IV.C-1 beginning in 2004. Even if these states have less environmental need in the near term, there are health benefits (particulate and air toxic emission reductions) as well as performance benefits for vehicle emission control systems (including avoidable irreversible sulfur effects) which need not be foregone. Therefore, we concluded that since it will not be more difficult to send gasoline to these adjoining areas through the distribution system, the significant environmental benefits of requiring low sulfur gasoline as early as is feasible justifies excluding these states from the GPA.
Some might argue that there are other states which should be considered under this program. However, based on our criteria of environmental need (including ozone transport and irreversibility concerns) challenged refineries, and limited access to complying gasoline we could identify no other states or territories which to include.
While the states in the GPA may have less of an environmental need for ozone precursor reductions in the near term, there are significant environmental reasons to make the program as stringent as possible, still enabling a smooth transition to low sulfur gasoline nationwide. Toward that end, we are establishing the following requirements for gasoline sold in the GPA, which we view as the appropriate balance between these two factors.
The GPA provision covers all gasoline produced or imported for use in the GPA, whether refined there or brought in by pipeline, truck, rail, etc.
Corporate pool average standards apply in the national gasoline sulfur program for calendar years 2004 and 2005. Most refiners/importers producing gasoline for use in the GPA market the majority of their gasoline outside of the GPA where they compete with many other refineries. Since the phase-in of the national program expects compliance with the 120/90 ppm corporate pool average standards in 2004 and 2005, we are requiring that refiners/importers who market the majority (greater than 50 percent of production volume) of their gasoline outside of the GPA to account for the sulfur levels of their GPA gasoline in their calculation for compliance with the corporate pool average standards.
To provide additional flexibility during this phase-in, refiners may use sulfur ABT credits and allotments (as explained in IV.C.1.c) to meet these standards. Refineries producing GPA gasoline can generate credits beginning in 2000 under the provisions of the national program (described in section IV.C.1.c). Also, refineries/importers marketing gasoline in the GPA may through extraordinary measures be able to generate credits in 2004-2006. To qualify they must achieve levels below 150 ppm or their more stringent baseline levels as discussed above whichever is less. Under these circumstances, these refineries/importers can earn credits for the GPA gasoline they produce during 2004-06. Credits generated under the GPA program are fully fungible with national credits and are subject to the same regulatory requirements.
The national program includes provisions which permit refiners/importers to generate allotments for use in 2004 and 2005. Refiners and importers marketing gasoline in the GPA may only generate sulfur allotments in 2004 or 2005 if their corporate average sulfur level meets the corporate pool average standards for each year (as indicated in Table IV.C.1), including gasoline produced for the GPA, if applicable. Refiners not compelled to meet the corporate pool
The temporary provisions for the GPA apply for three years, 2004 through 2006. Since the low sulfur standards for the rest of the country require compliance with a 30 ppm refinery average standard and an 80 ppm gallon cap in 2006, the geographic phase-in provides an additional year to reach those standards. This extra year and the somewhat less stringent standards during the phase-in will provide the refining industry the opportunity for more orderly transition to the 30/80 ppm standards by 2007.
Requirements for gasoline sold in the GPA are summarized in Table IV.C.-2, below. Gasoline produced by refiners subject to the small refiner standards described in Section IV.C.2. of this notice is not subject to the provision of the geographic phase-in, since the small refiner provisions apply to eligible refiners regardless of geographic location. Gasoline produced by such refiners can be sold nationwide, including in the GPA.
The sulfur level caps for gasoline sold in the phase-in area and the rest of the nation are the same in 2004 and 2005, but in 2006 the cap remains at 300 ppm in this area while it declines to 80 ppm for the rest of the country. To assure that compliance at the refinery gate is correct regardless of where the gasoline is ultimately sold, as gasoline intended for the GPA moves in the distribution system to or through the geographic area it must be identified as phase-in area gasoline in product transfer documents and must remain segregated from gasoline intended for use outside this area. In addition, use of phase-in area gasoline is prohibited outside the GPA, but the converse is allowed, i.e., gasoline designated for use outside the GPA can be used in this area. For all three years, refiners and importers must meet the requirements described in Tables IV-C.1 and IV-C.2, as applicable, and therefore must maintain refinery or import records as applicable as to where a gasoline batch is sold.
We recognize that this higher standard/cap for one year could create the incentive for those not marketing gasoline in the GPA today to seek a market to sell higher sulfur gasoline and for others to seek to increase market share. While this is indeed allowable under our program and is perhaps to be anticipated in a free market system, in all likelihood the incentives are small. Such refiners/importers would still have to meet the 150 ppm average and would perhaps face increased shipping and marketing costs. Nonetheless, we plan to monitor market developments to assess whether such a provision creates significant market shifts or the potential for increases in average sulfur levels in the GPA gasoline.
Those refiners or importers that sell all of their gasoline to the GPA (
Furthermore, any refiner/importer which certifies 50 percent or more of its gasoline production volume for sale as GPA gasoline in 2004 and 2005 is not required to meet the corporate pool average for that year for its entire gasoline pool. Not only would it be difficult to comply on average (if it were assumed that the GPA gasoline was 150 ppm and non-GPA gasoline was 30 ppm), but also it would undermine the achievement of the basic goal of a more orderly and efficient phase-in of low sulfur gasoline since the flexibility afforded by the GPA could be diminished.
Otherwise, those who produce less than 50 percent of their gasoline for the GPA (which is the majority of those refiners which market in both locations), must meet the corporate pool average standards in 2004 and 2005 for their entire gasoline pool. Thus, such refiners must compensate for the higher sulfur levels of their GPA gasoline by producing non-GPA gasoline that averages sufficiently less than 120 ppm in 2004 and 90 ppm in 2005 to ensure that their corporate average meets the corporate pool average standard for each year. Importers who provide less than 50 percent of their gasoline to the GPA must also include their GPA gasoline in their overall corporate pool average calculation. Alternatively, the refiner can use sulfur allotments to meet the corporate pool average standard for its total gasoline production, including gasoline sold inside and outside the phase-in area. Since most refiners which sell gasoline both in and outside the GPA sell the vast majority outside the GPA the additional flexibility provided for gasoline sold in the phase-in area should not significantly affect compliance with the corporate pool average standard for a refiner's nationwide production.
As part of program administration, we are requiring that any refiner/importer
EPA is establishing a geographic phase-in area that encompasses eight states (MT, ND, ID WY, CO, UT, NM, AK). In addition, counties and tribal lands in states immediately adjacent to these which received a majority of their gasoline in calendar year 1999 from a refinery(ies) located within the GPA will be covered by the phase-in area provisions. The criteria to identify these additional counties and tribal areas are designed to identify areas whose gasoline distribution system is closely tied to the eight states such that they share the same characteristics of gasoline supply. Therefore, dispensing outlets (retail and private) in such areas will continue to have access to that gasoline in most cases. Distribution and production of gasoline in these additional areas will be subject to the same standards and requirements as gasoline in the eight states identified above.
At this time, EPA is not able to identify all the counties and tribal lands that would be included in the phase in area. In light of the air quality benefits of introducing low sulfur gasoline as quickly as possible, we want to ensure that the phase-in area is accurately identified and that including any areas outside these eight states will not have a significant adverse air quality impact on any counties or tribal lands that are included in the phase-in area. EPA will be working with interested stakeholders will to conduct an assessment to determine which counties/tribal lands within the immediately adjacent states meet the criteria as described in the regulatory text. EPA expects to complete action on this assessment by December 31, 2000. c. How Does the Sulfur Averaging, Banking, and Trading Program Work?
The sulfur ABT program provides flexibility to refiners by giving them more time to bring all of their refineries into compliance with the corporate averages in 2004 and 2005 as well as the 30 ppm individual refinery standard in 2005 and beyond. ABT will provide the opportunity for reduced costs by allowing the industry the flexibility to average sulfur levels among different refineries, between companies, and across time. With ABT, some refineries will be able to delay installation of desulfurization equipment, because other refineries will generate sulfur allotments and credits through early sulfur reductions. In this way, installation of desulfurization technology will be spread out over a longer period of time than would be the case without ABT. Since, with the banking provisions, reductions in annual average sulfur levels which occur as early as 2000 have a value during program implementation, the ABT program provides an incentive for technological innovation and the early implementation of refining technology.
The ABT program also provides the opportunity for meaningful emissions reductions in 2004 because it allows the Tier 2 standards to be implemented earlier than might otherwise have been possible (if the Tier 2 standards were delayed to provide the refining industry more time to comply), and because it provides direct environmental benefits even in the years before Tier 2 vehicles are introduced. One benefit is related to the effect of gasoline sulfur on exhaust emissions, as discussed in the Regulatory Impact Analysis. This benefit will result both from older vehicles on the road (Tier 0 and Tier 1 emission control technologies, which have some degree of sulfur sensitivity and will benefit from sulfur reductions which occur prior to implementation of the refiner and refinery standards summarized in Table IV.C-1) and from NLEV vehicles (which are more sensitive to sulfur than earlier technologies) which will continue to be sold while Tier 2 vehicles are phased-in. Another environmental benefit is the reduction in atmospheric sulfur loads as a direct result of reduced gasoline sulfur levels, leading to reduced emissions of sulfur-containing compounds from motor vehicles.
The following sections explain the requirements for participation in the sulfur ABT program for allotments and credits.
To provide additional incentive for early sulfur reductions and to enhance the overall feasibility and cost effectiveness of the gasoline sulfur control program, we are implementing a sulfur allotment program. While few commenters supported the sulfur allotment concept in the NPRM, a number suggested that greater flexibility for compliance in the early years would be helpful. The program described below is in addition to the early sulfur credit program described elsewhere.
For 2003, refineries can generate sulfur allotments (in ppm-gallons) by producing gasoline containing less than 60 ppm sulfur on an annual-average basis. This 60 ppm “trigger” was chosen to reward refineries who demonstrate compliance using technology designed to meet the 30 ppm standard before 2005. Once this 60 ppm trigger is reached, allotments will be calculated based on the amount of reduction from 120 ppm.
For 2004 and 2005, refiners or importers (but not individual refineries)
Refiners and importers can use sulfur allotments that they generate or purchase from other refiners/importers to demonstrate compliance with the 120 ppm corporate standard in 2004 and the 90 ppm corporate standard in 2005. Each refiner's sulfur allotment for 2004 and 2005 will be calculated based on the total volume of gasoline imported and produced at their refineries (or only imported gasoline in the case of companies that only import gasoline) and the corporate pool average standard for that year. In anticipation of exceeding or falling short of the standard for any one year, companies may trade sulfur allotments, either in the compliance year or earlier (as early as the year 2000). For example, a refiner that expects to produce a total of 2.5 billion gallons of gasoline in 2004 has a sulfur allotment of 300 billion ppm-gallons (120 ppm × 2.5 billion gallons). If its corporate pool average is actually 200 ppm in 2004, it will exceed its 2004 allotment by 200 billion ppm-gallons (since 200 ppm × 2.5 billion gallons = 500 ppm-gallons), and must obtain sulfur allotments from another refiner to offset this increase. Similarly, if this refiner expects to average 80 ppm in 2004, it has an excess of 100 billion ppm-gallons to trade to other refiners. However, if a refiner trades away part of its allotment, the refiner must still comply with the corporate standard, just as another refiner has to do if it does not trade allotments.
In 2005, refiners must comply both with the corporate average standard and the refinery average standard for each of their refineries. Once a refiner has established compliance with the 90 ppm corporate average standard (with or without the use of allotments), each of its refineries can then establish compliance with the 30 ppm refinery standard through actual production of 30 ppm gasoline or through the use of
We expect most refiners will trade sulfur allotments well before the end of each compliance year so they will have the needed certainty of compliance with the corporate average standard. Our program allows such trades to occur at any time during the year, although the refiner is liable for any shortfall in compliance resulting from having traded away too many allotments. A refiner may also carry over excess 2004 allotments (those generated in 2003 or 2004) for compliance with the 90 ppm corporate standard for 2005. However, those allotments must be discounted by 50 percent. This 50 percent discount factor is needed to equalize the emission impact of sulfur control between 2004 and 2005. In 2005, there is an extra model year of NLEV/Tier 2 vehicles relative to 2004. In addition, the NLEV/Tier 2 fleet is one year older in 2005 than 2004. This increased age translates into higher vehicle emissions due to general deterioration. Since sulfur acts on a percentage basis, the absolute emission increase due to sulfur impacts on vehicle emission control systems in 2005 is higher than in 2004.
As discussed below in section IV.C.1.c.x, a refiner or importer may convert allotments into credits in 2004 and 2005 for compliance with the refinery average standards in 2005 and beyond. All transactions between refiners involving sulfur allotments must conclude by the last day of February in the calendar year following the compliance year in which the allotments are to be used.
The purpose of establishing a sulfur baseline for each refinery is to provide a starting point for determining sulfur credits for reductions in gasoline sulfur levels. We proposed that refiners would have to establish a sulfur baseline for each individual refinery, by submitting to us data establishing their annual average gasoline sulfur level based on the average of their 1997 and 1998 operations. We would review the data and, barring any discrepancies, approve a sulfur baseline for each refinery. We received comments supporting this option as well as comments stating that the time involved for this application and approval process would delay the refiner's ability to plan for and begin construction of gasoline desulfurization technology. Refiners would want the certainty of an approved sulfur baseline before making investment decisions, and thus would wait to obtain EPA's approval before proceeding. We also received comments about what year(s) would be most appropriate to use to establish a sulfur baseline. Some of these comments argued for the use of existing, approved 1990 baselines, or some adjusted version of 1990 baselines, rather than new data, to expedite the process of establishing sulfur baselines.
We also proposed a different sulfur baseline for reformulated gasoline (RFG) produced in the summer for those refineries which produce reformulated gasoline. While the conventional gasoline sulfur baseline (and the baseline for winter RFG) was proposed to be tied to current sulfur levels, the baseline for summer reformulated gasoline was proposed to be 150 ppm, the approximate level we expect summer reformulated gasoline to contain in 2000 and beyond because of the Phase II reformulated gasoline requirements, which take effect in 2000. We argued that winter RFG did not have any de facto sulfur restrictions, and thus winter RFG should be counted with conventional gasoline for the purpose of credit generation relative to the refinery's conventional gasoline sulfur baseline.
Since the proposal, we have learned that overall gasoline sulfur levels (conventional plus reformulated) are significantly lower than they were in 1990. As explained in the Regulatory Impact Analysis, national average sulfur levels when both conventional and reformulated gasolines are considered dropped to 306 ppm in 1997 and 268 ppm in 1998, compared to the 1990
Furthermore, as we proposed, and some commenters argued, we have concluded that averaging data from two years is the most appropriate approach, because averaging over two years will help to account for any unusual variations in operations that may have occurred at individual refineries in either of these years. We concluded that averaging data from 1998 and 1999 is not feasible, because the 1999 data will not be fully available to EPA until after the reporting deadline of May 2000. Hence, we believe it is preferable to use 1997 and 1998 data, rather than delaying the time baselines are established. We do not expect significant changes in 1999 sulfur levels relative to 1998 levels, so we believe the use of the 1997-1998 data provides a reasonable representation of current sulfur levels.
We have also learned that summer reformulated gasoline is already averaging close to our expected sulfur level for the year 2000. Winter RFG does not show this same decrease, presumably because refiners are shifting high sulfur blendstocks out of RFG in the summer but back into RFG in the winter to maintain compliance with the conventional gasoline antidumping requirements. Thus, it appears that if we held summer RFG to a lower baseline, as proposed, we would have to raise the winter RFG baseline commensurately to reflect actual refinery operations. The net environmental impact would be no different than if we had a single sulfur baseline applying to all RFG, or to all gasoline produced at the refinery, since the annual pool sulfur levels are constant even while there may be seasonal variations. Therefore, we are not finalizing a separate sulfur baseline for summer RFG, but rather combined conventional and reformulated gasoline sulfur levels.
Having considered the comments we received and the new data available to us, we have concluded that refiner sulfur baselines should be established from 1997 and 1998 operating data. Hence, we are requiring refiners which wish to generate sulfur credits prior to 2004 to establish a 1997-98 sulfur baseline for each refinery at which they intend to generate credits. We believe the process we have defined will minimize the burden to the industry and the time it will take for us to review and approve the sulfur baselines. Specifically, refiners which plan to generate sulfur credits must submit to us information which establishes the batch report numbers, sulfur levels, and volumes of each batch of gasoline produced in 1997 and 1998, as well as the annual average sulfur level calculated from these data. Within 60 days, we will review the application and notify the refiner of approval or of any discrepancies we find in the data submitted. If we do not respond within 60 days, the baseline should be considered to be approved.
While we expect most refiners will apply for a sulfur baseline in the near future (to maximize the time that they can generate credits before 2004), there is no cut-off date for applying for a sulfur baseline. However, if the refiner wishes to generate credits for a given calendar year, we must receive his baseline application no later than September 30 of that year to provide us adequate time to review the baseline prior to the end of the year (at which time any credits generated in that year would be assessed and reported by the refiner). We believe that this approach for establishing sulfur baselines meets our goal of providing a workable ABT program that refiners can take advantage beginning in the year 2000, without sacrificing the environmental benefits of the sulfur standards.
Foreign refiners which have already established an individual refinery baseline with us, and thus have submitted reports on all batches of gasoline sent to the U.S. in 1997 and 1998, may follow this same procedure if they wish to generate sulfur credits prior to 2004. Foreign refiners which have not reported 1997-98 gasoline qualities to us must follow an alternate approach. Specifically, they must follow the general requirements of our protocol for establishing individual refinery baselines (see §§ 80.91-94 and also § 80.410) by providing sufficient data to establish the volume of gasoline imported to the U.S. from each refinery in 1997-98 and the annual average sulfur level of that gasoline. If the test method used to identify the sulfur level differs from the one specified in today's action, the refiner must provide sufficient information about the test method to allow us to evaluate the appropriateness of the alternative. Because this information will be new to us, we may require more time to review and approve their 1997-98 sulfur baseline. But, consistent with our previous handling of foreign refiner submissions, once we have determined that the submission is complete and the protocol has been followed, they may use the baseline while waiting for our formal approval. However, the refiner will be held to the baseline that is ultimately approved. A foreign refiner who is unable to generate adequate data to establish a 1997-98 sulfur baseline will not be permitted to generate sulfur credits in 2000-2003.
Small refiners that plan to request small refiner standards (as provided in Section IV.C.2 below) which also want to generate early sulfur ABT credits will use the same data required to define their small refiner baseline to determine their baseline for the ABT program. In other words, if a refiner becomes a small refiner under our definition and procedures, credits generated by that refinery would be calculated relative to the refinery's actual 1997-98 sulfur average. The trigger for generating sulfur credits under the ABT program (discussed in the next section) would still apply for small refiners generating credits prior to 2004 relative to their 1997-98 sulfur average. In addition, the applicable interim sulfur standard for small refiners who generate credits through sulfur reductions prior to 2004 will be calculated based on the reduced sulfur level, rather than the 1997-98 baseline level, as explained below in Section IV.C.2.
Importers and gasoline blenders will not be assigned a sulfur baseline because they are not eligible to generate early credits (prior to 2004) under the ABT program. This includes gasoline refiners who are also importers; such parties cannot generate sulfur credits prior to 2004 on the basis of their imported gasoline but may only generate credits based on the gasoline produced by their refinery(ies). It also includes oxygenate blenders, who, as discussed in Section VI below, are not subject to the sulfur standards but are responsible for compliance with the downstream provisions.
In the proposal, we also discussed the need for a baseline gasoline volume as well as a baseline sulfur level. This stemmed from the design of our current conventional gasoline anti-dumping program, which requires a baseline volume so that we can confirm that conventional gasoline is no dirtier now than it was in 1990. However, for the gasoline sulfur ABT program, we have determined that there is no need to restrict refineries' sulfur baselines (against which they can generate sulfur credits) to a specific volume of gasoline. The purpose of the ABT program is to encourage early sulfur reductions by some refineries, and we see no need to limit the amount of credits such a refinery can generate on the basis of a historic volume of gasoline production. In fact, additional volumes of cleaner gasoline should achieve additional early environmental benefits.
In our proposal, we discussed a credit generation trigger of 150 ppm for early credit generation (2000-2003), arguing that we wanted to encourage investment in desulfurization technologies that refineries ultimately need to get to a 30 ppm average. Many comments we received argued that the 150 ppm trigger was too restrictive, requiring capital investments that most refiners could not make earlier than 2004 (due to construction limitations, among other reasons). Thus, few credits would be generated, and without sufficient certainty that credits would be generated, refiners would not be able to count on the flexibility that the ABT program was intended to provide when planning their compliance strategies for 2004 and beyond.
Having considered these comments and reanalyzed the ability of the industry to comply with the standards in 2004 (as we discussed above at the introduction to section IV.C.1), we have concluded that the proposed 150 ppm trigger would inappropriately limit the credits available. While we want to encourage refiners to make reductions early, we do not want to preclude refiners from making less capital intensive sulfur reductions in the short term while they prepare to reach the 30 ppm average in the long term. At the same time, we believe that a refinery should be required to demonstrate that the sulfur reduction was real and not just a consequence of national variations from year to year. Hence, we are establishing a trigger which we believe represents a sulfur reduction that requires action above and beyond simple annual or even seasonal fluctuations in crude oil sulfur level or product slate variations that could have a very small impact on annual sulfur average.
During the period 2000-2003, credits can be generated annually by any refinery that produces gasoline averaging at least 10 percent lower than that refinery's baseline sulfur level. In other words, to generate credits, the refinery's annual average sulfur level for all of its gasoline on average must be 0.9 × (baseline sulfur level). Once this “trigger” is reached, credits will be calculated based on the amount of reduction from the refinery's sulfur baseline. For example, if in 2002 a refinery reduced its annual average sulfur level from a baseline of 450 ppm to 150 ppm (well below the trigger of 0.9×450=405 ppm), its sulfur credits will be determined based on the difference in annual sulfur level (450-150=300 ppm) multiplied by the volume of gasoline produced in 2002. Similarly, foreign refineries with an individual sulfur baseline can generate credits in these years as long as the annual average sulfur level of the gasoline imported to the U.S. from that refinery is lower than 90 percent of the baseline sulfur level.
Although by adopting a more modest trigger for credit generation we are enabling more credits to be generated, the environment will still benefit from our program. Although the use of a more modest trigger keyed to each refinery's sulfur baseline may allow more credits to be generated, we believe this will only occur because the credit program is providing incentives to refineries to reduce sulfur levels earlier than they would have otherwise, particularly with a strict 150 ppm trigger. Thus, more lower sulfur gasoline will be in the marketplace prior to 2004 than would otherwise have occurred, given our understanding of the state of desulfurization technologies and the likely pattern of investments by the industry. With our corporate average and cap standards, sulfur levels will continue to decrease after 2004, even if individual refineries take an added year or two to meet the 30 ppm standard.
We had also proposed that credit generation prior to 2004 would be different for reformulated gasoline than for conventional gasoline, because reformulated gasoline's assigned sulfur baseline was proposed to be 150 ppm. Thus, we proposed that credits could only be generated from reformulated gasoline if the sulfur level averaged below 150 ppm, and that the credits would be calculated based on the difference between 150 ppm and the new, lower average. Since we have not finalized a separate baseline for reformulated gasolines, we are not adopting a different process for generating credits from reformulated gasoline. All gasoline produced at the refinery in 2000 (and beyond) is considered in calculating the annual average sulfur level, compliance with the 90 percent trigger, and the sulfur credits earned, if any.
Several states have adopted or are considering adopting gasoline sulfur control programs (see discussion at section IV.C.1.d below on state sulfur programs). While we had proposed to exclude this gasoline from sulfur credit generation, we have reconsidered our position. Gasoline produced in response to state
In 2004 and beyond, refineries, blenders, and importers can generate credits, but only if the actual annual sulfur level of all gasoline produced or imported averages below 30 ppm, and only for the difference between the standard and the actual annual sulfur average. (For example, a refinery producing gasoline in 2005 that averages 25 ppm can generate 30-25=5 ppm sulfur credits on the total volume of gasoline produced at that refinery.) However, since in 2004 and beyond importers are the regulated party responsible for ensuring that imported gasoline meets the sulfur standards, foreign gasoline would in effect generate sulfur credits through the importer beginning in 2004. Foreign refineries which want to send gasoline containing less than 30 ppm sulfur to the U.S. would still benefit from doing so by making appropriate arrangements with importers, which are subject to all of our standards.
Refineries, blenders, and importers can use sulfur credits to demonstrate compliance with the 30 ppm annual average refinery standard in 2005 and beyond, if they are unable to meet the standard with actual gasoline production. During 2005 and 2006 only, refineries may use credits banked by that refinery in 2000-2003 as a result of early sulfur reductions, or credits purchased from other refineries which have banked early sulfur credits. Blenders and importers can purchase credits from refiners (including any foreign refiners which generated early credits), or use credits they generated in 2004 and beyond. All transactions will have to be concluded by the last day of February after the close of the annual compliance period (2005, 2006, etc.).
As discussed above, 2005 is the only year when averaging and trading against the corporate average and averaging, banking, and trading against the refinery average are both allowed. In that year, sulfur credits may only be used against the 30 ppm standard for each refinery once the refiner has demonstrated compliance with the corporate pool average standard. The refiner must meet his corporate average based on actual sulfur levels or through a trade for sulfur allotments if it falls short of the 90 ppm corporate average standard. At that point, each of his refineries is evaluated for compliance with the 30 ppm refinery average standard. Those refineries that are not producing gasoline averaging 30 ppm sulfur must obtain sulfur credits generated in 2005 or earlier and/or sulfur allotments to bring the refinery's sulfur average from the actual level (a maximum of 90 ppm for each refinery, since by meeting the corporate average, even if in part through the use of allotments, each refinery in the company will be considered to average no more than 90 ppm) down to 30 ppm.
Refineries or importers which sell some or all of their gasoline in the GPA (and which have elected to participate in the phase-in) may also use sulfur credits to meet their refinery averages in 2004-2006. However, because this gasoline must be designated for sale in the GPA, they must account separately for compliance with the 150 ppm refinery average for gasoline sold in the phase-in area and with the 30 ppm refinery average for gasoline sold outside of that area. Thus, in 2004, such refiners/importers may use sulfur credits to establish compliance with the 150 ppm standard for gasoline sold in the phase-in area, if required. In 2005 and 2006, they may use credits to meet the 150 ppm standard for gasoline sold in the area and/or use credits to meet the 30 ppm standard for gasoline sold outside of the area.
As explained in section IV.C.1.b., some of the refiners participating in the GPA are exempt from the corporate average standards, but may use either sulfur credits or sulfur allotments in 2004-2006 to establish compliance with the 150 ppm refinery average standard. Those that are not exempt from the corporate average standards may use sulfur allotments only to meet the corporate average standards. For such refiners, compliance with the corporate average standard will be measured first (using allotments if needed), then compliance with the refinery average standard (using credits and/or allotments as needed) in the same manner as described above for refiners who sell all of their gasoline outside of the GPA.
Foreign refineries are not required to comply with the 30 ppm refinery standard in 2005 and beyond; instead, compliance for foreign gasoline is required by the importer. Sulfur credits generated by foreign refineries prior to 2004 will still have value, since these refineries can sell sulfur credits to U.S. refineries, blenders, or importers who need credits to meet the standard in 2005 or beyond. In fact, foreign refiner's credits could simply be transferred to the importer which is importing that refinery's gasoline into the U.S. For example, a foreign refiner could send gasoline exceeding 30 ppm on average to an importer and transfer the appropriate amount of sulfur credits it generated prior to 2004 to allow the importer to meet the 30 ppm standard. Similarly, after 2004 a foreign refiner may send gasoline containing less than 30 ppm to the U.S. through an importer, and the importer would benefit from generating credits (and presumably would include the value of these credits in the financial transaction with the foreign refinery).
As explained in Section IV.C.3.b. above, in 2005 no batch of domestically produced or imported gasoline can exceed 300 ppm, and a refiner's/importer's annual corporate pool average sulfur level cannot exceed 90 ppm, except for gasoline sold in the GPA or by small refiners complying with the standards in Table IV.C.-3. In 2006 and beyond, sulfur is capped at 80 ppm and there is no longer a corporate pool average standard. These standards (as well as the 300 ppm cap and corporate pool averages) cannot be met through the use of credits generated under the ABT program. As described above, credits may only be applied to demonstrate compliance with the 30 ppm refinery standard, not to the corporate pool average or the cap. Given the limitations that the 80 ppm cap places on sulfur levels in 2006 and beyond, we do not expect many sulfur credits to be used in future years of this program (since, even with the use of credits, no gasoline may exceed 80 ppm in these years).
We allow an individual refinery that does not meet the 30 ppm standard in a particular year to carry forward the credit debt one year. Under this provision, the refinery will have to make up the credit deficit and come into compliance with the 30 ppm standard the next calendar year, or face penalties. This provision will in no way absolve the refiner from having to meet the
We have some concern that the potential exists for credits to be generated by one party and subsequently purchased or used in good faith by another, and later found to have been calculated or created improperly or otherwise determined to be invalid. For this reason, we proposed that both the seller and purchaser would have to adjust their sulfur calculations to reflect the proper credits and either party (or both) could be deemed in violation of the standards and other requirements if the adjusted calculations demonstrate noncompliance with an applicable standard. One commenter, representing a number of refiners, objected to this approach.
Nevertheless, our strong preference is to hold the credit or allotment seller liable for the violation, as opposed to the credit or allotment purchaser. As a general matter we would expect to enforce a shortfall in compliance calculations (caused by the good faith purchase of invalid credits) against a good faith purchaser only in cases where we are unable to recover valid credits from the seller to cover the compliance shortfall. Moreover, in settlement of such cases we would strongly encourage the seller to purchase credits to cover the good faith purchaser's credit shortfall. Under the deficit provisions of section 80.205(e), for compliance periods through 2010, a credit shortfall may be corrected if the conditions of that section are met. EPA will consider covering a credit deficit through the purchase of valid credits a very important factor in mitigation of any case against a good faith purchaser, whether the purchase of valid credits is made by the seller or by the purchaser.
Some commenters stated that sulfur credits should be transferred directly from the refiner or importer that generated them to the party that will use them, as we had proposed. We believe that this helps to ensure that parties purchasing credits will be better able to assess the likelihood that the credits will be valid, and aids compliance monitoring. Therefore, the final rule adopts this provision, with the exception that where a credit generator transfers credits to a refiner or importer who cannot use all the credits, that transferee may transfer the credits to another refiner or importer. That second transferee cannot again transfer the credits; they must either be used or terminated by the second transferee. Nevertheless, there is nothing in the final rule that would prevent a person who is not a refiner or importer from facilitating the transfer of credits from parties that have generated them to parties who need them for compliance,
The ABT program is designed to encourage sulfur reductions earlier than the standards require, by providing a market for credit generation. The emissions benefits of these early reductions are most valuable in the early years of the ABT program when national average levels remain substantially higher than the final 30 ppm average standard. At the same time, these emissions reductions are offset in time by higher emissions incurred by later vehicles which use gasoline with a higher sulfur level. Because the overall intention of the gasoline sulfur program is to enable and protect Tier 2 vehicles and provide time for refiners to select and construct desulfurization equipment, sulfur credits should have a limited life to limit the degree to which later Tier 2 vehicles are exposed to higher sulfur levels.
The ABT program is also designed to ease implementation of the new standards, particularly the refinery average standard, and the credits will be of their greatest value to refineries during the first few years of the program. ABT is not intended to permit a refinery to operate substantially above the standard for a protracted time period. While limiting credit life may reduce the incentive to generate credits for some refineries, the credit program will be of relatively small value to any refinery/importer that held credits for a protracted period of time and did not need to use them. This is particularly true in 2006 and beyond, when the 80 ppm cap limits the need for and value of any credits the refinery may possess.
Hence, we are finalizing limitations on the life of credits which differ somewhat from our proposal. Credits generated prior to 2004 must be used for compliance purposes and calculations with respect to gasoline produced on or before December 31, 2006. These credits can be used to meet the 30 ppm standard in 2005 or 2006. This expiration date applies to credits used by the refinery which generated the credits, as well as credits transferred to another refinery. While the proposal presented a life through 2007 for credits generated early, we have shortened this life span one year to reflect the fact that early credits are intended to enable and ease compliance with the 30 ppm standard in the first years of the program, allowing refiners to spread out investments without compromising the environmental benefits of the program. At the beginning of 2006, all gasoline (except that produced by small refiners and that marketed in the GPA) will be capped at 80 ppm, and by the end of 2006, every refinery should be capable of producing gasoline that meets the 30 ppm standard. Hence, the value of the early credits diminishes greatly. It should be noted that early credits can be used for GPA certified gasoline through 2006 and for small refiner gasoline through 2007.
Credits generated in 2004 and beyond will have to be used within five years of the year in which they were generated. If these credits are traded to another party during that five year period, they will have to be used by the new owner within that same five years, regardless of when the transfer occurs. This is a change from our proposal, which provided for a potential maximum ten-year life for credits that were generated and then traded in the fifth year to another party. However, we believe this approach is more consistent with our environmental goals of keeping sulfur levels averaging 30 ppm in 2006 and beyond. With the 80 ppm cap, refiners will be able to use only very few credits if they are unable to meet the 30 ppm average in 2006 or beyond. Therefore, limiting credit life to five years will likely have minimal impact on the actual use of credits. A longer credit life will make tracking and enforcement difficult, and could have negative environmental consequences. Hence, we have limited credit life to
A refiner or importer may convert allotments into credits for compliance with the refinery average standards in 2005 and beyond. Allotments that are generated by reducing gasoline sulfur levels to 30 ppm or higher (defined as Type “A” allotments) are equivalent to credits generated in 2000-2003. These allotments may be (1) used as allotments by a refiner for compliance with the corporate average standard in 2004 and 2005 or (2) converted into credits to be used by the refiner's refineries for compliance with the refinery average standard in 2005 and 2006.
Allotments that are generated by reducing gasoline sulfur levels to lower than 30 ppm (defined as Type “B” allotments) are equivalent to credits generated in 2004 and beyond (by producing gasoline with less than 30 ppm sulfur). Similar to Type “A” allotments, these allotments may be (1) used as allotments by a refiner for compliance with the corporate average standard in 2004 and 2005 or (2) converted into credits to be used by the refiner's refineries for compliance with the refinery average standard in 2005 and beyond.
Allotments or credits that are used by refiners for compliance with the GPA gasoline standards must be used by the last day of February 2007. Allotments or credits used by small refiners for compliance with the small refiner standards must be used by the last day of February 2008. Any allotments, whether Type “A” or “B”, that are carried over for compliance with the corporate and refinery average standards for 2005 must be discounted by 50 percent as discussed in above. Any allotments that are converted to credits (
Section 211(c)(4)(A) of the CAA prohibits states
We are adopting the sulfur standards pursuant to our authority under section 211(c)(1). Thus, we believe that today's action results in the clear preemption of future state actions to prescribe or enforce fuel sulfur controls.
Section 211(c)(4)(A) preempts state fuel controls if EPA has “prescribed” federal controls. We read this language to preempt non-identical state standards on the date of promulgation of the standards, as opposed to the date the standards become enforceable. Thus, today's action preempts state actions as of December 21, 1999, even though the standards will not require sulfur reductions until 2004. This interpretation is consistent with EPA actions applying other federal fuel measures.
Aside from the explicit preemption in Section 211(c)(4)(A), a court could also consider whether a state sulfur control is implicitly preempted under the Supremacy Clause of the U.S. Constitution. Courts have determined that a state law is preempted by federal law where the state requirement actually conflicts with federal law by preventing compliance with both federal and state requirements, or by standing as an obstacle to accomplishment of Congressional objectives. A court could thus consider whether a given state sulfur control is preempted, notwithstanding waiver of preemption under 211(c)(4)(C), if it places such significant cost and investment burdens on refiners that refiners cannot meet both state and federal requirements in time, or if the state control would otherwise meet the criteria for conflict preemption.
This section describes various provisions for certain qualifying refiners who may face hardship circumstances.
In developing our gasoline sulfur program, we evaluated the need and the ability of refiners to meet the 30/80 standards as expeditiously as possible. This analysis is described in detail in the RIA. As a part of this analysis, we found that while the majority of refiners would be able to meet the needed air quality goals in the 2004-2006 time frame, there would be some refiners who would face particularly difficult circumstances which would cause them to have more difficulty, in comparison
In order to ensure that the vast majority of the program could be implemented reasonably quickly in order to achieve the air quality benefits sooner, rather than basing the time frame on the lowest common denominator we have provided an extended phase-in for a small group of refiners that represents less than four percent of the overall gasoline volume, and a much smaller percentage in the areas of greatest environmental need. As described in more detail below, and in Chapter VIII of the RIA, we concluded that refineries owned by small businesses face unique hardship circumstances, compared to larger companies.
The primary reason for this consideration is that small businesses lack the resources available to large companies which enable the large companies (including those large companies that own small volume refineries) to raise capital for investing in desulfurization equipment. The small businesses are also likely to have insufficient time to secure loans, compete for engineering resources, and complete construction of the needed desulfurization equipment in time to meet the standards adopted today which begin in 2004.
The emissions benefits of low sulfur gasoline are needed as soon as possible, for two primary reasons: (1) To reduce ozone and other harmful air pollutants, and (2) to enable vehicle emissions control technology for Tier 2 vehicles. Since our analysis showed that small businesses in particular face hardship circumstances, we are adopting temporary, interim standards that will provide refineries owned by small businesses additional time to meet the ultimate 30 ppm refinery average and 80 ppm per gallon cap standards. This approach allows us to achieve the needed emission reductions in the 2004-2007 time frame because hardship circumstances are expected to be faced by only a small portion of the refining industry.
We believe that these temporary, interim standards are an effective way to phase in the low sulfur standards as expeditiously as is feasible thereby achieving significant air quality benefits in an expeditious manner. This section describes the special provisions we are offering small businesses to mitigate the impacts of our program on them and generally explains the process we undertook to analyze those impacts. Please refer to the RTC document for a detailed discussion of comments received on these provisions, and to the RIA for a more detailed discussion of our analysis of small refiner circumstances.
As explained in the regulatory flexibility analysis in Section VIII.B. of this document and in Chapter 8 of the RIA, we considered the impacts of our proposed regulations on small businesses. We have historically, as a matter of practice, considered the potential impacts of our regulations on small businesses, as discussed in more detail in Section IV.C.2.a.ii., below. The analysis of small business impacts conducted for this rulemaking was performed in conjunction with a Small Business Advocacy Review (SBAR) Panel we convened, pursuant to the Regulatory Flexibility Act as amended by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA). We believe that the temporary, interim standards we are adopting for small refiners contributed to our development of a framework to achieve significant environmental benefits from lower sulfur gasoline in the most expeditious manner that is reasonably practicable. In the SBREFA amendments, Congress stated that “uniform Federal regulatory * * * requirements have in numerous instances imposed unnecessary and disproportionately burdensome demands including legal, accounting, and consulting costs upon small businesses * * * with limited resources[,]” and directed agencies to consider the impacts of certain actions on small entities. The final report of the Panel is available in the docket. Through the SBREFA process, the Panel provided information and recommendations regarding:
• The significant economic impact of the proposed rule on small entities;
• Any significant alternatives to the proposed rule which would ensure that the objectives of the proposal were accomplished while minimizing the economic impact of the proposed rule on small entities;
• The projected reporting, recordkeeping, and other compliance requirements of the proposed rule; and,
• Other relevant federal rules that may duplicate, overlap, or conflict with the proposed rule.
In addition to our participation in the SBREFA process, we conducted our own outreach, fact-finding, and analysis of the potential impacts of our regulations on small businesses. Many of the small refiners with whom we and the Panel met indicated their belief that their businesses may close due to the substantial costs, capital and other, of meeting the 30/80 standard without additional time. Based on these discussions and our data analysis, the Panel and we agree that small refiners would likely experience a significant and disproportionate economic hardship in reaching the objectives of our gasoline sulfur reduction program. However, the Panel also noted that the undue burden imposed upon the small refiners by our sulfur requirements could be alleviated with additional time for compliance. We agree with the Panel on both of these points.
For today's action, we have structured a temporary, interim compliance flexibility for qualifying small refiners, both domestic and foreign, based on the factors described below. Specifically, we structured this provision to address small refiner hardship while achieving air quality benefits expeditiously and ensuring that the reductions needed in gasoline sulfur coincide with the introduction of Tier 2 vehicles.
First, the compliance deadlines in the program, combined with flexibility for small refiners, will achieve the air quality benefits of the program quickly, while ensuring that small refiners will have adequate time to raise capital for infrastructure changes. Many, if not most, small refiners have limited, if any, additional sources of income beyond their refinery for financing the equipment necessary to produce low sulfur gasoline. Because these small refiners typically do not have the financial backing that larger and generally more integrated companies have, they need additional time to secure capital financing from their lenders.
Second, we believe that allowing time for sulfur-reduction technologies to be proven-out by larger refiners before small refiners have to put them in place would reduce the risks incurred by small refiners who utilize these technologies to meet the standards. The added time would likely allow for costs of these desulfurization units to decrease, thereby limiting the economic consequences for small refiners. Small refiners are disadvantaged by the economies of scale that exist for the larger refining companies—capital costs and per-barrel fixed operating costs are generally higher for them.
Finally, providing small refiners more time to comply would ensure that adequate engineering and construction resources would be available. Since most large and small refiners will need to install additional processing equipment to meet the sulfur requirements, there will be a tremendous amount of competition for technology services, engineering manpower, and construction management and labor. Our analysis
Providing this flexibility to allow small refiners to deal with hardship circumstances enables us to go forward with the phase-in of the 30 ppm sulfur standard beginning in 2004. Without this flexibility, it is possible that the benefits of the 30 ppm standard would not be achieved as quickly. By providing temporary relief to those refiners that need additional time, we are able to adopt a program that reduces gasoline sulfur levels expeditiously and in a way that is feasible for the industry as a whole.
In addition, we believe the volume of gasoline that will be eligible for the interim standards is small. We estimate that small refiners produce approximately four percent of all gasoline used in the U.S., excluding California. In most cases, gasoline produced by refiners is mixed with substantial amounts of other gasoline prior to retail distribution (due to the nature of the gasoline distribution system). This mixing generally results in only marginal increases in overall sulfur levels. Thus, the sulfur level of gasoline actually used by Tier 2 vehicles should generally be much lower than that produced by individual small refineries under this provision.
In identifying the small refiners most susceptible to the economic challenge of meeting the low-sulfur requirements, we closely examined the Small Business Administration's (SBA) definition of small refiner for the purposes of regulation. In that assessment we concluded that the SBA definition provided a reasonable metric for identifying small refiners that would be significantly impacted by the sulfur program requirements. By adopting the SBA definition we could expeditiously provide certainty of small refiner status to refiners who applied for the temporary compliance flexibility. Specifically, we proposed a definition where any petroleum refining company having no more than 1,500 employees throughout the corporation as of January 1, 1999 could apply for the temporary compliance flexibilities. This proposed employee limit included any subsidiaries, regardless of the number of individual gasoline-producing refineries owned by the company or the number of employees at any given refinery.
While we proposed a definition based on corporate employment, in light of the SBA definition and the SBAR Panel's recommendations, we also sought comment on alternative definitions of a small refiner. Such alternatives included definitions based on volume of crude oil processed (at a given refinery and/or corporate-wide) or volume of gasoline produced, with the understanding that any relief offered to refiners must not substantially reduce the program's environmental benefits.
Based on comments received on the proposal, we are making two changes to our definition of a small refiner: we are (1) revising the employee number criterion; and, (2) adopting a cap on the corporate crude oil capacity for a refining company to qualify as a small business under today's regulations.
In regard to the employee number criterion, we are modifying how the employee number is determined, based on comments received from SBA. As mentioned above, our proposed definition applied to any petroleum refining company having no more than 1,500 employees throughout the corporation as of January 1, 1999. We selected that date to prevent companies from “gaming” the system. However, as SBA pointed out in its comments, the Small Business Act regulations specify that, where the number of employees is used as a size standard, as we proposed for small refiners, size determination is based on the average number of employees for all pay periods during the preceding 12 months.
Since we intended to use SBA's size standard in our proposal, we are incorporating that definition correctly in today's action. It is also worth mentioning that SBA shares our concerns about preventing companies from gaming the system and that it solved this problem specifically by using the average employment over 12 months. In effect, this approach helps to prevent companies from applying for and receiving small refiner status in bad faith. An example of an inappropriate application for small refiner status would be a refiner that temporarily reduced its workforce from 1600 employees to 1495 employees immediately before January 1, 1999 and then immediately rehired those employees after that cutoff date. Furthermore, the averaging concept was designed to properly address firms with seasonal fluctuations, according to SBA.
Second, we're amending the small refiner definition to include a corporate crude oil capacity cap. We believe such a corporate volume limitation is necessary to ensure that only truly small businesses benefit from the relaxed interim standards. Refineries that process large amounts of crude are likely to be better able to install desulfurization equipment to meet the national standards in 2004. In addition to ensuring that the interim standards target the appropriate group of refiners that need additional time, the volume limit also serves to ensure that the volume of gasoline subject to such standards is not significant. In addition, we received many comments that we should adopt a threshold based on crude capacity as specified in the Clean Air Act and used in past EPA fuel programs.
In the lead phase-down program for gasoline, we used a definition of “small refinery” that Congress adopted in 1977 specifically for the lead phase-down program. The definition was based on crude oil or feedstock capacity at a particular refinery (less than or equal to 50,000 barrels per calendar day (bpcd)), combined with total crude oil or feed stock capacity of the refiner that owned the refinery (less than or equal to 137,500 bpcd). In 1990, the lead phase-down program was complete and Congress removed this provision from the Act.
Shortly before the Act was amended in 1990, we set standards for sulfur content in diesel fuel, including a two-year delay for small refineries. We used the same definition of small refinery as we used in the lead phase-down program. This two-year delay, like many of the small business flexibilities in our gasoline sulfur proposal, was aimed at problems that small refineries faced in raising capital and in arranging for refinery construction.
In the 1990 amendments to the Clean Air Act, Congress rejected this small refinery provision, and instead allocated allowances to small diesel refineries under the Title IV Acid Rain program. (See CAA Section 410(h).) This approach was also aimed at helping small refineries solve the problem of raising the capital needed to make investments to reduce diesel sulfur. Congress provided allowances to small refineries that met criteria similar to that used in the lead phase-down provision—based on the crude oil throughput at a particular refinery, combined with the total crude oil throughput of the refiner that owned the refinery.
As mentioned above, the CAA definition was based on crude oil or feedstock capacity at a particular refinery, combined with total crude oil
Therefore, in consideration of the above, a refiner must meet both of the following criteria to qualify for the special small refiner provisions described in the next section:
• No more than 1500 employees corporate-wide, based on the average number of employees for all pay periods from January 1, 1998 to January 1, 1999; and
• A corporate crude capacity less than or equal to 155,000 bpcd for 1998.
Upon careful review of the comments received on the proposal as well as the recommendations of the SBAR Panel, we have determined that regulatory relief in the form of delayed compliance dates is appropriate to allow small refiners, both foreign and domestic, to comply with our regulations without disproportionate burdens. From 2004 to 2007, when U.S. refiners must meet the 30/80 standard or the standards listed in Table IV.C-1 if they are participating in our ABT program, refiners meeting the corporate employee and capacity limits prescribed above are allowed to comply with somewhat less stringent requirements. These interim annual-average standards for qualifying small refiners are shown in Table IV.C-3 below.
The cap standards for the first two “bins” of refineries (that is those with baseline sulfur levels from zero to 30 and 31 to 200) have been relaxed somewhat from the proposal based on comments that the proposed standards for these two bins were more stringent than the options under discussion for all other refiners. We believe that these small refiners should be able to meet the average standards without much, if any, change to their operations but the more lenient cap will give them some flexibility for turnarounds or unexpected equipment “upsets”.
Compliance with the standards in Table IV.C-3 is based on a refiner's demonstration that it meets our specific small refiner criteria. Refiners who qualify as a small refiner under our definition must establish a sulfur baseline for each of their participating refineries. The following sections explain these requirements in more detail to supplement the information presented above. We also explain how small refiners can apply for an extension of up to two additional years of the applicable small refiner standards, based on a variety of factors such as technology availability or financial hardship.
Refiners seeking small refiner status under our gasoline sulfur program must apply to us in writing no later than December 31, 2000, requesting this status. This application for small refiner status must contain the information described below.
Companies
• A listing of the name and address of each location where any employee of the company worked during the 12 months preceding January 1, 1999.
• The average number of employees at each location based upon the number of employees for each of the company's pay periods for the 12 months preceding January 1, 1999.
• The type of business activities carried out at each location.
• The total corporate crude oil capacity of the refiner as reported to the Energy Information Administration (EIA) of the U.S. Department of Energy (DOE).
For refineries owned by joint ventures, the total employment of both (all) companies must be considered in determining whether the 1,500 employee limit is met. In addition, a refiner who reactivates a refinery that was shut down or non-operational between January 1, 1998 and January 1, 1999, may apply for small refiner status no later than June 1, 2002. In this case, we will consider the information provided to determine the correct period for judging compliance with the 1500 threshold. Where appropriate we will look at the most recent 12 months of employment information.
Refiners seeking small refiner status must also provide us with the total crude capacity of their corporation (the sum of all individual refinery capacities for multiple-refinery companies, including any and all subsidiaries) as reported to EIA for 1998 (published by EIA in 1999). The information submitted to EIA is presumed to be correct. However, in cases where a company disputes this information, we will allow 60 days after the company submits its application for small refiner status for that company to petition the Agency with the appropriate data to correct the record. For reactivated refineries owned by a small refiner, we will consider the information provided to determine the correct period for judging compliance with the corporate capacity threshold. Where appropriate, we will look at the most recent year of crude capacity information.
If a refiner with approved small refiner status later exceeds the 1,500 employee threshold without merger or acquisition or the corporate capacity of 155,000 bpcd, its refineries could keep their individual refinery standards. This is to avoid stifling normal company growth and is subject to our finding that the company did not apply for and receive the small refiner status in bad faith.
A qualifying small refiner, domestic or foreign, may apply for an individual sulfur baseline by December 31, 2000 for any refinery owned by the company by providing the following information:
• A calculation of the refinery's sulfur baseline using its average gasoline sulfur level based on 1997 and 1998 production data,
• The average volume of gasoline (including conventional and reformulated) produced in these two years.
As we proposed, baseline sulfur levels and gasoline volumes are averaged over two years (1997 and 1998) to account for any production-related anomalies that may have occurred in 1997 or 1998. For the overall program, however, we are only using 1997 and 1998 data for the reasons described in Section IV.C.1, above. For any refiner who reactivates a refinery that was shut down or non-operational between January 1, 1998 and January 1, 1999, we will use the most recent information available for baseline establishment purposes.
The regulations specify the information to be submitted to support the baseline application. The baseline calculations should include any oxygen added to the gasoline at the refinery. This application would be submitted at the same time the refiner applies for small business status; confirmation of small business status would not be required to apply for an individual sulfur baseline. Pending refinery baseline approval, we will assign standards to each of the company's refineries in accordance with Table IV.C.-3.
Oxygenate blenders, regardless of their size, are not eligible for the small refiner individual baselines and standards because they would not experience circumstances similar to those of small refining companies. That is, oxygenate blenders do not have the burden of capital costs to install desulfurization equipment, which is the primary reason for allowing small refiners to have a relaxed compliance schedule.
Except as noted below, the volume of gasoline subject to a small refinery's individual standards is limited to the average volume of gasoline the refinery produced from crude oil during the baseline years (1997 and 1998), excluding the volume of gasoline produced using blendstocks produced at another refinery and exports.
However, to ensure that the overall sulfur in gasoline from small refiners does not greatly increase under the terms of the small refiner extension and result in overall gasoline pool sulfur levels higher than anticipated, the volume would be limited beginning in 2004 to the volume of gasoline that is the lesser of: (1) 105 percent of the baseline volume, or (2) the volume of gasoline produced during the year from crude oil. Any volume of gasoline produced during an averaging period in excess of this limitation is subject to the corporate average standards that apply to all other refiners (
In 2006 and 2007, the refinery averages of Table IV.C.-1 will apply. In this case, the small refinery's annual average standard will be adjusted based on the excess volume in a manner similar to the compliance baseline equation for conventional gasoline under Section 80.101(f) of Part 40 of the Code of Federal Regulations. However, the small refinery's per-gallon cap standard will not be adjusted.
This limitation assures that small refineries receive relief only for gasoline produced from crude oil, that is the portion of the refinery operation requiring capital investment to meet lower sulfur standards.
Beginning January 1, 2008, all small companies' refineries must meet the national sulfur standard of 30 ppm on average and the 80 ppm cap, except small refineries under IV.C.2.i. that apply for and receive an extension of their small refiner status and unique standards. An extension will provide a given small refinery up to an additional two years to comply with the national standards. An extension must be requested in writing and must specify the factors that demonstrate a significant economic hardship to qualify the refinery for such an extension. Factors considered for an extension could include, but are not limited to, the refinery's financial position; its efforts to procure necessary equipment and to obtain design and engineering services and construction contractors; the availability of desulfurization equipment, and any other relevant factors.
In order for us to consider an extension, a refiner must submit a detailed request for an extension by January 1, 2007, demonstrating that it has made best efforts to obtain necessary financing, and must provide detailed information regarding any lack of success in obtaining financing. This information shall include, but may not be limited to copies of loan applications for the necessary financing for the construction of appropriate sulfur reduction technology as well as the application of financing for other equipment procurements or improvements in this time frame. If financing has been disapproved or is otherwise unsuccessful, the refiner shall provide documents supporting the basis for that disapproval and evidence of efforts to pursue other means of financing. If we determine that the refiner has made the best efforts possible to achieve compliance with the national standards by January 1, 2008, but has been unsuccessful for reasons beyond its control, we will consider granting the hardship extension initially for the 2008 averaging period. If further relief is appropriate for good reasons, we will consider a further extension through the 2009 averaging period but in no case will this relief be provided unless the refiner can demonstrate conclusively that it has financing in place and that it will be able to complete construction and meet the national gasoline sulfur standards no later than December 31, 2009.
This final rule includes a compliance plan provision for those refiners who may seek a hardship extension of their approved interim standards. This provision requires that those refiners with approved interim standards who seek a hardship extension must submit a series of reports to EPA discussing and describing their progress toward producing gasoline that meets the 30/80 ppm standards by January 1, 2008. We expect that small refiners will need to begin preparations to meet the national standards in 2008 by 2004. However, we understand that the potential exists for some small refiners to face additional hardship circumstances that will warrant more time to meet the standards. For this reason, we have adopted provisions (see above) allowing
By June 1, 2004, such refiners would need to submit preliminary information in the form of a report outlining its time line for compliance and a project plan discussing areas such as permits, engineering plans (
By no later than June 1, 2005, these small refiners would need to submit a report to us stating in detail progress to date based on their time line and project plan. This should include copies of approved permits for construction of the equipment, contracts for design and construction, and any available evidence of having secured the necessary financing to complete the required construction. If any difficulties in meeting this requirement are anticipated, the refiner must submit a detailed report of all efforts to date and the factors that may cause delay, including costs, specification of engineering or other design work still needed and reasons for delay, specification of equipment needed and any reasons for delay, potential equipment suppliers and history of negotiations, and any other relevant information. If unavailability of equipment is a factor, the report must include a discussion of other options considered, and the reasons these other options are not feasible.
In addition, the small refiner would need to provide evidence by June 1, 2006, that on-site construction has begun at its refinery(s) and that absent unforeseen circumstances or problems, they will be producing complying gasoline (30/80 ppm) by January 1, 2008. While the submission of these progress reports is evidence of a refiner's good faith efforts to comply by 2008, it does not bind the refiner to make gasoline in 2008. There are several reasons why a refiner may choose to exit the gasoline-production business in 2008 that go beyond the low sulfur gasoline requirement.
As a result of a refiner's efforts in moving toward compliance with the 2008 standards, for market, economic, business, or technical reasons, the company could choose not to make gasoline in 2008. Although we do not believe this will be the likely outcome for small refiners, we cannot preclude it. Any refiner that makes such a determination in its progress reports will have until 2008 to transition out of gasoline production, but will not be considered for a extension of hardship relief.
As described in IV.C.1.c.i above, any refinery (including those owned by small refiners) can generate sulfur allotments (in ppm-gallons) in 2003 by producing gasoline containing less than 60 ppm sulfur on an annual-average basis. Once this 60 ppm trigger is reached, allotments will be calculated based on the amount of reduction from 120 ppm
During the period 2000-2003, refineries owned by small refiners can also generate credits by producing gasoline averaging at least 10 percent lower than that refinery's baseline sulfur level. In other words, to generate credits, the refinery's annual average sulfur level for all of its gasoline on average must be 0.9 × (baseline sulfur level). Once this “trigger” is reached, credits will be calculated based on the amount of reduction from the refinery's sulfur baseline. For example, if in 2002 a refinery reduced its annual average sulfur level from a baseline of 450 ppm to 150 ppm (well below the trigger of 0.9 × 450 = 405 ppm), its sulfur credits would be determined based on the difference in annual sulfur level (450—150 = 300 ppm) multiplied by the volume of gasoline produced in 2002. Similarly, small foreign refiner-owned refineries with an individual sulfur baseline can generate credits in these years as long as the annual average sulfur level of the gasoline exported to the U.S. from that refinery is lower than 90 percent of the baseline sulfur level.
During the period 2004-2007, refineries owned by small refiners will be permitted to generate credits but only if their actual annual sulfur level of all gasoline produced or imported averages below their refinery standard, and only for the difference between the standard and the actual annual sulfur average.
A refinery (owned by a small refiner) wishing to participate in the ABT program can sell credits beginning as soon as January 1, 2000 but may wait until December 31, 2000 to apply for small refiner status. However, the standards assigned to that refinery (as presented in Table IV.C-3 above) will be based on the sulfur level from which credits were generated, not the baseline sulfur level, since the refiner would have already demonstrated the ability to meet the lower sulfur level. For compliance purposes and to give refineries certainty regarding the gasoline sulfur standards to which they will be held during 2004-2007, the standards for a small refiner refinery participating in ABT will be set based on the refinery's lowest sulfur average for any year between 1999 and 2003.
Using the example above, a refinery (owned by a refiner with small refiner status) with a 1997-98 baseline sulfur level of 450 ppm would have an interim average standard of 450/2 = 225 ppm and a cap of 225 × 1.5 = 338 ppm. If that refinery generated 300 sulfur credits in 2002 by producing gasoline with 150 ppm sulfur, then that refinery's average sulfur standard for 2004-2007 would be ratcheted down to 150 ppm with a cap of 300 ppm. However, that refinery would still be able to use the 300 credits that it had generated and banked in 2002 for compliance with its 150 ppm standard.
Based on the comments received on our proposal, we are allowing small refineries to use credits and/or allotments that they generated and/or to purchase credits and/or allotments from another refinery to meet their average standard during 2004-2007. We solicited comment on whether small refiners subject to the interim standards should be permitted to use credits towards meeting those standards, and several small refiners who already produce very clean gasoline commented that the special small refiner standards do not benefit them in any way. These refiners argued that if they could generate sufficient sulfur credits in 2000-2003, or could obtain such credits
At any time, a small refiner can choose to “opt out” of the small refiner program and, beginning the next calendar year, comply with the standards in Table IV.C-2. The refiner would have to notify us of this change in its compliance program. Once a small refiner leaves the small refiner program, however, it would not be eligible to re-enter the small refiner program.
In the final rule, EPA is adopting a provision permitting refiners to seek a temporary waiver from the sulfur standards in certain circumstances. Such waivers will be granted at EPA's discretion. Under this provision a refiner may seek permission to distribute gasoline that does not meet the applicable low sulfur standards for a brief time period, based on the refiner's inability to produce complying gasoline because of extreme and unusual circumstances outside the refiner's control that could not have been avoided through the exercise of due diligence. This provision is similar to a provision in EPA's RFG regulations, and is intended to provide refiners short-term relief in unanticipated circumstances such as an accidental refinery fire or a natural disaster. The short-term waiver provision is intended to address unanticipated circumstances that cannot be reasonably foreseen at this time or in the near future
The conditions for obtaining such a waiver that are similar to those in the RFG regulations. These conditions are necessary and appropriate to ensure that any waivers that are granted are limited in scope, and that refiners do not gain economic benefits from a waiver. Therefore, refiners seeking a waiver must show that the waiver is in the public interest, that the refiner was not able to avoid the nonconformity, that it will make up the air quality detriment associated with the waiver, as well as any economic benefit from the waiver, and that it will meet the applicable sulfur standards as expeditiously as possible.
In addition to the provision for short-term relief in unanticipated circumstances, we are adopting a provision for relief based on extreme hardship circumstances. In developing our sulfur program, we considered whether any refiners would face particular difficulty in complying with the standards in the lead time provided. As described in Section IV.C.2.a., we concluded that refineries owned by small businesses would experience more difficulty in complying with the standards on time because, as a group, they have less ability to raise capital necessary for refinery investments, face proportionately higher costs because of economies of scale, and are less able to successfully compete for limited engineering and construction resources. However, it is possible that other refiners who do not meet our criteria for the interim standards also face particular difficulty in complying with the sulfur standards on time. Therefore, we are including in the final rule a provision allowing us, at our discretion, to grant temporary waivers from the sulfur standards based on a showing of extreme hardship circumstances. We do not anticipate, nor do we expect there is a need for, granting temporary waivers that apply to more than approximately one percent of the national gasoline pool in any given year. This provision would allow refiners (domestic and foreign) to request a waiver from the sulfur standards based on a showing of unusual circumstances that result in extreme hardship and significantly affect the ability to comply by the applicable date. As with the small refiner interim standards, this provision furthers our overall environmental goals of achieving low sulfur gasoline nationwide as soon as possible. By providing short-term relief to those refiners that need additional time because they face hardship circumstances, we can adopt a program that reduces gasoline sulfur beginning in 2004 for the majority of the industry that can comply by then.
As described above, EPA understands that this program will require significant economic investments by the refining industry. We have adopted a program with sufficient flexibilities (including an ABT program, allotment trading, a geographic phase-in, and interim standards for qualifying small refiners) to make these investments reasonable and feasible over the time frame in which the standards are phased in. Because the refining industry encompasses a wide variety of individual circumstances, and our program phases in based on the lead time we believe is reasonable for the industry as a whole, there may be unusual circumstances that impose extreme hardship and significantly affect an individual refinery's ability to comply in the lead time provided. However, we do not intend for this waiver provision to encourage refiners to delay planning and investments they would otherwise make in anticipation of receiving relief from the applicable requirements. In addition, we want to limit the environmental impact of any hardship waivers from compliance with the standards. Thus, we anticipate that hardship waivers will only be granted in rare circumstances.
Because of the significant environmental benefits of lowering sulfur in gasoline, we will administer this provision in a manner consistent with continuing to ensure the environmental objectives of the regulation. In our analysis of the interim small refiner standards, we concluded that only a minimal portion of the national gasoline pool would potentially be impacted by the less stringent interim standards, due to the relatively small production volume of these facilities. To limit the potential environmental impact of this hardship provision, we reserve the discretion to deny applications where we find that granting a waiver would result in an unacceptable environmental impact. While this determination will be made on a case-by-case basis, we do not expect there is a need for, nor do we anticipate, granting waivers that apply to more than approximately one percent of the total national pool of gasoline in any given year, or to more than a minimal percentage of the gasoline supply of an area known to have significant air quality problems.
There are several factors we will consider in evaluating a petition for additional time to comply. This could include refinery configuration, severe economic limitations, and other factors that prevent compliance in the lead time provided. Applications for a waiver must include information that will allow us to evaluate all appropriate factors. EPA will consider whether the refinery configuration or operation is unique or atypical, how much of a refinery's gasoline is produced using an FCC unit, its hydrotreating capacity relative to its total crude capacity, total reformer unit throughput capacity relative to total production, gasoline
This provision is intended to address unusual circumstances that we expect will be foreseeable now or in the immediate future, such as unique and atypical gasoline refinery operations or a demonstrated inability to raise capital. These kinds of circumstances should be apparent at this time or in the near future, so refiners seeking additional time under this provision must apply for relief by September 1, 2000. A refiner seeking a waiver must show that unusual circumstances exist that impose extreme hardship and significantly affect its ability to meet the standards on time, and that it has made best efforts to comply with the standards, including efforts to obtain credits and/or allotments towards compliance. Applicants for a hardship waiver must also submit a plan demonstrating how the standards will be achieved as expeditiously as possible. In submitting the plan, it must include a timetable for obtaining the necessary capital, contracting for engineering and construction resources, and obtaining permits. EPA will review and act on applications, and, if a waiver is granted, will specify a time period, not to extend beyond January 1, 2008 (the date by which all gasoline is expected to meet the 30 ppm refinery average and 80 ppm per gallon cap standards), for the waiver.
If a waiver is granted, EPA will impose as a condition of the waiver other reasonable requirements, including antibacksliding requirements to ensure no deterioration in the sulfur level of gasoline and interim sulfur standards that the refiner must meet. This is appropriate since some refiners who may qualify for a waiver can achieve some sulfur reductions, and even reductions to levels above 30 ppm will result in some environmental benefits. While this provision allows EPA to waive the per gallon standards as well as the average standards, EPA would not allow gasoline sulfur to exceed the highest per gallon cap applicable to a refiner under the interim small refiner standards described in Section IV.C.2. Once all applications have been received, EPA will consider the appropriate process to follow in reviewing and acting on applications, including whether to conduct a notice and comment decision-making process.
Industry commenters expressed concern over the ability to obtain permits to construct and operate the facility modifications needed to meet the Tier 2 rule requirements by the end of 2004. As part of the preamble to the proposed rule, we outlined possible approaches to provide greater certainty and to expedite potentially applicable permit processes. In general, we solicited comments on whether and how policy options might be designed so as to exempt Tier 2 projects from major New Source Review (NSR) and/or to expedite the processing of permits where such requirements would apply. In particular, we solicited comment on whether the major NSR process could be expedited if: (1) EPA provided guidance on Lowest Achievable Emission Rate (LAER) requirements or Best Available Control Technology (BACT) determinations; (2) emissions reductions could be made available or designated for offsetting Tier 2 activities; (3) EPA developed model permits, or (4) EPA assisted the States in resolving source-specific permitting issues as they would arise. The Agency also solicited comments on how the title V operating permit requirements, where applicable, might need to be integrated with the relevant NSR process.
In proposing various mechanisms to expedite the permitting of Tier 2 projects, we recognized that a combination of measures might be needed, since the situations could vary widely among individual refineries due to differences in such factors as available equipment capacity, amount of sulfur in the crude oil, and applicable State regulations. Source-specific analyses are also necessary to establish what sulfur reduction techniques can be applied, to determine the applicable permitting requirements, and to evaluate what controls will be necessary as a result of these requirements. We indicated our intent to offer assistance where needed.
The most significant comments received on the proposal concerning the timing impacts due to air permit requirements are presented below. These commenters focused exclusively on the requirements to obtain a preconstruction permit under the NSR program. Generally, commenters only concerns regarding the title V operating permit program were that the States' ongoing efforts to issue these permits might create a backlog which could delay the issuance of NSR permits for Tier 2 projects. A more detailed discussion of comments received on the proposal and EPA's response are contained in the Response To Comments document and is filed in the Docket for this action.
We received written and oral comments from refineries about the permit requirements associated with Tier 2 projects. Refiners emphasized the need for certainty. They pointed out the need to secure preconstruction permits within 18 months (
Based on the comments and other information received in response to the proposal, EPA believes that it is not necessary or appropriate to explore further the development of possible options which would exempt Tier 2 projects from the normally applicable preconstruction review process. This position is supported by: (1) The comments of States that industry can, in general, apply and receive NSR permits in time to comply with Tier 2; and (2) the recognition of industry's potential ability to use emissions reductions to net Tier 2 projects out of major NSR which would otherwise be applicable. Nonetheless, we believe that actions
First, as previously discussed, we have structured the final gasoline sulfur program to allow additional lead time for many refiners (i.e., certain refineries would be able to make desulfurization changes later than the proposed 2004 compliance date to meet Tier 2 requirements). This approach will help address the concerns over the availability of necessary new equipment and permitting backlogs caused by many refineries acting to obtain permits and order equipment within relatively the same time period.
Second, we intend to take several actions (described in more detail below) to expedite and impart greater certainty in obtaining necessary major NSR permits. As a result of comments received on the proposal, and the lead time provided in the final gasoline sulfur program, we believe that the vast majority of permits can be issued within the necessary time frames, provided that refineries submit their preconstruction applications in a timely manner and regulatory authorities prioritize the issuance of these permits. We also intend to assist States and refiners on a case-by-case basis in their efforts to address any unique permitting problems that might arise and, thus, remedy potential problems that could cause unanticipated delays. In the unlikely event permitting delays occur, EPA will work with refiners and the state/local permitting agencies on a case-by-case basis, where a refinery has unique circumstances that necessitate unique treatment.
While today's strategy will help expedite the permitting process, refineries that trigger major NSR as a result of producing low sulfur gasoline will still have to install the stringent level of emissions control technology required by the Act. However, we intend to issue guidance to assist states in making decisions about the levels of control technology, as described more below. In addition, the Agency wishes to clarify that, in our efforts to provide greater certainty and to facilitate more expeditious permitting, we are in no way shortcutting existing opportunities for public participation. We recognize the importance of public participation in making permitting decisions and intend that the measures adopted to address permitting concerns will not diminish the opportunities for public participation.
The major NSR program, as it applies to existing major stationary sources of air pollution, requires that a preconstruction permit be issued before a source makes a physical change or change in its method of operation of any project that would result in a significant net emissions increase. As described in the proposal, the steps taken by certain refineries to implement gasoline sulfur reductions to meet today's rule could result in emissions increases in one or more pollutants which may trigger the requirements for this type of preconstruction permit. A number of the refineries are located in areas designated as nonattainment for at least one pollutant. The nonattainment NSR requirements pursuant to part D of the Act would apply to any such refinery undergoing a major modification. For those refineries located in attainment or unclassifiable areas, permit requirements for the prevention of significant deterioration (PSD) of air quality must be met for major modifications.
The EPA recognizes the importance of timely major NSR (as applicable) permit actions for refineries to proceed with necessary changes to meet the new low sulfur gasoline standard. We encourage refineries to begin discussions with permitting authorities and to submit permit applications—as early as possible. In addition, based on comments received, we believe that there are a few key areas in which assistance would be useful toward helping States issue timely permits to the applicable refineries:
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Refineries subject to major NSR review will be required to undergo a source-specific evaluation to apply either BACT or LAER, depending upon the applicable program requirements. For example, the evaluation for BACT is case-by-case and takes into account the alternative technologies available to control pollution from a particular emissions unit or process, and considers the energy, environmental, economic and other costs associated with each technology. We intend to issue guidance setting out a level of emissions that, in our view, would be expected to satisfy the requirements for BACT for certain emissions units associated with refinery desulfurization projects. While States would not be required to use the results to establish BACT for a particular refinery subject to review and EPA's guidance on a control technology may not be appropriate where there exists unusual site-specific circumstances, such guidance would add the certainty of EPA's expectations.
Since negotiation of an appropriate BACT level often is one of the most time consuming aspects of permitting, we believe this EPA guidance will significantly expedite the process. The federal guidance on BACT, by including an evaluation of the most stringent control levels currently being achieved or required, will also provide federal guidance on LAER. The EPA plans to make a draft of this guidance available for public review and comment in January 2000. Final guidance would then be prepared, after relevant comments are considered, in time for States, refiners, and the public to consider in preparing and reviewing permit applications and proposed permits.
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Refineries located in nonattainment areas must offset any proposed significant emissions increases with an equal or greater amount of emissions reductions from other sources, usually coming from within the same nonattainment area. We believe that vehicle emissions reductions resulting from the use of low sulfur gasoline can be used as offsets for the refineries, as long as the statutory and regulatory criteria for creditable offsets are satisfied and States decide to provide for this opportunity in their SIP attainment demonstration. We believe generally that this option should be available to States since only a small fraction of the total vehicle emissions reductions in any county would be needed to offset refinery emissions increases resulting from implementation of gasoline desulfurization projects. Generally, the reductions must also occur in the same nonattainment area as the location of the refinery for which the offsets are required. The EPA plans to issue the appropriate guidance early in the year 2000 to help a State to determine whether and to what extent it may wish to use vehicle emissions reductions as offsets for Tier 2 projects.
• EPA refinery permitting teams.
We intend to assemble special EPA teams, comprised of Headquarters and Regional Office experts, that will track the overall progress in permit issuance and will be available to assist State and local permitting authorities, refineries, and the public upon request to resolve site-specific permitting issues. These teams will be comprised of persons who are knowledgeable about permitting programs and refinery operations and can provide expert assistance to troubleshoot permitting issues that may arise. As appropriate, the teams will work with stakeholders on a case-by-
The Tier 2/gasoline sulfur rule will help achieve significant nationwide reductions in the emissions of nitrogen oxides (NOx), volatile organic compounds (VOC), particulate matter (PM), and sulfur dioxide (SO
We believe it is important to understand and address concerns relating to potential localized emissions increases from refineries that make significant process changes to meet the requirements of the Tier 2 rule. We believe that, among other things, the keys to addressing any potential concerns are as follows:
• Providing meaningful community involvement early and throughout the process;
• Determining what information and actions would eliminate concerns; and
• Determining what EPA, States, and industry can do to make the permitting process smoother by ensuring ongoing community involvement in the decision making process and by building trust among stakeholders.
To this end, the Agency has already taken some actions to try to mitigate potential environmental justice concerns. First, EPA's Office of Air and Radiation and the Alternative Dispute Resolution Team within EPA's Office of the Administrator implemented a national convening process which was designed to bring together a broad spectrum of stakeholders to explore with them their perceptions and views of issues associated with Tier 2 permitting and to assess the potential for a collaborative process to address specific implementation issues at some time in the future. The convening was carried out by an outside neutral party who conducted interviews with representatives from selected EPA offices, States, industry, environmental groups, and environmental justice organizations. Second, EPA held informational briefings and provided background materials to the National Environmental Justice Advisory Council's (NEJAC)
The EPA is committed to continue working with all stakeholders to resolve specific Environmental Justice issues if and when they arise. To fulfill this commitment, we plan to undertake additional actions in the future, including providing education and outreach about the rule and its impacts in local communities, developing permitting guidance through a public process and addressing Title VI petitions if they arise.
Consideration of the economic impacts of new standards for vehicles and fuels has been an important part of our decision making process for this final rule. The following sections describe first the costs associated with meeting the new vehicle standards and the new fuel standards. This will be followed with a discussion of the cost effectiveness of the rule. Lastly, we will discuss the results of a benefit-cost assessment that we have prepared.
Full details of our cost analyses, including information not presented here, can be found in the RIA associated with this rule. Also, our response to comments on the cost, cost effectiveness, and monetized benefits analyses are contained in the Response to Comments document for this rule.
To perform a cost analysis for the standards, we first determined a package of likely technologies that manufacturers could use to meet the standards and then determined the costs of those technologies. In making our estimates we have relied on our own technology assessment which included publicly available information, such as that developed by California, as well as confidential information supplied by individual manufacturers, and the results of our own in-house testing.
In general, we expect that the Tier 2 standards will be met through refinements of current emissions control components and systems rather than through the widespread use of new technology. Furthermore, smaller lighter-weight vehicles and trucks will generally require less extensive improvements than larger vehicles and trucks. More specifically, we anticipate a combination of technology upgrades such as the following:
• Improvements to the catalyst system design, structure, and formulation plus in some cases an increase in average catalyst size and loading;
• Air and fuel system modifications including changes such as improved microprocessors, improved oxygen sensors, leak free exhaust systems, air assisted fuel injection, and calibration changes including improved precision fuel control and individual cylinder fuel control;
• Engine modifications, possibly including an additional spark plug per cylinder, an additional swirl control valve, or other hardware changes needed to achieve cold combustion stability;
• Increased use of fully electronic exhaust gas recirculation (EGR); and
• Increased use of secondary air injection for 6 cylinder and larger engines.
The costs for MDPVs have been included here with the LDT4 cost estimates. We expect that the technologies needed to meet the Tier 2 standards for the MDPVs will be very similar to those for LDT4s. However, the MDPVs cost estimates are somewhat higher than for LDT4s. Vehicles over 8,500 pounds GVWR are currently certified to heavy-duty engine emissions standards using the heavy-duty test procedures. This, at least in part, has led to differences in baseline technologies compared to current LDT4s. Vehicles above 8,500 pounds, for example, are currently equipped with technologies such as close coupled catalysts and secondary air injection to a lesser extent. Therefore, we expect higher incremental costs for the MDPVs compared to LDT4s. There is further information on the costs for MDPVs in the RIA.
Using a typical mix of changes for each group, we projected costs separately for LDVs, the different LDT classes, and for different engine sizes (4, 6, 8, 10-cylinder) within each class. For each group we developed estimates of both variable costs (for hardware and assembly time) and fixed costs (for R&D, retooling, and certification).
Cost estimates based on the current projected costs for our estimated technology packages represent an expected incremental cost of vehicles in the near-term. For the longer term, we have identified factors that would cause cost impacts to decrease over time. First, since fixed costs are assumed to be recovered over a five-year period, these costs disappear from the analysis after the fifth model year of production. Second, the analysis incorporates the expectation that manufacturers and suppliers will apply ongoing research and manufacturing innovation to making emission controls more effective and less costly over time. Research in the costs of manufacturing has consistently shown that as manufacturers gain experience in production and use, they are able to apply innovations to simplify machining and assembly operations, use lower cost materials, and reduce the number or complexity of component parts.
We have prepared our cost estimates for meeting the Tier 2 standards using a baseline of NLEV technologies for LDVs, LDT1s, and LDT2s, and Tier 1, or current technologies for LDT3s, LDT4s and MDPVs. These are the standards that vehicles would be meeting in 2003.
For the total annual cost estimates, we projected that manufacturers will start the phase-in of Tier 2 vehicles with LDVs in 2004 and progress to heavier vehicles until all LDT2s meet Tier 2 standards in 2007. For LDT3s and LDT4s, we projected some sales of Tier 2 LDT3s prior to 2008 for purposes of averaging in the interim program and that the phase-in of Tier 2 vehicles would end with LDT4s and MDPVs in 2009.
Finally, we have incorporated what we believe to be a conservatively high level of R&D spending at $5,000,000 per vehicle line (with annual sales of 100,000 units per line). We have included this large R&D effort because calibration and system optimization is likely to be a critical part of the effort to meet Tier 2 standards. However, we believe that the R&D costs may be generous because the projection ignores the carryover of knowledge from the first vehicle lines designed to meet the standard to others phased-in later.
The evaporative emissions standards we are finalizing today for LDVs, LDTs and MDPVs are feasible with relatively small cost impacts. We estimate the cost of system improvements to be about $4 per vehicle, for all vehicle classes. This incremental cost reflects the cost of moving to low permeability materials, improved designs or low-loss connectors. R&D for the evaporative emissions standard is included in the R&D estimates given above for the tailpipe standards. We have included no projections of learning curve reductions for the evaporative standard.
Table IV.D.-1 provides our estimates of the per vehicle increase in purchase price for LDVs, LDTs, and MDPVs. The near-term cost estimates in Table IV.D.-1 are for the first years that vehicles meeting the standards are sold, prior to cost reductions due to lower productions costs and the retirement of fixed costs. The long-term projections take these cost reductions into account. We have sales weighted the cost differences for the various engine sizes (4-, 6-, 8-, 10-cylinder) within each category.
We did not receive comments disagreeing with the technology projections or technology cost estimates contained in the proposal. We have, however, revised our cost estimates somewhat based on new information available since the proposal. We moderately lowered our cost estimates due to adjustments we have made in our technology projections. Based on the results of our vehicle testing program described above in section IV.A.1., we now believe that a few of the hardware changes we had anticipated are not likely to be needed to meet the standards. Albeit there is always fluctuation, the spot prices of precious metals have increased somewhat since the proposal and we have adjusted our analysis to reflect those changes.
Overall, the cost estimates are within 5 percent of those in the proposal for LDVs and LLDTs. The changes noted above moderately lowered the costs for HLDTs compared to the proposal. The cost increase due to the inclusion of MDPVs offsets most of the lowered costs
We are also finalizing OBD II requirements and onboard vapor recovery (ORVR) requirements for MDPVs. We have estimated that OBD II will cost about $80, which includes the costs of additional sensors and system improvements. We have estimated ORVR system costs to be about $10. The $10 cost for ORVR does not include any fuel cost savings over the life of the vehicles due the recover of fuel vapor during refueling. ORVR provides a fuel cost savings because the vapors are captured, and burned in the engine, rather than escaping to the atmosphere. We estimate the savings over the life of the vehicle to be about $6. These costs are not reflected in Table IV.D.-1.
As we explained at the beginning of Section IV.C, we expect that most refiners will have to install capital equipment to meet the gasoline sulfur standard. Presuming that refiners will want to minimize the cost involved, the majority of refiners are expected to desulfurize the gasoline blendstock produced by the fluidized catalytic cracker (FCC) unit, although a few may choose to desulfurize the feed to the FCC unit. Recent advances have led to significant improvements in the hydrotreating technologies used for FCC gasoline desulfurization. Since these improved technologies represent the lowest cost options and are expected to be used by most refiners needing to install desulfurization equipment, we have based our cost estimates primarily on their use. However, in acknowledgment that some refiners, particularly those which make investment decisions in the near term, are likely to select more traditional approaches using proven technologies, we have included the costs for currently proven desulfurization technologies in our analysis, as well. This is different from the analysis we did in support of our proposal, where we assumed that all refiners would take advantage of the most improved technologies we were aware of at that time.
For our analysis of the costs of controlling gasoline sulfur, we estimated the costs in five different regions of the country (Petroleum Administration Districts for Defense, or PADDs) for reductions from the current PADD average gasoline sulfur level down to a 30 ppm average. We then combined the regional costs to develop an average national individual refinery cost, and used this figure to calculate national aggregate capital and operating costs. In our proposal we estimated a single cost for desulfurizing gasoline, using as an assumption for the purpose of analysis that all refiners would upgrade their refineries by 2004 and that all would choose one of two improved technologies we knew of at the time. We then reduced this cost over time to reflect expected cost reductions due to further technology advancements and reduced operating costs due to improved understanding of the technologies and refinery debottlenecking. Based on improved information about the availability of technologies, we have now analyzed the costs of controlling sulfur on a year-by-year basis beginning with 2004, to be consistent with our analysis of the rate at which the industry would invest in desulfurization technologies over the first years of the program and the changing technology selections (and costs) that would accompany this phase-in (discussed in Section IV.C.1 above). A detailed description of our calculations can be found in the Regulatory Impact Analysis; the reader can refer to the draft RIA released with the proposed rule for more information on our prior analysis.
We estimate that, on average, refineries which install equipment to meet the 30 ppm average standard will invest about $44 million for capital equipment and spend about $16 million per year for each refinery to cover the operating costs associated with these desulfurization units. Since this average represents many refineries diverse in size and gasoline sulfur level as well as a mix of desulfurization technologies, some refineries will pay more and others less than the average costs. When the average per-refinery cost is aggregated for all the gasoline expected to be produced in this country in 2008 (the first year that all refiners will be required to meet the 30 ppm standard, unless any small refiners are granted a extension of hardship relief), the total investment for desulfurization processing units (spread between 2003 and 2007) is estimated to be about $4.3 billion, and operating costs for these units is expected to be about $1.3 billion per year.
Using our estimated capital and operating costs for domestic refineries, we calculated the average per-gallon cost of reducing gasoline sulfur down to 30 ppm for each year as the program is implemented. Using a capital cost amortization factor (based on a seven percent rate of return on investment) and including no taxes, we estimated the average national cost for desulfurizing gasoline to be about 1.7-1.9 cents per gallon as the program is phased in. This cost is the cost to society of reducing gasoline sulfur down to 30 ppm that we used for estimating cost effectiveness. Table IV.D.-2 below summarizes our estimates of per-gallon gasoline cost increases for select years.
Although the costs shown here are slightly higher than we projected in the proposal, overall, we believe our revised costs are consistent with those in the proposal and that our improved methodology and information are the source of the differences. As stated earlier in this section, we believe this analysis more accurately reflects the actual investment decisions of individual refiners over the years in which the industry is phasing down sulfur levels. Furthermore, we have also made a number of other adjustments to our analysis of capital and operating costs for each individual technology based on new information received from the technology vendors and information we obtained during the comment period. For example, we now include eight different technologies in our analysis, including some more traditional approaches, whereas in the proposal we only considered two new technologies. Hence, the range of costs is broader. In addition, as explained in the RIA, we now believe we underestimated the capital costs of desulfurization slightly in the proposal based on our calculation of the costs of providing hydrogen to the processes. We believe our analysis now reflects the most up-to-date information about the costs of installing and operating the various desulfurization technologies included in our analysis. These adjustments are explained in detail in the Regulatory Impact Analysis.
We still believe that over time, particularly in 2006-8 when the last refineries will be making investments, the costs of gasoline desulfurization equipment will be significantly lower
Using current data for the size and characteristics of the vehicle fleet and making projections for the future, the per-vehicle and per-gallon fuel costs described above can be used to estimate the total cost to the nation for the emission standards in any year. Figure IV.D.-1 portrays the results of these projections.
As can be seen from the figure, the annual cost starts out at about $1.9 billion per year and increases over the phase-in period to about $4.1 billion in 2008. Total annualized costs are projected to remain at about $4 billion through 2018. After 2018, annualized fuel costs are projected to decrease somewhat due to the use of new technologies which would enable refiners to produce low sulfur fuel at a lower cost. The gradual rise in costs long term is due to the effects of projected growth in vehicle sales and fuel consumption. The RIA provides further detail regarding these cost projections.
This section summarizes the cost-effectiveness analysis conducted by EPA and its results. The purpose of this analysis is to show that the reductions from the vehicle and fuel controls being finalized today are cost-effective in comparison to alternative means of attaining or maintaining the NAAQS. This analysis involves a comparison of our program not only to past measures, but also to other potential future measures that might be employed to attain and maintain the NAAQS. Both EPA and states have already adopted numerous control measures, and remaining measures tend to be more expensive than those previously employed. As we employ the most cost-effective available measures first, more expensive ones tend to become necessary over time.
The emission reductions used to calculate the cost-effectiveness levels reported here are based on those reductions used for our air quality analysis modeling and benefits analysis. This was done to maintain consistency in the analyses. As noted in Section III.B. above, we have updated our inventory model since the air quality modeling inventories were calculated. In Chapter III of our RIA, Table III.A.-3 compares the updated Tier 2 model with the air quality analysis modeling and shows that the emission reductions expected from Tier 2/gasoline sulfur will be substantially greater than the amounts originally calculated. If the
We received a number of comments on our cost-effectiveness analysis in response to our NPRM. Our responses to these comments can be found in the Response To Comments document.
We have calculated the cost-effectiveness of the exhaust emission/gasoline sulfur standards and the evaporative emission standards, based on two different approaches. The first considers the net present value of all costs incurred and emission reductions generated over the life of an average Tier 2 vehicle. This per-vehicle approach focuses on the cost-effectiveness of the program from the point of view of the Tier 2 vehicles which will be used to meet the new requirements, and is the method used in our proposal. However, the per-vehicle approach does not capture all of the costs or emission reductions from the Tier 2/gasoline sulfur program since it does not account for the use of low sulfur gasoline in pre-Tier 2 vehicles. Therefore, we have also calculated an aggregate cost-effectiveness using the net present value of costs and emission reductions for all in-use vehicles over a 30-year time frame.
As described earlier in the discussion of the cost of this program, the cost of complying with the new standards will decline over time as manufacturing costs are reduced and amortized capital investments are recovered. To show the effect of declining cost in the per-vehicle cost-effectiveness analysis, we have developed both near term and long term cost-effectiveness values. More specifically, these correspond to vehicles sold in years one and six of the vehicle and fuel programs. Vehicle cost is constant from year six onward. Fuel costs per gallon continue to decline slowly in the years past year six; however, the overall impact of this decline is small and we have decided to use year six results for our long term cost-effectiveness. Chapter VI of the RIA contains a full description of this analysis, and you should look in that document for more details of the results summarized here.
The aggregate approach to calculating the cost-effectiveness of our program involves the net present value of all nationwide emission reductions and costs for a 30-year period beginning with the start of the program in 2004. This timeframe captures both the early period of the program when very few Tier 2 vehicles will be in the fleet, and the later period when essentially all vehicles in the fleet will meet Tier 2 standards. We have calculated the aggregate cost-effectiveness using the net present value of the nationwide emission reductions and costs for each calendar year. These emission reductions and costs are summarized in Sections III.B, III.C, and IV.D.3, and are given for every calendar year in the RIA. For more information on how the aggregate cost-effectiveness was calculated please refer to the RIA.
Our per-vehicle and aggregate cost-effectiveness values are given in Tables IV.D.-3 and IV.D.-4. Table IV.D.-3 summarizes the per-vehicle, net present value lifetime costs, NMHC+NO
Tables IV.D.-3 and IV.D.-4 also display cost-effectiveness values based on two approaches to account for the reductions in SO
In comparison with other mobile source control programs, we believe that our program represents the most cost-effective new mobile source control strategy currently available that is capable of generating substantial NO
We can see from the table that the cost-effectiveness of the Tier 2/gasoline sulfur standards falls within the range of these other programs. Engine-based standards (the 2004 highway heavy-duty diesel standards, the nonroad diesel engine standards and the marine spark-ignited engine standards) have generally been less costly than Tier 2/gasoline sulfur. Vehicle standards, most similar to today's program, have values comparable to or higher than Tier 2/gasoline sulfur.
The values in Table IV.D.-5 might imply that further reductions in NO
On the light-duty vehicle side, the last two sets of standards were Tier 1 and NLEV, which had cost-effectiveness comparable to or higher than Tier 2/gasoline sulfur. Compared to engines, these levels reflect the advanced (and more expensive) state of vehicle control technology, where standards have been in effect for a much longer period than for engines. Considering the increased stringency of the Tier 2 standards, it is noteworthy that the cost-effectiveness of Tier 2/gasoline sulfur is in the same range as these actions. Based on these results, Tier 2/gasoline sulfur is a logical and consistent next step in vehicle control.
In conclusion, we believe that the Tier 2/Gasoline Sulfur program is a cost-effective program for mobile source NO
In evaluating the cost-effectiveness of the Tier 2/Gasoline Sulfur program, we also considered whether our program is cost-effective in comparison with alternative means of attaining or maintaining the NAAQS other than mobile source programs. As described below, we have concluded that Tier 2/Gasoline Sulfur is cost-effective considering the anticipated cost of other technologies that will be needed to help attain and maintain the NAAQS.
In the context of the Agency's rulemaking to revise the ozone and PM NAAQS,
In addition, our Tier 2/Gasoline Sulfur program will deliver critical further reductions that are not readily obtainable by any other means known to the Agency. If all of the technologies modeled in the NAAQS analysis costing less than $10,000/ton were implemented nationwide, they would produce NO
We recognize that the cost-effectiveness calculated for Tier 2/Gasoline Sulfur is not strictly comparable to a figure for measures targeted at nonattainment areas, since Tier 2/Gasoline Sulfur is a nationwide program. However, there are several additional considerations that have led us to conclude that Tier 2/Gasoline Sulfur is cost-effective considering
First of all is the fact that the cost effectiveness of Tier 2/Gasoline Sulfur is so much better than the numbers developed for the NAAQS analysis. It is only 20 percent as costly per ton as the $10,000 per ton upper limit employed in that analysis for selecting suitable strategies even though, as noted above, Tier 2/Gasoline Sulfur will produce almost the same level of emission reduction. Furthermore, as a national program, Tier 2/Gasoline Sulfur can be implemented as a single unified rule without the need for individual action by each of the states.
In dealing with the question of comparing local and national programs, it is also relevant to point out that, because of air transport, the need for NO
Finally, the statute indicates that in considering the cost-effectiveness of Tier 2/Gasoline Sulfur EPA should consider not only attainment, but also maintenance of the standards. Tier 2/Gasoline Sulfur—unlike nonattainment area measures—will achieve attainment area reductions that, among other effects, will help to maintain air quality that meets the NAAQS. These reductions relate not only to the ozone and PM NAAQS, but also to SO
In summary, given the array of controls that will have to be implemented to make progress toward attaining and maintaining the NAAQS, we believe that the weight of the evidence from alternative means of providing substantial NO
While relative cost-effectiveness is the principal economic policy criterion established for these standards in the Clean Air Act (see CAA § 202(i)), further insight regarding the merits of the standards can be provided by benefit-cost analysis. The purpose of this section is to summarize the methods we used and results we obtained in conducting an analysis of the economic benefits of the Tier 2 program, and to compare these economic benefits with the estimated costs of the rule. In summary, the results of our analysis using the EPAs preferred approach to valuing premature mortality indicate that the economic benefits of the Tier 2/gasoline sulfur standards will likely exceed the costs of meeting the standards by about $20 billion (1997$).
Benefit-cost analysis (BCA) is a useful tool for evaluating the economic merits of proposed changes in environmental programs and policies. In its traditional application, BCA estimates the economic “efficiency” of proposed changes in public policy by organizing the various expected consequences and representing those changes in terms of dollars. Expressing the effects of these policy changes in dollar terms provides a common basis for measuring and comparing these various effects. Because improvement in economic efficiency is typically defined to mean maximization of total wealth spread among all members of society, traditional BCA must be supplemented with other analyses in order to gain a full appreciation of the potential merits of new policies and programs. These other analyses may include such things as examinations of legal and institutional constraints and effects; engineering analyses of technology feasibility, performance and cost; or assessment of the air quality need.
In addition to the narrow, economic efficiency focus of most BCAs, the technique is also limited in its ability to project future economic consequences of alternative policies in a definitive way. Critical limitations on the availability, validity, or reliability of data; limitations in the scope and capabilities of environmental and economic effect models; and controversies and uncertainties surrounding key underlying scientific and economic literature all contribute to an inability to estimate the economic effects of environmental policy changes in exact and unambiguous terms. Under these circumstances, we consider it most appropriate to view BCA as a tool to inform, but not dictate, regulatory decisions such as the ones reflected in today's rule.
Despite the limitations inherent in BCA of environmental programs, we consider it useful to estimate the potential benefits of today's action both in terms of physical changes in human health and welfare and environmental change, and in terms of the estimated economic value of those physical changes.
The basic question we sought to answer in the BCA was: “What are the net yearly economic benefits to society of the reduction in mobile source emissions likely to be achieved by the final Tier 2 program?” In designing an analysis to answer this question, we selected a future year for analysis (2030) that is representative of full-implementation of the program (
Every BCA examining the potential effects of a change in environmental protection requirements is limited to some extent by data gaps, limitations in model capabilities (such as geographic coverage), and uncertainties in the underlying scientific and economic
• The exclusion of potentially significant benefit categories (
• Errors in measurement and projection for variables such as population growth,
• Variability in the estimated relationships of health and welfare effects to changes in pollutant concentrations.
In addition to these uncertainties and shortcomings which pervade all analyses of criteria air pollutant control programs, a number of limitations apply specifically to the BCA of today's action. Though we used the best data and models currently available, we were required to adopt a number of simplifying assumptions and to use data sets which, while reasonably close, did not match precisely the conditions and effects expected to result from implementation of the standards. For example, to estimate the effects of the program at full implementation we projected vehicle miles traveled and populations in the year 2030. These assumptions may play a significant role in determining the magnitude of the benefits estimate. In addition, although the emissions data sets used for this analysis have been updated from those used in the proposal, they may not anticipate the emissions reductions realized by other future actions and by expected near-future control programs. For example, it is possible that the Tier 2/gasoline sulfur standards will not be the governing vehicle emissions standards in 2030. In the years before 2030, the benefits from the Tier 2 program will be less than those estimated here (significantly less in the early years), because the Tier 2 fleet will not be fully phased in.
Finally, the implementation period for phasing-in the rule requirements is a critical period that deserves careful evaluation. The benefit-cost analysis for 2030 is not significantly affected by alternative phase-in decisions, the primary impact of which will occur in the 2005-2015 time frame. As a result, the analysis of phase-in alternatives must rely on other types of analysis (
The key limitations and uncertainties unique to the BCA of the final rule, therefore, include:
• Uncertainties in the estimation of future year emissions inventories and air quality,
• Uncertainties associated with the extrapolation of air quality monitoring data to some unmonitored areas required to better capture the effects of the standards on affected populations, and
• Uncertainties associated with the effect of potential future actions to limit emissions.
Despite these uncertainties, which are discussed in more detail or referenced in the RIA, we believe the BCA provide a reasonable indication of the expected economic benefits of the Tier 2 program in 2030 under one set of assumptions. This is because the analysis focuses on estimating the economic effects of the
We significantly improved the analysis that was presented at proposal. For the final rule, EPA updated the emissions inventory from 1990 to 1996 using updated models, refined the projections of the effects of the rule when it is fully implemented, and updated our air quality modeling to reflect new programs issued since 1990. In addition, we also updated our assumptions for estimating physical effects and monetary benefits based on recommendations from the EPA's Science Advisory Board (SAB) during the summer of 1999. Details on these recommendations can be found in the advisory statements published by the SAB.
The analytical sequence begins with a projection of the mix of technologies likely to be deployed to comply with the new standards, and the costs incurred and emissions reductions achieved by these changes in technology. The Tier 2 program has various cost and emission related components, as described earlier in this section. These components would begin at various times and in some cases would phase in over time. This means that during the early years of the program there would not be a consistent match between cost and benefits. This is especially true for the vehicle control portions of the program, where the full vehicle cost would be incurred at the time of vehicle purchase, while the fuel cost along with the emission reductions and benefits would occur throughout the lifetime of the vehicle.
To develop a benefit-cost number that is representative of a fleet of Tier 2 vehicles, we need to have a stable set of cost and emission reductions to use. This means using a future year where the fleet is fully turned over and there is a consistent annual cost and annual emission reduction. For the Tier 2 program, this stability would not occur until well into the future. For this analysis, we selected the year 2030. The resulting analysis represents a snapshot of benefits and costs in a future year in which the light-duty fleet consists almost entirely of Tier 2 vehicles. As such, it depicts the maximum emission reductions (and resultant benefits) and among the lowest costs that would be achieved in any one year by the program on a “per mile” basis. (Note, however, that net benefits would continue to grow over time beyond those resulting from this analysis, because of growth in population and vehicle miles traveled.) Thus, based on the long-term costs for a fully turned over fleet, the resulting benefit-cost ratio will be close to its maximum point (for those benefits which we have been able to value).
To present a BCA, we designed the cost estimate to reflect conditions in the same year as the benefit valuation. Costs are, therefore, developed for the year 2030 fleet. For this purpose we used the long term cost once the capital costs have been recovered and the manufacturing learning curve
We also made adjustments in the costs to account for the fact that there is a time difference between when some of the costs are expended and when the benefits are realized. The vehicle costs are expended when the vehicle is sold, while the fuel related costs and the benefits are distributed over the life of the vehicle. We resolved this difference by using costs distributed over time such that there is a constant cost per ton of emissions reduction and such that the net present value of these distributed costs corresponds to the net present value of the actual costs.
The resulting adjusted costs are somewhat greater than the expected actual annual cost of the program, reflecting the time value adjustment. Thus, the costs presented in this section do not represent expected actual annual costs for 2030. Rather, they represent an approximation of the steady-state cost per ton that would likely prevail in that time period. The benefit cost ratio for the earlier years of the program would be expected to be lower than that based on these costs, since the per-vehicle costs are larger in the early years of the program while the benefits are smaller.
In order to estimate the changes in air quality conditions which would result from these emissions reductions, we developed two separate, year 2030 emissions inventories to be used as inputs to the air quality models. The first, baseline inventory, reflects the best available approximation of the county-by-county emissions for NO
With these two emissions inventories in hand, the next step was to “map” the county-by-county and pollutant-by-pollutant emission estimates to the input grid cells of two air quality models and one deposition model. The first model, called the Urban Airshed Model (UAM), is designed to estimate the tropospheric ozone concentrations resulting from a specific inventory of emissions of ozone precursor pollutants, particularly NO
After developing these two sets of year 2030 air quality profiles, we used the same health and environmental effect models used in the section 812 studies to calculate the differences in human health and environmental outcomes projected to occur with and without the proposed standards. Specifically, we used the Criteria Air Pollutant Modeling System (CAPMS) to estimate changes in human health outcomes, and the Agricultural Simulation Model (AGSIM) to estimate changes in yields of a selected few agricultural crops. In addition, the impacts of reduced visibility impairment and estimates of the effect of changes in nitrogen deposition to a selection of sensitive estuaries were estimated using slightly modified versions of the methods used in the section 812 studies. Several air quality-related health and environmental benefits, however, could not be calculated for the BCA of today's proposed standards. Changes in human health and environmental effects due to changes in ambient concentrations of carbon monoxide (CO), gaseous sulfur dioxide (SO
To characterize the total economic value of the reductions in adverse effects achieved across the lower 48 states,
The last step of the analysis is to characterize the uncertainty surrounding our estimate of benefits. Again, we follow the recommendations of the SAB for the presentation of uncertainty. They recommend that a primary estimate should be presented along with a description of the uncertainty associated with each endpoint. At proposal, our characterization of uncertainty was based on an estimated range of benefits which might occur if important but uncertain underlying factors were allowed to vary. This approach, however, is criticized by the SAB because while the low- or high-end estimates provided for individual endpoints was “plausible,” the probability of all of the assumptions in these estimates occurring simultaneously was likely to be small.
Therefore, for the final Tier 2/gasoline sulfur rule, the benefit analysis adopts an approach similar to the section 812 study. Our analysis first presents our estimate for a primary set of benefit endpoints followed by a presentation of “alternative calculations” of key health and welfare endpoints to characterize the uncertainty in this primary set. However, the adoption of a value for the projected reduction in the risk of premature mortality is the subject of continuing discussion within the economic and public policy analysis community within and outside the Administration. In response to the sensitivity on this issue, we provide estimates reflecting two alternative approaches for mortality benefits: the EPAs preferred approach using the value of a statistical life, and an alternative approach using the value of a statistical life years. These are discussed further in section f. of this presentation. The presentation of the alternative calculations for certain endpoints seeks to demonstrate how much the overall benefit estimate might vary based on the value EPA has given to a parameter (which has some uncertainty associated with it) underlying the estimates for human health and environmental effect incidence and the economic valuation
• Presentation of an estimated confidence interval around the Primary estimate of benefits to characterize The standard error in the C-R and valuation studies used in developing benefit estimates for each endpoint;
• Valuing PM-related premature mortality based on a different C-R study;
• Value of avoided premature mortality incidences based on statistical life years;
• Consideration of reversals in chronic bronchitis treated as lowest severity cases;
• Value of visibility changes in all Class I areas;
• Value of visibility changes in Eastern U.S. residential areas;
• Value of visibility changes in Western U.S. residential areas;
• Value of reduced household soiling damage; and
• Avoided costs of reducing nitrogen loadings in east coast estuaries.
For instance, the study by Dockery, et al. estimates of the relationship between PM exposure and premature mortality is a plausible alternative to the Pope, et al. study used for the Primary estimate of benefits. The SAB has noted that “the study had better monitoring with less measurement error than did most other studies” (EPA-SAB-COUNCIL-ADV-99-012, 1999). The Dockery study had a more limited geographic scope (and a smaller study population) than the Pope, et al. study and the Pope study appears more likely to mitigate a key source of potential confounding. The Dockery study also covered a broader age category (25 and older compared to 30 and older in the Pope study) and followed the cohort for a longer period (15 years compared to 8 years in the Pope study). For these reasons, the Dockery study is considered to be a plausible alternative estimate of the avoided premature mortality incidences associated with the final Tier 2/gasoline sulfur rule. The alternative estimate for mortality can be substituted for the valuation component in our primary estimate of mortality benefits to observe how the net benefits of the program may be influenced by this assumption. Unfortunately, it is not possible to combine all of the assumptions used in the alternate calculations to arrive at different total benefit estimates because, it is highly unlikely that the selected combination of alternative values would all occur simultaneously. Therefore, it is better to consider each alternative calculation individually to assess the uncertainty in the estimate.
In addition to the estimate for the primary set of endpoints and alternative calculations of benefits, our RIA also presents an appendix with supplemental benefit estimates and sensitivity analyses of other key parameters in the benefit analysis that have greater uncertainty surrounding them due to limitations in the scientific literature. Supplemental estimates are presented for premature mortality associated with short-term exposures to PM and ozone, asthma attacks, occurrences of moderate or worse asthma symptoms, and an estimate of the avoided incidences of premature mortality in infants.
Even with our efforts to fully disclose the uncertainty in our estimate, this uncertainty presentation method does not provide a definitive or complete picture of the true range of monetized benefits estimates. This approach, as implemented in this BCA, does not reflect important uncertainties in earlier steps of the analysis, including estimation of compliance technologies and strategies, emissions reductions and costs associated with those technologies and strategies, and air quality and deposition changes achieved by those emissions reductions. Nor does this approach provide a full accounting of all potential benefits associated with the Tier 2/gasoline sulfur standards, due to data or methodological limitations. Therefore, the uncertainty range is only representative of those benefits that we were able to quantify and monetize.
The BCA for the Tier 2 program reflects a single year “snapshot” of the yearly benefits and costs expected to be realized once the standards have been fully implemented and non-compliant vehicles have all been retired. Near-term costs will be higher than long-run costs as vehicle manufacturers and oil companies invest in new capital equipment and develop and implement new technologies. In addition, near-term benefits will be lower than long-run benefits because it will take a number of years for Tier 2-compliant vehicles to fully displace older, more polluting vehicles. However, as described earlier, we have adjusted the cost estimates upward to compensate for some of this discrepancy in the timing of benefits and costs and to ensure that the long-term benefits and costs are calculated on a consistent basis. The resulting adjusted long-term cost value is given in Table IV.D.-5a. Because of the adjustment process, the cost estimates should not be interpreted as reflecting the actual costs expected to be incurred in the year 2030. Actual program costs can be found in Section IV.D.3.
With respect to the benefits, several different measures of benefits can be useful to compare and contrast to the estimated compliance costs. These benefit measures include (a) the tons of emissions reductions achieved, (b) the reductions in incidences of adverse health and environmental effects, and (c) the estimated economic value of those reduced adverse effects. Calculating the cost per ton of pollutant reduced is particularly useful for comparing the cost-effectiveness of the new standards or programs against existing programs or alternative new programs achieving reductions in the same pollutant or combination of pollutants. The cost-effectiveness analysis presented earlier in this preamble provides such calculations on a per-vehicle basis. Considering the absolute numbers of avoided adverse health and environmental effects can also provide valuable insights into the nature of the health and environmental problem being addressed by the rule as well as the magnitude of the total public health and environmental gains potentially achieved by the rule. Finally, when considered along with other important economic dimensions —including environmental justice, small business financial effects, and other outcomes related to the distribution of benefits and costs among particular groups— the direct comparison of quantified economic benefits and economic costs can provide useful insights into the potential magnitude of the estimated net economic effect of the rule, keeping in mind the limited set of effects we are able to monetize.
Table IV.D.-6 presents the EPAs preferred approach to estimate the benefits of both the estimated reductions in adverse effect incidences and the estimated economic value of
Total monetized benefits, however, are driven primarily by the estimated 4300 fewer premature fatalities. The adoption of a value for the projected reduction in the risk of premature mortality is the subject of continuing discussion within the economic and public policy analysis community within and outside the Administration. In response to the sensitivity on this issue, we provide estimates reflecting two alternative approaches. The first approach—supported by some in the above community and preferred by EPA—uses a Value of a Statistical Life (VSL) approach developed for the Clean Air Act Section 812 benefit-cost studies. This VSL estimate of $5.9 million (1997$) was derived from a set of 26 studies identified by EPA using criteria established in Viscusi (1992), as those most appropriate for environmental policy analysis applications.
An alternative, age-adjusted approach is preferred by some others in the above community both within and outside the Administration. This approach was also developed for the Section 812 studies and addresses concerns with applying the VSL estimate—reflecting a valuation derived mostly from labor market studies involving healthy working-age manual laborers—to PM-related mortality risks that are primarily associated with older populations and those with impaired health status. This alternative approach leads to an estimate of the value of a statistical life year (VSLY), which is derived directly from the VSL estimate. It differs only in incorporating an explicit assumption about the number of life years saved and an implicit assumption that the valuation of each life year is not affected by age.
Both approaches are imperfect, and raise difficult methodological issues which are discussed in depth in the recently published Section 812 Prospective Study, the draft EPA Economic Guidelines, and the peer-review commentaries prepared in support of each of these documents. For example, both methodologies embed assumptions (explicit or implicit) about which there is little or no definitive scientific guidance. In particular, both methods adopt the assumption that the risk versus dollars trade-offs revealed by available labor market studies are applicable to the risk versus dollar trade-offs in an air pollution context.
EPA currently prefers the VSL approach because, essentially, the method reflects the direct, application of what EPA considers to be the most reliable estimates for valuation of premature mortality available in the current economic literature. While there are several differences between the labor market studies EPA uses to derive a VSL estimate and the particulate matter air pollution context addressed here, those differences in the affected populations and the nature of the risks imply both upward and downward adjustments. For example, adjusting for age differences may imply the need to adjust the $5.9 million VSL downward as would adjusting for health differences, but the involuntary nature of air pollution-related risks and the lower level of risk-aversion of the manual laborers in the labor market studies may imply the need for upward adjustments. In the absence of a comprehensive and balanced set of adjustment factors, EPA believes it is reasonable to continue to use the $5.9 million value while acknowledging the significant limitations and uncertainties in the available literature. Furthermore, EPA prefers not to draw distinctions in the monetary value assigned to the lives saved even if they differ in age, health status, socioeconomic status, gender or other characteristic of the adult population.
Those who favor the alternative, age-adjusted approach (i.e. the VSLY approach) emphasize that the value of a statistical life is not a single number relevant for all situations. Indeed, the VSL estimate of $5.9 million (1997 dollars) is itself the central tendency of a number of estimates of the VSL for some rather narrowly defined populations. When there are significant differences between the population affected by a particular health risk and the populations used in the labor market studies—as is the case here—they prefer to adjust the VSL estimate to reflect those differences. While acknowledging that the VSLY approach provides an admittedly crude adjustment (for age though not for other possible differences between the populations), they point out that it has the advantage of yielding an estimate that is not presumptively biased. Proponents of adjusting for age differences using the VSLY approach fully concur that enormous uncertainty remains on both sides of this estimate—upwards as well as downwards—and that the populations differ in ways other than age (and therefore life expectancy). But rather than waiting for all relevant questions to be answered, they prefer a process of refining estimates by incorporating new information and evidence as it becomes available.
In addition to the presentation of mortality valuation, this table also indicates with a “B” those additional health and environmental benefits which could not be expressed in quantitative incidence and/or economic value terms. A full listing of the benefit categories that could not be quantified or monetized in our estimate are provided in Table IV.D.-8. For instance, visibility is expected to improve in all areas of the country, with the largest improvements occurring in heavily populated residential areas (
In summary, the VSL approach—the approach EPA prefers—yields a monetized benefit estimate of $25.2 billion in 2030. The alternative, age-adjusted VSLY approach (presented in Table IV.D.7) yields monetary benefits of approximately $13.8 billion in 2030.
In addition, in analyzing the present rule, we recognized that the benefits estimates were subject to a number of uncertainties with other parameters. In Table IV D-9, we present alternative calculations representing the effect of different assumptions on individual elements of the benefits analysis and on the total benefits estimate. For example, this table can be used to answer questions like “What would total benefits be if we were to use the Dockery, et al. C-R function to estimate avoided premature mortality?” This table also displays some assumptions that can be made to value some of the categories that are indicated with a “B” in the primary estimate. Overall, this table provides alternative calculations both for valuation issues (e.g., the correct value for a statistical life saved) and for physical effects issues (e.g., how reversals in chronic illnesses are treated). We show how the alternative assumption being valued would change the resulting total primary estimate, and the percentage change from the primary estimate associated with the alternative calculation. This table is not meant to be comprehensive. Rather, it reflects some of the key issues identified by EPA or commenters as likely to have a significant impact on total benefits.
The estimated adjusted cost of implementing the final Tier 2 program is $5.3 billion (1997$), while the estimate of monetized benefits using EPA's preferred approach for monetizing reductions in PM-related premature mortality—the VSL approach—are $25.2 billion (1997$). Monetized net benefits using EPA's preferred method for valuing avoided incidences of premature mortality are approximately $19.9 billion (1997$). Using the alternative, age-adjusted approach—the VSLY approach—total monetized benefits are projected to be around $13.8 billion (1997$). Monetized net benefits using this approach are approximately $8.5 billion (1997$). Therefore, implementation of the Tier 2 program will provide society with a net gain in social welfare. Tables VI.D.-10a and IV.D.-10b summarize the costs, benefits, and net benefits for the two alternative valuation approaches.
The section describes several additional provisions of today's final rule that were not previously discussed in this preamble.
Tables IV.B.-4 and -5 in Section IV.B.4.a. above presented the Tier 2 standards for carbon monoxide (CO), formaldehyde (HCHO), and particulate matter (PM). The following paragraphs discuss our selection of these specific standards.
Beyond aligning carbon monoxide (CO) standards for all LDVs and LDTs, and harmonizing with California vehicle technology, reduction in CO emissions is not a primary goal of the Tier 2 program. However, we note that more than three-fourths of CO emissions in 1997 came from mobile sources and that there are currently 20 officially designated CO nonattainment areas in the U.S. These areas include 47 counties with a combined population of 34 million. In addition, there are 23 officially designated maintenance areas also with a combined population of 34 million. Further, CO is a deadly gas that leads to accidental poisoning fatalities and injuries. Also, CO may play a role in ozone formation by increasing the reactivities of VOCs in the atmosphere.
Although there remain many areas of nonattainment and maintenance for the
Thus the CO standards we are finalizing for all Tier 2 LDVs and LDTs are essentially the same as those from the NLEV program for LDV/LLDTs. These standards will harmonize with CalLEV II CO standards except at California's SULEV level (EPA Bin 2). This lone divergence will not pose additional burden to manufacturers because the federal Tier 2 CO standards for these vehicles will be less stringent than California's. Bins applicable during the interim programs will include CO values from the NLEV program for LDV/LLDTs and from the Cal LEV I program for HLDTs.
Similar to our approach to CO standards, we are aligning all Tier 2 LDVs and LDTs under the formaldehyde standards from the NLEV program or CalLEV II program. HLDTs, which are not subject to the NLEV program, will become subject to federal formaldehyde standards for the first time under the provisions of this rulemaking.
Formaldehyde is a hazardous air pollutant and EPA is required to regulate motor vehicle formaldehyde under section 202(l) of the Act. The standards finalized today are primarily of concern for methanol and methane (compressed natural gas or CNG)-fueled vehicles, because formaldehyde is chemically similar to methanol and methane and is likely to be produced when methanol or methane are not completely burned in the engine. HLDTs are not included under the NLEV program and will therefore not face formaldehyde standards as LDVs and LLDTs will in 2001 (1999 in the northeast states). We believe it is appropriate to bring HLDTs under HCHO standards in this rulemaking. Applying formaldehyde standards to HLDTs will be consistent with our goals of aligning standards for all LDVs and LDTs regardless of fuel type and harmonizing technologically with California standards wherever possible and reasonable and the burden will be minimal. Consequently, we are including formaldehyde standards for HLDTs under the Tier 2 program as well as under the interim programs.
In response to comments, we are finalizing a provision to allow manufacturers to demonstrate compliance with the interim and Tier 2 NMOG standards using NMHC data (non-methane hydrocarbons) for gasoline and diesel vehicles. For these vehicles, NMOG and NMHC emissions are very similar and testing for NMHC is considerably simpler and cheaper than measuring NMOG. Data available to us show that NMHC emissions at levels expected from interim and Tier 2 LDVs and LDTs can be adjusted to represent NMOG emissions by a small multiplicative factor. We are finalizing to accept NMHC test results to demonstrate compliance with the NMOG standards, but are requiring that the NMHC results be multiplied by 1.04. We will permit the use of other adjustment factors based upon comparative testing.
A drawback to NMHC testing is that NMHC testing does not yield formaldehyde results as NMOG testing does. We noted in the NPRM that HCHO is actually a component of NMOG and that we expect that all vehicles able to meet the proposed Tier 2 or interim standards (including methanol and CNG-fueled vehicles) will readily comply with the HCHO standards. In fact, based upon a review of certification data, we believe that gasoline and diesel vehicles will be far below the HCHO standards, perhaps by as much as 90%. (See the Response to Comments document for details)
To reduce testing costs while harmonizing with the CalLEV II standards we are finalizing a provision that will permit manufacturers of gasoline and diesel vehicles to demonstrate compliance with the formaldehyde standards based on engineering judgement. This provision will apply only to diesel and gasoline fueled vehicles and will require manufacturers to make a demonstration in their certification application that vehicles having similar engine and vehicle size and engine and aftertreatment technologies have been shown to exhibit compliance with the applicable formaldehyde standard for their full useful life. This demonstration will be similar to that currently required for gasoline vehicles to demonstrate compliance with the particulate matter standard (see 40 CFR 86.1829(b)(1)), and should be readily available from California vehicles where NMOG testing is required and formaldehyde data is routinely generated.
We proposed to adopt tighter PM standards. For Tier 2 vehicles, we proposed PM bin values such that PM would consistently be 0.01 g/mi or less. To provide manufacturers with flexibility, we proposed a 0.02 g/mi PM standard for vehicles that certify to the highest Tier 2 bins. As we have indicated elsewhere in this preamble, we anticipate that low sulfur diesel fuel will be available by 2007 to enable diesel vehicles to utilize advanced diesel technologies and meet these PM standards.
For the interim standards we proposed a PM standard of 0.06 g/mi for the highest bins. We received considerable comment from manufacturers and others about the PM standards we proposed. In the final rule, we are raising the PM standard to 0.08 g/mi for bin 10. For HLDTs, manufacturers would likely have had to use advanced diesel technologies to attain our proposed interim standards and these technologies require low sulfur diesel fuel. Since we do not expect that fuel to be widely available until the 2006-2007 timeframe, we are raising the PM standard so that diesels are not barred from the interim program by a fuel situation beyond their manufacturers' control.
PM standards are primarily a concern for diesel-cycle vehicles, but they also apply to gasoline and other otto-cycle
The “useful life” of a vehicle is the period of time, in terms of years and miles, during which a manufacturer is formally responsible for the vehicle's emissions performance. For LDVs and LDTs, there have historically been both “full useful life” values, approximating the average life of the vehicle on the road, and “intermediate useful life” values, representing about half of the vehicle's life. We proposed and are finalizing several changes to the current useful life provisions for LDVs and LDTs.
We are finalizing our proposal to equalize full useful life values for all Tier 2 LDVs and LDTs at 120,000 miles. Congress, in directing EPA to perform the Tier 2 study, also directed EPA to consider changing the useful lives of LDVs and LDTs. Manufacturers have made numerous advances in quality, materials and engineering that have led to longer actual vehicle lives and data show that each year of a vehicle's life, people are driving more miles. Current data indicate that passenger cars are driven approximately 120,000 miles in their first ten years of life. Trucks are driven further. Current regulatory useful lives are 10 years/100,000 miles for LDV/LLDTs and 11 years/120,000 miles for HLDTs. We project, based on our Tier 2 model, that approximately 13 percent of light-duty NO
We proposed to extend the useful life of interim LDV/LLDTs to 10 years/ 120,000 miles beginning in 2004. Based upon extensive comment, we are not finalizing that provision and the useful lives of interim LDV/LLDTs will remain unchanged to help facilitate their carryover from the NLEV program into the interim program. Commenters provided persuasive argument that the proposed provision, along with others, would impose a large workload burden on manufacturers because they would be unable to carry over certification data from 2003 and would have to recertify virtually all of their LDV/LLDTs in 2004. Manufacturers stressed that this would be an especially unproductive use of their resources because these vehicles would all have to be recertified again as they were phased into the Tier 2 standards between 2005 and 2007. This change in the final rule will have only minimal impact on the benefits of our program.
We are adopting as proposed a provision to provide additional NO
Today's vehicles are lasting longer and being driven farther than those built in past years and we believe it is reasonable to encourage the development of more durable emission control systems. Consequently we believe it is appropriate to provide incentives to manufacturers to certify their vehicles to extended useful lives beyond 120,000 miles. This is why we proposed and are today finalizing additional NO
In the final rule we are adding an option that, for a test group certified to a 150,000 mile useful life, the manufacturer may choose between the additional credits or a waiver of intermediate life standards. Commenters suggested that some vehicles would be discriminated against by our intermediate life standards, because they might have flat deterioration curves, and could meet our full life standards, but not the lower intermediate life standards. We are reluctant to give up our intermediate life standards, because we believe they provide an additional measure of certainty that vehicles will meet standards. Nonetheless, we believe that certification to a longer useful life is an important goal and that manufacturers who do so will likely use technologies that have very flat deterioration curves. This option provides manufacturers with the flexibility to certify vehicles without having to comply with intermediate life standards. In exchange they must comply with full life standards for considerably longer mileage.
Supplemental Federal Test Procedure (SFTP) standards require manufacturers to control emissions from vehicles when operated at high rates of speed and acceleration (the US06 test cycle) and when operated under high ambient temperatures with air conditioning loads (the SC03 test cycle). The existing light duty SFTP requirements begin a three year phase-in in model year 2000 for Tier 1 LDV/LLDTs.
The NLEV program includes SFTP requirements for LDVs, LDT1s and LDT2s. These requirements impose the Tier 1 intermediate and full useful life SFTP standards on Tier 1 and TLEV vehicles, but impose only 4000 mile standards adopted from California LEV I program on LEVs and ULEVs.
NLEV SFTP standards for LEVs and ULEVs are shown in Table V.A.-2. Table V.A.-2 also includes the California LEV I SFTP standards for LDT3s and 4s. The standards in that table do not provide for a weighted standard for NMHC+ NO
Since no significant numbers of vehicles certified to SFTP standards will enter the fleet until 2001, manufacturers raised concerns during the development of the NPRM regarding significant changes to the SFTP program before its implementation. We stated in the NPRM that it was reasonable not to increase SFTP stringency beyond NLEV/CalLEV I levels for the Tier 2 program, but we proposed to include SFTP standards adjusted for intermediate and full useful life deterioration where there are currently only 4000 mile standards.
Full useful life standards for Tier 2 vehicles are consistent with our mandate under the Clean Air Act. We derived the full and intermediate useful life standards in the NPRM by applying deterioration allowances from our draft MOBILE 6 model to the existing 4000 mile standards for LDVs and LLDTs. For HLDTs we applied similarly derived deterioration allowances to California's LEV I SFTP standards for MDV2s and MDV3s, which are the corresponding categories to LDT3s and LDT4s in the California LEV I program. The full and intermediate useful life SFTP standards we proposed would have applied to all Tier 2 vehicles including Tier 2 LDT3s and LDT4s. Further, since our interim standards are derived from NLEV and Cal LEV I standards, we proposed that our full life SFTP standards would apply to all interim LDV/LLDTs beginning in 2004.
Based upon extensive comment from manufacturers, we are persuaded that our proposed intermediate and full life SFTP standards need more review and should possibly be reexamined in a separate rulemaking. Manufacturers were quite concerned that the technique we used to obtain the intermediate and full life SFTP standards led to standards that were overly stringent. They argued that they have little experience with SFTP compliant vehicles given the current infancy of the program and they do not know whether SFTP emissions can be reasonably be expected to deteriorate like FTP emissions. Consequently, in today's notice, we are finalizing a program that will adopt the existing NLEV/Cal LEV I 4000 mile standards and utilize adjusted full life standards from the Tier 1 program, instead of values derived by applying the draft MOBILE 6 model.
These standards will apply to all Tier 2 vehicles and to all interim LDV/LLDTs. We proposed and are finalizing that interim HLDTs meet Tier 1 SFTP standards which do not finish their phase-in until the 2004 model year.
With regard to intermediate and full life SFTP standards, the preamble to the final rule implementing the SFTP program for the Tier 1 SFTP emission standards (61 FR 54856) provided a formula for computing SFTP standards to apply under more stringent future
In today's final rule, we will employ this formula to compute full useful life SFTP standards for all Tier 2 vehicles and for interim LDV/LLDTs. Because we are also adopting the California 4000 mile SFTP standards for these vehicles, we are not adopting intermediate life SFTP standards, so as to avoid the burden of three sets of SFTP standards.
LDT3 and LDT4 SFTP standards do not currently apply to diesels. Further, the standards applicable to Tier 1 diesel LDVs and LDT1s are less stringent than gasoline standards and do not apply to the SC03 cycle. There are no SFTP standards under Tier 1 for diesel LDT2s. In this final rule, we are applying the same approach we are using with other standards in this document to the Tier 2 and interim SFTP standards. Consequently, we are finalizing that Tier 2 vehicles and interim LDV/LLDTs with diesel or gasoline engines must comply with the same NMHC+NO
Because we lack certainty as to whether diesel vehicles can comply with the 4,000 mile SFTP standards for gasoline vehicles that we are adopting from the NLEV and Cal LEV I programs, we are providing an option that diesel LDV/LLDTs may comply with intermediate life SFTP standards instead.
We requested comment on the appropriate SFTP PM standards for diesel vehicles. We suggested it would be appropriate to establish a margin above the applicable FTP PM standard to serve as the SFTP standard. EPA has implemented such margins in recent consent decrees, under which heavy-duty engine manufacturers have agreed not to exceed emission levels 1.25 times the applicable exhaust standards (including PM standards) when engines are operated over a wide range of operating conditions. We received comments in favor of an SFTP PM standard of 1.25 times the FTP standard and we received many comments from manufacturers against setting any SFTP PM standard until more data become available.
We believe it is reasonable to include an SFTP standard for PM. However, we are uncertain as to the technical appropriateness of the 1.25 value for passenger vehicles. Further, the 1.25 value would lead to an SFTP standard for PM that would not match the stringency of the other SFTP standards we are finalizing. Consequently, we are finalizing a procedure for computing diesel PM standards that is nearly identical to the procedure for computing weighted SFTP standards for NMHC+NO
To compute the SFTP PM standards, manufacturers will use the same formula described above for NMHC+NO
For HLDTs , we proposed and are finalizing that Tier 1 SFTP standards would apply through the interim program. because of the late start of SFTP phase-in for Tier 1 vehicles. We see no reason to impose SFTP PM standards on these vehicles during the interim period when their manufacturers will be under pressure to develop diesel vehicles to comply with the Tier 2 standards. Also, if we were to impose an FTP PM standard on the interim vehicles, it would likely be matched to the interim phase in for HLDTs and manufacturers would simply defer compliance for diesels until the last phase-in year (2007). The manufacturers would then have to recertify to the Tier 2 standards by 2009. Given the relatively small number of diesel vehicles, we believe the most reasonable approach is to defer SFTP PM standards for HLDTs until the Tier 2 phase-in. Consequently, we are finalizing that Tier 2 HLDTs will have to comply with an SFTP PM standard computed as described above.
For LDV/LLDTs we are also including the SFTP PM standard for the Tier 2 vehicles. There are only a few diesel LDV/LLDTs currently produced and no large increase in their numbers is expected. We see little environmental benefit in imposing the SFTP PM standard on interim vehicles.
We are very concerned about “off cycle” emissions,
Historically, HLDTs (LDT3s and LDT4s) have been emission tested at their adjusted loaded vehicle weight (ALVW), while LDVs, LDT1s, and LDT2s have been tested at their loaded vehicle weight (LVW). ALVW is equivalent to the curb weight of the truck plus half its maximum payload, while LVW is equivalent to the curb weight of the truck plus a driver and one adult passenger (300 pounds). As we are equalizing standards and useful lives across LDVs and all categories of LDTs, we believe it is appropriate to test all the vehicles under the same conditions. Therefore, we are finalizing as proposed to test HLDTs at their loaded vehicle weight. We believe this is appropriate because the standards we are imposing on HLDTs under Tier 2 are considerably more stringent than the Tier 1 standards. Further, one of our reasons for bringing HLDTs under the same standards as passenger cars is that these trucks include many vans and sport utility vehicles that are often used as passenger cars with just one or two passengers. Lastly, we note that testing HLDTs at LVW is consistent with the way they have been tested for fuel economy purposes for many years. Consequently, we believe it is appropriate to test them at LVW.
The NPRM proposed that all HLDTs would certify using LVW beginning in the 2004 model year. Based upon comments, the final rule will allow the certification of HLDTs based on ALVW until those vehicles are phased into the Tier 2 standards in 2008 and 2009 at which time they must be tested at LVW. This will enhance carryover of California vehicles to the Federal interim program in cases where the California vehicles meet our interim standards.
As discussed elsewhere in this preamble, the NLEV program was adopted virtually in its entirety from California's program. Because California's standards were developed around the use of California Phase II reformulated gasoline (RFG) as the exhaust emission test fuel, we adopted California Phase II test fuel as the exhaust emission test fuel for gasoline-fueled vehicles in the federal NLEV program, although we recognized at the time that vehicles outside of California would be unlikely to operate on that fuel in use. In the NPRM we proposed interim programs that were derived from NLEV (for LDV/LLDTs) and the CAL LEVI program (for HLDTs), and we proposed to accept certification test results generated on California fuel, but indicated that we might test or require in-use testing on federal fuel.
Based upon comment we are finalizing provisions to permit, for interim vehicles, that if a test group has been certified to the exhaust emission standards using California fuel and is being carried into the interim program from NLEV or is being carried across from California LEV I certification, then we will not test or require in-use exhaust testing on federal fuel. This change is intended to help address recertification workload concerns raised by manufacturers. For new certification not carried across from California LEV I or carried over from NLEV, and for any Tier 2 vehicles, we will accept exhaust certification test results based on California fuel for 50 state vehicles only, but we will reserve the right to perform or require certification confirmatory testing and in-use testing on federal test fuel.
We recognize that manufacturers may want to perform calibration changes on vehicles carried across from the California LEV I program or carried over from NLEV program. These calibration changes will likely be aimed at certifying the test group to the lowest possible NO
Because differences exist between the California and federal evaporative emission testing procedures, we proposed to continue to require the use of federal certification fuel as the test fuel in evaporative emission testing. Under current programs, where California and federal evaporative emission standards are essentially the same, California accepts evaporative results generated on the federal procedure (using federal test fuel), because available data indicates the federal procedure to be a “worst case” procedure. The evaporative standards California has adopted for their LEV II program are more stringent than those we are finalizing in this document. In the NPRM, we requested comment and supporting emission test data on whether vehicles certified to CalLEV II evaporative standards using California fuels will necessarily comply with the federal Tier 2 evaporative standards, including ORVR standards, when tested with federal test fuel. While we got comments from manufacturers advocating that we accept the results of California evaporative testing to demonstrate compliance with the federal evaporative standards, we received no supporting data. Still, given the fairly large difference between California and federal evaporative standards, it seems reasonable that a vehicle meeting the California standards under California fuels and test conditions might also meet federal standards under federal fuels and conditions. We believe it may be possible for manufacturers to establish a relationship between the two sets of standards, fuels and conditions that would enable us to grant federal certification based upon data showing conformity with the California standards under California fuels and conditions. Consequently, we are including a provision in the certification regulations to enable manufacturers to obtain federal evaporative certification based upon California results, if they obtain advance approval from EPA. EPA will review test data from manufacturers to establish whether it is appropriate to accept California data to demonstrate compliance with federal standards.
Current certification procedures, including regulations under the new CAP2000 program,
We have reviewed data indicating that the permeability, and therefore the evaporative losses, of hoses and other evaporative components can be greatly increased by exposure to fuels containing alcohols.
Alcohols do not impact evaporative components and hoses immediately, but rather it may take as long as one year of exposure to alcohol fuels for permeation rates to stabilize. The end result is higher permeation and increased in-use evaporative emissions.
Today, roughly 10% of fuel sold in the U.S. contains alcohol, mainly in the form of ethanol, and such fuels are often offered in ozone nonattainment areas. We believe it is appropriate to ensure that evaporative certification processes expose evaporative components to alcohols and do so long enough to stabilize their permeability. Therefore, we are finalizing our proposal to the evaporative certification requirements to require manufacturers to develop their deterioration factors using a fuel that contains the highest legal quantity of ethanol available in the U.S.
To implement this change, we are modifying the Durability Demonstration Procedures for Evaporative Emissions found at § 86.1824-01. The amendments will require manufacturers not using an approved option, to age their systems using a fuel containing the maximum concentration of alcohols allowed by EPA in the fuel on which the vehicle is intended to operate,
We requested comment on alternative ways by which manufacturers could document or demonstrate that their components are made of materials whose permeability is not significantly affected by alcohols. We received no comments responsive to this request, but we did receive comments that EPA should not change the CAP2000 provision allowing manufacturers to develop their own durability process for calculating evaporative emission deterioration factors “using good engineering judgement”. We do not wish to foreclose the possibility that an alternative method may exist or may arise in the future. Consequently, in the final rule we will permit manufacturers to use an optional method based on good engineering judgement acceptable to EPA. As an example, one method would be for the manufacturer to show that it is exclusively using materials documented in the technical literature to have low permeability in the presence of alcohols.
California's LEV II program implements a number of minor changes to exhaust emissions test procedures. We have evaluated these changes and found that, for tailpipe emissions, the California test procedures fall within ranges and specifications permitted under the Federal Test Procedure.
With regard to hybrid electric vehicles (HEVs) and zero emission vehicles (ZEVs), we believe that these vehicles will be predominantly available in California, or that they will typically be first offered for sale in California, because of California's ZEV requirement, which promotes the sale of HEVs and ZEVs. Where manufacturers market HEVs or ZEVs outside of California, it is likely that they will market the same vehicles in California. Consequently, we are finalizing our proposal to incorporate by reference California's exhaust emission test procedures for HEVs and ZEVs.
In the NLEV program, we provided a specific formula used by California that could be used to compute an HEV contribution factor to NMOG emissions. This formula took into consideration the range without engine operation of various types of HEVs and had the effect of reducing the NMOG emission standard for a given emission bin (for HEV vehicles only). This would have obvious beneficial effects on a manufacturer's calculation of its corporate NMOG average.
The technology of HEVs is under rapid change and we do not believe that we can design a formula now that will accurately predict the impact of HEVs on corporate average NO
These factors will be based on good engineering judgement and will consider such vehicle parameters as vehicle weight, the portion of the time during the test procedure that the vehicle operates with zero emissions, the zero emission range of the vehicle, NO
The final NLEV rule (
The issue of RAFs is relevant primarily to alcohol and CNG-fueled vehicles. RAFs are not relevant at all if a manufacturer elects to use NMHC data to show compliance with the NMOG standards. While, in our final rule, alcohol and CNG vehicles will have to comply with NMOG standards beginning in 2004 and while we desire to harmonize with California when practical and reasonable, we will not permit the use of RAFs for Tier 2 vehicles and interim non-Tier 2 vehicles. We note that we are finalizing a provision from the NPRM that permits dual fueled and flexible fueled vehicles to elect an NMOG value from the next higher bin when they are tested on an alternative fuel. This provides flexibility in compliance with applicable NMOG standards for these vehicles. We do not believe that dedicated alcohol or CNG vehicles should have any problems complying with the NMOG standards we are finalizing and consequently the relief these vehicles might get when RAFs are employed is unnecessary.
In its LEV II program, California is also implementing a number of changes to evaporative emission test procedures.
Our final rule includes the following flexibilities intended to assist all manufacturers in complying with the stringent proposed standards without harm to the program's environmental goals as presented in the NPRM:
• A four year phase-in of the standards for LDV/LLDTs;
• A delayed phase-in for HLDTs;
• The freedom to select from specific bins of standards;
• A standard that can be met through averaging, banking and trading of NO
• Provisions for NO
• Provisions for alternative phase-in schedules.
These flexibilities apply to all manufacturers, regardless of size, and in general we believe they eliminate the need for more specific provisions for small volume manufacturers.
As explained in the NPRM, we will continue to apply the federal small volume manufacturer provisions, which provide relief from emission data and durability showing and reduce the amount of information required to be submitted to obtain a certificate of conformity. In addition, the CAP2000 program contains reduced in-use testing requirements for small volume manufacturers.
Exempting small volume manufacturers from the Tier 2 and interim HLDT phase-in requirements eliminates a dilemma that phase-in percentages can pose to a manufacturer that has a limited product line,
We requested comment in the NPRM as to whether ICIs should be exempted from the interim and Tier 2 fleet average NO
Since we do not believe it is wise to finalize a provision that could lead to an inequity like this, and since averaging may not be workable for ICIs, we are finalizing that ICIs must comply with the standards from the bin that contains the relevant fleet average NO
We do not believe that ICIs can predict or estimate their sales of various vehicles well enough to participate in a program that will allow them leeway to produce some vehicles to higher bins now, knowing that they will sell vehicles from lower bins later. We also do not believe that we can reasonably assume that an ICI that certifies and produces vehicles one year, will certify or even be in business the next, consequently, we are also not permitting ICIs to utilize the deficit carryforward provisions of the rule.
Essentially, ICIs will be allowed the major benefits of the averaging, banking and trading program, but will be constrained from getting into a situation where they can ever produce vehicles to higher bins that they can not cover with credits at the time they produce the vehicles.
The panel convened under the Small Business Regulatory Enforcement Fairness Act recommended that we seek comment on the inclusion of a hardship provision. We requested comment on whether we should include such a provision in the NPRM. Based upon comment, we are including a limited hardship provision in the final rule that will be applicable to small volume manufacturers.
Small volume manufacturers include companies that independently import motor vehicles (Independent Commercial Importers or ICIs), companies that modify vehicles to operate on alternative fuels, companies that produce specialty vehicles by modifying vehicles produced by others, and companies that produce small quantities of their own vehicles, but rely on major manufacturers for engines and other vital emission related components. In these businesses, predicting sales is difficult and it is often necessary to rely on others for technology.
This provision will provide limited relief in the case where a small volume manufacturer is unable to comply with the phase-in dates or average NO
Appeals for hardship relief must be made in writing, must be submitted before the earliest date of noncompliance, must include evidence that the noncompliance will occur despite the manufacturer's best efforts to comply and must include evidence that severe economic hardship will be faced by the company if the relief is not granted. Hardship relief will only be granted for the first year after a new standard is finally implemented. For small volume manufacturers, which are already exempted from the phase-in schedules for the interim and Tier 2 programs, this means that relief would be available for the final phase-in year for the LDV/LLDT Tier 2 phase-in (2007), for the final phase-in year for the interim HLDT phase-in (2007), and the final phase-in year for the Tier 2 HLDT phase-in (2009). Relief will also be available for manufacturers that did not opt into NLEV and must meet our interim standards for all their LDV/LLDTs in 2004, and relief will be available for HLDTs and MDPVs which must be brought under our interim program in the 2004 model year.
We will work with the applicant to ensure that all other remedies available under this rule, e.g., use of banked or purchased credits, are exhausted before granting additional relief, and will limit the period of relief to one year. Note that in our discussion of the credit deficit carryforward provision in section IV.B.4.d.vi, we indicate that we are not permitting small volume manufacturers to carry deficits forward until they have demonstrated compliance with the NO
To avoid this provision creating a self-implementing problem, by which the very existence of the hardship provision prompts small volume manufacturers to delay development, acquisition and application of new technology, we want to make clear that we expect this provision to be rarely used. Our final rule contains numerous flexibilities for all manufacturers and it waives the phase-in steps for small volume manufacturers, which effectively provides them more time. We expect small manufacturers, to prepare for the applicable implementation dates in today's rule.
The CAP2000 program (64 FR 23905, May 14, 1999) streamlines and simplifies the procedures for certification of new vehicles and will also require manufacturers to test in-use vehicles to monitor compliance with emission standards. The CAP2000 program was developed jointly with the State of California and involved considerable input and support from manufacturers. As the name implies, it can be implemented as early as the 2000 model year.
We are finalizing our proposal that the Tier 2 and the interim requirements will be implemented subject to the requirements of the CAP2000 program. Certain CAP2000 requirements are being slightly modified to reflect changes to useful lives, standard structure and other aspects of the Tier 2 program, but we proposed no major changes to fundamental principles of the CAP2000 program, and we are not adding any major changes with today's final rule.
Although we proposed changes to useful lives, we did not propose to amend the 50,000 mile minimum mileage used in manufacturer in-use verification testing or in-use confirmatory testing under the CAP2000 program at this time. The CAP2000 in-use program is not yet implemented and we believe it is appropriate to allow manufacturers to gain experience with procuring and testing vehicles at the 50,000 mile level before making significant changes. However, where one vehicle from each in-use test group would have a minimum mileage of 75,000 miles under the CAP2000 program, we proposed and are finalizing, consistent with California, to
We may, in our own in-use program, procure and test vehicles at mileages higher than 50,000 and pursue remedial actions (e.g., recalls) based on that data. We may also use that data as the basis to initiate a rulemaking to make changes in the CAP2000 in-use requirements, if the data indicate significant non-conformity at higher mileages.
We are finalizing certification test fuel specifications consistent with our final fuel sulfur requirements. Given the phase-in for low sulfur fuel we are finalizing in this rulemaking, we recognize that 2004 to 2007 vehicles (and vehicles certified in earlier model years to bank early NO
Consistent with our approach under the NLEV program, we will consider requests from manufacturers to permit OBD systems that function properly on low sulfur fuel, but exhibit sulfur-induced passes when operated on higher sulfur fuel. For OBD systems that exhibit sulfur-induced indicator light illumination, we will consider requests to modify such vehicles on a case-by-case basis.
We plan no new compliance monitoring activities or programs for Tier 2 vehicles. These vehicles will be subject to the certification and manufacturer in-use testing provisions of the CAP2000 rule. Also, we expect to continue our own in-use testing program for exhaust and evaporative emissions. We will pursue remedial actions when substantial numbers of properly maintained and used vehicles fail any standard in either in-use testing program.
Consistent with our approach under NLEV we will consider requests, prior to manufacturer or EPA in-use testing to permit preconditioning procedures designed solely to remove the effects of high sulfur gasoline on vehicles produced through the 2007 model year.
We retain the right to conduct Selective Enforcement Auditing of new vehicles at manufacturer's facilities. In recent years, we have discontinued SEA testing of new LDVs and LDTs, because compliance rates were routinely at 100%. We recognize that the need for SEA testing may be reduced by the low mileage in-use testing requirements of the CAP2000 program. However, we expect to re-examine the need for SEA testing as standards tighten under the NLEV, interim, and Tier 2 programs.
We have established a data base to record and track manufacturers' compliance with NLEV requirements including the corporate average NMOG standards. We expect to monitor manufacturers' compliance with the Tier 2 and interim corporate average NO
The Tier 2 standards will be challenging for manufacturers to achieve, and some vehicles will pose more of a challenge than others. Not only will manufacturers be responsible for assuring that vehicles can meet the standards at the time of certification, they will also have to ensure that the vehicles comply when self-tested in-use under the provisions of the CAP2000 program, and when tested by EPA under its in-use (“Recall”) test program.
With any new technology, or even with new calibrations of existing technology, there are risks of in-use compliance problems that may not appear in the certification process. In-use compliance concerns may discourage manufacturers from applying new technologies or new calibrations. Thus, we proposed and are finalizing, relaxed in-use standards for those bins most likely to require the greatest applications of effort, to provide assurance to the manufacturers that they will not face recall if they exceed standards by a specified amount.
For the first two years after a test group meeting a new standard is introduced, that test group will be subject to more lenient in-use standards. These “in-use standards” will apply only to bin 5 and below, only for the pollutants indicated, and only for the first two model years that a test group is certified under that bin. The in-use standards will not be applicable to any test group first certified to a new standard after 2007 for LDV/LLDTs or after 2009 for HLDTs.
The temporary in-use standards are shown in Table V.A.-3 below.
Because we are concerned that diesel vehicles may require low sulfur fuel to comply with our interim requirements and that such fuel may not be widely available until the 2006-2007 timeframe, we are providing in-use standards specifically for diesel vehicles certified to bin 10 standards. These standards will be determined by multiplying the applicable NO
We believe manufacturers should and will strive to meet certification standards for the full useful lives of the vehicles, but we recognize that the existence of such in-use standards poses some risk that a manufacturer might aim for the in-use standard in its design efforts rather than the certification standard, and thus market less durable designs. We do not believe that risk to be significant. We believe that such risks are more than balanced by the gains that can result from earlier application of new technology or new calibration techniques that might occur in a scenario where in-use liability is slightly reduced. Further, we believe that the in-use standards will be of short enough duration that any risks are minimal.
We are finalizing, as proposed, that manufacturers can either report that they meet the relevant corporate average NO
The averaging, banking and trading program will be enforced through the certificate of conformity that the manufacturer must obtain in order to introduce any regulated vehicles into commerce. The certificate for each test group will require all vehicles to meet the applicable Tier 2 emission standards from the applicable bin of the Tier 2 program, and will be conditioned upon the manufacturer meeting the corporate average NO
As outlined in detail in the preamble to the final NLEV rule, EPA will review the manufacturer's sales to designate the vehicles that caused the exceedance of the corporate average NO
During phase in years, the certificates will also require manufacturers to meet the applicable phase-in requirements. Compliance with the phase-in requirements will be enforced in the same manner as for the corporate average NO
We will also condition certificates to enforce the requirements that manufacturers not sell NO
In the case of a trade that results in a negative credit balance that a manufacturer could not cover by the reporting deadline for the model year in which the trade occurred, we proposed, and are finalizing, to hold both the buyer and the seller liable. This is consistent with other mobile source rules, except for the NLEV rule as discussed below. We believe that holding both parties liable will induce the buyer to exercise diligence in assuring that the seller has or will be able to generate appropriate credits and will help to ensure that inappropriate trades do not occur.
In the NLEV program we implemented a system in which only the seller of credits would be liable. In the preamble to the final NLEV rule (
The NLEV program was implemented to be a relatively short duration program, during which time we could expect relative stability in the industry. Also, given that NLEV is a voluntary program of lower than mandated standards, we did not expect that the smallest manufacturers would opt in. These are the companies whose stability is most in jeopardy in a dynamic and very competitive worldwide business.
We currently believe that the Tier 2 program and its framework will remain for many years. We note that the program is not scheduled for complete phase-in for almost nine years after the publication of today's rule. All manufacturers, large and small, will ultimately have to meet the Tier 2 standards. We cannot predict that in the Tier 2 timeframe there will not be companies that leave the market or are divided between other companies in mergers and acquisitions. Thus we believe it is prudent to implement a program to provide inducements to the seller to assure the validity of any credits that it purchases or contracts for.
Compliance with the current and proposed EPA motor vehicle emission standards is based on the emission performance of a vehicle over EPA's prescribed test procedure. While this test procedure addresses many of the aspects of a vehicle's impact on air quality, it does not address all such impacts. EPA is aware of two developing technologies which have potential to improve ozone-related air quality, but that would not do so over the current EPA test procedure.
The first example is a device that removes ozone from the air as the vehicle is driven. A major producer of automotive catalysts, Englehard, has developed a catalytic coating for vehicle radiators (called PremAir) that converts ambient ozone to oxygen. ARB has been working with Englehard for some time to develop a procedure which would grant PremAir and other direct ozone reducing technologies a NMOG credit under its LEV I and LEV II programs. ARB issued on December 20, 1999 a Manufacturers Advisory Circular outlining procedures for establishing such a NMOG credit.
Englehard submitted substantial comments to the Tier 2 NPRM, including ozone modeling results for five cities (Los Angeles, Houston, Atlanta, New York City, and Chicago). This ozone modeling compared the ozone reductions from reduced exhaust VOC and NO
The second example is an insulated catalyst. The insulation retains heat for extended periods of time, increasing the catalyst temperature when the engine is started and reducing the time required for the catalyst to reach an operational temperature. This technology can reduce cold start emissions for engine off times (called soaks) of 24 hours or less. The vast majority of engine soaks in-use are less than 24 hours. However, EPA's test procedure only tests emissions at two fairly extreme soak times: 10 minutes and 12-36 hours. The 10 minute soak is so short that even an uninsulated catalyst is warm enough to quickly begin working upon restart. The 36 hour soak is beyond the practical limit of cost-effective insulating techniques. As a result of the Tier 2 NPRM, EPA received a number of inquiries from potential manufacturers of insulated catalysts, requesting further information about emission credits, test procedures and certification requirements.
EPA believes that both of these technologies, as well as other potential technologies, will reduce regulated emissions and/or ambient ozone levels, as long as they operate as designed in-use. EPA will work with the developers of such technologies to establish regulatory procedures to determine whether it is appropriate to grant emission credit for particular technologies. This process will involve the opportunity for public notice and comment.
With regard to Englehard's PremAir technology, EPA specifically requested comments on ARB's proposed approach to determining an NMOG credit and received no adverse comment on granting this type of technology a VOC emission credit. Thus, EPA is promulgating today procedures very similar to ARB's for certifying such technologies and determining the appropriate VOC emission credit. The only difference between EPA's and ARB's procedures involve assessing the effectiveness of VOC emission reductions and ozone reducing devices in areas outside of California.
In summary, the ozone reductions associated by both the ozone reducing technology, such as PremAir, and exhaust VOC emission reductions will be estimated using urban airshed modeling, using up-to-date chemical and meteorological simulation techniques. Four local areas shall be modeled: New York City, Chicago, Atlanta and Houston. The ozone episodes to be modeled shall be those selected by the states for use in their most recent ozone SIPs. Emissions shall be projected for calendar year 2007. Baseline emissions will include the benefits of the Tier 2 and sulfur standards being promulgated today, as well as all other emission controls assumed in EPA's ozone modeling of the benefits of the Tier 2 and sulfur standards described above. The ozone benefit of VOC emission reductions will be modeled by assuming that Tier 2 LDVs and LDTs meet a 0.055 g/mi exhaust NMOG standard instead of a 0.09 g/mi NMOG standard. The relationship between changes in exhaust NMOG emission standards and in-use VOC emissions shall be determined by modeling LDV+LDT emission in 2030 assuming that all Tier 2 vehicles meet a 0.055 g/mi exhaust NMOG standard instead of a 0.09 g/mi NMOG standard. All emission modeling shall utilize the updated Tier 2 emission model developed by EPA as part of this rule, or MOBILE6, once it is available. The measure of ozone to be used in calculating VOC emission equivalency will be the peak one-hour ozone level anywhere in the modeled region on the day when ozone is at its highest. The NMOG credit will be determined by averaging the NMOG credit determined in each of the four local areas.
Simulation of the benefits of the direct ozone reducing device will assume that ozone levels immediately around the roadway will be 40% less than that existing in the broader grid. The performance aspects of the direct ozone reducing device can be simulated by any reasonable values, since the appropriate NMOG credit for any specific application of this technology will be scaled to the performance of the specific application.
The manufacturer wishing to obtain an NMOG credit for use of this technology must demonstrate its effectiveness to EPA as part of the certification process. This will involve demonstrating the air flow through the device, its ozone destruction capability under conditions analogous to those photochemically modeled, the durability of this capability over the useful life of the vehicle and the method to be used to diagnose its effectiveness in-use.
Regarding the insulated catalyst technology, less information has been received to date on its performance. We are not promulgating regulations for determining the appropriate credit for such technology today. However, when we were developing our SFTP standards, EPA developed a methodology to assess the emission benefits of insulated catalysts or other techniques which reduced emissions after the vehicle soaks between 10 minutes and 12-36 hours. Thus, EPA expects to use this methodology as a starting point in assessing the benefit of insulated catalysts and will continue to assess development of options in this area. Because an insulated catalyst operates essentially like a typical catalyst, we do not expect that the test procedures for its certification would differ from those applicable to typical Tier 2 vehicles. The primary difference will be an assessment of its effectiveness relative to conventional catalyst technology over a range of vehicle soak times between 10 minutes and 36 hours. Then, it will be necessary to estimate the average effectiveness in-use relative to conventional technology using the in-use frequency of vehicle soak times.
The standards set forth in today's final rule are very stringent. They require extremely tight control of air/fuel ratios and also tight control of the inputs to the catalyst(s). A sealed exhaust system is crucial to the proper operation and emission control of current vehicles and even more so to the expected Tier 2 vehicles. Because a given point in the exhaust system intermittently sees negative pressure, exhaust leaks can permit air to enter the exhaust system. Even tiny amounts of air entering this way can have large impacts on the output of the oxygen sensor. If the output of the oxygen sensor is affected, then the exhaust output of the cylinders will be affected. Consequently, an exhaust leak can lead to both excess NO
In the preamble to the NPRM, we expressed our concerns about the impact of small exhaust leaks and requested comment on design or on-board monitoring measures we could finalize to ensure that exhaust systems were manufactured and installed in such a way that leaks are prevented. We also asked for comment on whether we should implement a provision that would require manufacturers to demonstrate through engineering analysis or design that the possibilities of exhaust leaks have been addressed.
Manufacturers indicated in their comments that they believe addressing exhaust leaks is unnecessary. We believe otherwise. Data we have seen suggest that very large emission effects can occur due to very small leaks. Consequently, we are finalizing a provision in today's rule that will require, as part of the certification process, for manufacturers to indicate that they have conducted an engineering analysis of the exhaust system. This
With regard to the concept of “facilitating leak-free repair”, we intend that manufacturers should ascertain that the exhaust system can be removed in a dealership or repair shop for repairs to the exhaust system itself or to other components of the vehicle and be able to be reassembled and reinstalled in a leak free manner using commonly available tools. It is not our intention that the concept of “facilitating leak-free repair” apply to situations of gross misuse, tampering or serious vehicle damage.
The EPA staff will continue to assess the emission control potential of vehicles powered by technologies such as lean-burn and/or fuel-efficient technologies, including diesel engines equipped with advanced aftertreatment systems, gasoline direct injection engines, and other technologies that show promise for significant advances in fuel economy and meeting the Tier 2 standards in the post-2004 time frame. In this assessment, we will maintain a “systems” perspective, considering the progress of advanced vehicle technologies in the context of the role that sulfur in fuels plays in enabling the introduction of these advanced technologies or maximizing their effectiveness.
We are finalizing, as proposed, to continue existing emission standards from Tier 1 and NLEV that apply to cold CO, certification short testing, refueling, running loss, and highway NO
The gasoline sulfur program promulgated today has many of the same features as the reformulated gasoline/conventional gasoline (RFG/CG) program, including refinery averaging, refinery and downstream level caps, and the generation and use of credits. These features raise similar compliance issues for both programs. As a result, the enforcement mechanisms of the gasoline sulfur rule generally track those of the RFG/CG rule, where applicable. Because low sulfur gasoline is necessary to avoid significant impairment of Tier 2 motor vehicle emissions technology, we believe measures are needed to assure that gasoline meets the standards promulgated in today's rule at the time the gasoline leaves the refinery gate or is imported, and to assure that the quality of the gasoline is maintained downstream of the refinery.
More specifically, today's rule includes the following provisions:
• Refiners and importers must test each batch of gasoline produced or imported for sulfur content and maintain testing records and retain test samples;
• Refiners and importers must submit reports regarding compliance with the average standards and credit provisions;
• Attest procedures
• Refiners and importers are prohibited from using, selling or purchasing invalid sulfur credits, and are required to adjust compliance calculations if invalid credits have been used, sold or purchased;
• Small foreign refiners subject to the small refiner standards described in section IV.C. above must comply with the rule's small refiner compliance requirements and other requirements to ensure the separation of such foreign gasoline from all other gasoline to the U.S. port of entry; any foreign refiners participating in the early credit generation program must also meet certain provisions concerning credit generation, including reporting and recordkeeping;
• All regulated parties in the gasoline distribution system who are downstream from the refiner or importer must comply with downstream sulfur cap standards;
• Regulated parties are subject to presumptive liability for violations at a party's own facility and for violations at other facilities that could have been caused by the regulated party; branded refiners are subject to liability for violations occurring at branded facilities.
• Refiners and distributors may implement downstream quality assurance testing to assure compliance and to establish an element of defense against presumptive liability.
As in other fuels programs, the sulfur standards apply to all motor vehicle fuel that meets the definition of gasoline, except for aviation fuel and racing gasoline, as was proposed in the NPRM. See 40 CFR 80.2(c). Gasoline sulfur standards apply, however, to gasoline that is ultimately used in nonroad equipment or marine engines.
As we noted in the NPRM, we are aware there are certain fuels, such as aviation fuel and racing fuel, that are generally segregated from gasoline throughout the distribution system. Where such fuels are segregated from motor vehicle gasoline and not made available for use in motor vehicles, the fuel is not subject to sulfur rule standards. However, if such fuels are not segregated throughout the distribution system, but are used as motor vehicle gasoline or are commingled with motor vehicle gasoline, then any person who introduces such fuels into the gasoline distribution system is a refiner, subject to all the refiner requirements of today's regulations, including registration, reporting, testing and meeting the national refiner average and cap standards for the volume of gasoline that person added to the distribution system. Today's rule adopts the provisions concerning fuel used for racing vehicles as proposed.
One commenter suggested that racing gasoline or aviation gas should be allowed to be used as motor vehicle gasoline by downstream parties so long as the racing gasoline or aviation gas does not exceed the applicable downstream cap standard. We disagree. Racing gas that meets the applicable downstream sulfur cap would nevertheless not be subject to the refinery gate cap or averaging standards, and may not meet such standards. Allowing such fuels to be distributed for motor vehicle use would thus circumvent the intent of the rule.
The rule promulgated today clarifies the definition of “refinery” at 40 CFR 80.2(h), as was proposed in the NPRM. We received no comments on this clarifying change. Specifically, section 80.2(h) now provides that “refinery”
In the NPRM we proposed that oxygenate blenders
While it is true that some of today's gasoline has a sulfur content as high as 1,000 ppm which if used as an ethanol denaturant results in ethanol having a sulfur content of 50 ppm, the average sulfur content of gasoline is about 300 ppm which if used as an ethanol denaturant results in ethanol with a sulfur content of 15 ppm. In addition, when the gasoline sulfur standards being promulgated today are in effect, the average sulfur levels of gasoline will be significantly reduced, which will further reduce the sulfur content of denatured ethanol to very low levels. For this reason, we are finalizing the regulation as proposed that oxygenate blenders are not subject to refiner sulfur standards.
However, if gasoline blendstock instead of finished gasoline is used as a denaturant for ethanol the oxygenate blender who adds the ethanol would become a “refiner,” who is required to demonstrate compliance with the sulfur standards for the denatured ethanol added to gasoline. This is because the oxygenate blender would be adding a blendstock along with the ethanol, which subjects the blendstock blender to refiner standards and requirements. Moreover, if the blendstock has a high sulfur content the denatured ethanol could have a sulfur content greater than 30 ppm, or even greater than 80 ppm, which could make compliance by such a “refiner” difficult or impossible. In addition, as discussed above, in certain cases ethanol is included in the refinery compliance calculations of the refiner who produced the gasoline or RBOB with which the ethanol is blended. Refiners assume this ethanol has no sulfur content, an assumption that could be incorrect if high sulfur blendstock is used as the denaturant.
For these reasons we believe it is important that ethanol blenders use denatured ethanol with a sulfur content of 30 ppm or less, which would occur if the current practice of using finished gasoline as ethanol denaturant continues. In order to ensure this result, the regulations include a provision that prohibits ethanol blenders from using denatured ethanol with a sulfur content greater than 30 ppm. We believe ethanol blenders can comply with this requirement through commercial arrangements with their ethanol suppliers, that specify the maximum sulfur content of denatured ethanol. In addition, ethanol blenders can assure compliance with this requirement by testing to determine the sulfur content of denatured ethanol received.
One commenter suggested that the Agency policy under the RFG/CG rule that allows certain imported gasoline to be treated as a blendstock by importer-refiners should be applied to today's rule. The GTAB policy was originally issued in the RFG Question and Answer document, and was subsequently published as part of a proposed RFG rulemaking in 1997.
We are aware that when gasoline meeting the requirements finalized in today's rule is transported through pipelines, there will be some situations where adjacent distillate product in the pipeline will mix with a portion of the gasoline to create an interface product, commonly referred to as transmix. This transmix may not be blended into the diesel fuel because the gasoline in the transmix may result in diesel fuel performance problems. Historically, this type of transmix product has either been blended into the gasoline, in limited concentrations, or the transmix has been separated into its gasoline and distillate components at a reprocessing plant. However, the practice of blending the transmix into gasoline may result in violations of the downstream standards for RFG, and such blending could violate the downstream sulfur caps finalized in today's rule, because many distillates have a very high sulfur content. Therefore, we believe regulatory provisions are needed to resolve these issues. We have not addressed transmix issues in today's rule because we have already proposed regulations regarding transmix blending and processing in another rulemaking.
Several commenters suggested the rule should include a provision, similar to the RFG rule provision at 40 CFR 80.73, to address situations where, due to extraordinary circumstances, a refiner or importer cannot produce or distribute conforming gasoline. Section 80.73 applies to refiners, importers and oxygenate blenders. Today's rule has adopted the provisions of section 80.73 for RFG and CG, for importers and refiners, but not for oxygenate blenders. This is because the gasoline sulfur program does not include provisions that would be expected to require oxygenate blender relief.
In the remainder of this section we discuss enforcement issues regarding today's rule that are not covered in this Overview or in section IV.C., above.
In the NPRM we proposed that standards for gasoline produced by foreign refineries that are not subject to small refiner individual refinery standards would be met by the importer. Standards for gasoline produced by a foreign refinery subject to an individual sulfur rule standard would be met by the foreign refinery, with certain limited exceptions as provided in the foreign refinery provisions. The rule promulgated today adopts the provisions as proposed, except for several changes aimed at clarifying the proposed requirements, changes relating to the temporary relief provision, and changes relating to foreign refiners' participation in the early credit program. These provisions are very similar to the foreign refinery provisions of the RFG/CG rule.
Under the RFG/CG rule, EPA promulgated regulations
In the NPRM, we proposed similar requirements for compliance with the applicable sulfur standards that would apply to any foreign refiner who demonstrates that it meets the sulfur program's small refiner criteria. We proposed that foreign refinery baselines would be based on annual average sulfur levels and the volume of gasoline imported to the U.S. during the same baseline period as would be applicable to domestic small refiners. In today's final rule we have also adopted provisions for foreign refiners to establish baselines to participate in the early credit generation program, and to request temporary relief. Any foreign refiner who obtains a foreign refinery gasoline sulfur baseline would be subject to the same requirements as domestic refiners with individual refinery baselines under today's rule. Additionally, provisions similar to the provisions at 40 CFR 80.94 would apply, which include:
• Segregating gasoline produced at the small refinery until it reaches the U.S.;
• Refinery registration;
• Controls on product designation;
• Load port and port of entry testing;
• Attest requirements; and
• Requirements regarding bonds and sovereign immunity.
The rationale for these enforcement provisions is discussed more fully in the Agency's preamble to the final RFG/CG foreign refineries rule (62 FR 45533 (Aug. 28, 1997)).
Several commenters suggested that the rule should have even stronger enforcement provisions concerning foreign refiners, including criminal provisions against foreign individuals who violate the requirements of the rule. While we agree that the rule's enforcement provisions pertaining to foreign refiners must be effective, we believe the proposed enforcement provisions are sufficient, and that attempts to further strengthen them would not significantly increase their overall effectiveness. Today's rule imposes various requirements on foreign refiners not required of domestic refiners, as noted above, which we believe are more effective for ensuring environmental compliance than criminal provisions would be for foreign individuals, in light of the potential difficulties of enforcing sanctions against foreign individuals. EPA's experience to date with the similar RFG/CG requirements under section 80.94 of the RFG/CG rule does not indicate the provisions are inadequate.
Therefore, today's rule generally retains these provisions as proposed. The final rule makes several technical changes, including changes regarding baselines for foreign refiners, to be consistent with the requirements for domestic small refiners and refiners generating early credits finalized in today's rule. The rule's foreign refiner enforcement provisions now also apply to foreign refiners participating in the early credits program, and to the use of credits by foreign small refiners.
One commenter stated that the language of the proposed § 80.410(n) would be too broad in that prohibiting any “person” from combining certified small foreign refiner gasoline with non-certified small foreign refiner gasoline or with certified small foreign refinery gasoline produced at a different refinery would prohibit even retail level commingling of such products. This was not intended and today's rule clarifies that such commingling can occur subsequent to importation.
Under the proposal, when the small refiner standards sunset (and additionally under today's rule, when the temporary refiner relief provisions sunset),
Today's final rule adopts the proposed requirement for importers to sample and test each batch of gasoline imported. However, as noted in the preamble to the NPRM, for parties that import gasoline into the U.S. by truck, the every-batch testing requirement would include testing the gasoline in each truck compartment, or if the gasoline is homogeneous, testing the gasoline in the truck.
In the NPRM we recognized that this every-batch testing requirement may not be feasible for truckers hauling many small loads of gasoline, and we therefore proposed a limited alternative approach for truck importers in lieu of every-batch testing. The proposed alternative approach is based on the importer meeting the 30 ppm sulfur standard on a per-gallon basis. Under this alternative approach, the importer would be allowed to rely on the sulfur results based on sampling and testing conducted by the operator of the foreign truck loading terminal. Because, in most cases, the terminal operator will not be subject to United States laws, we also proposed safeguards intended to ensure that the gasoline in fact meets the applicable standard. This includes the requirement that the importer conduct a quality assurance sampling and testing program independent from the sampling and testing conducted by the terminal. Under this approach the reporting requirements would be minimized since no averaging would be required. The environmental consequences of this approach would be neutral, because by meeting the 30 ppm sulfur standard on an every-gallon basis the standard also would be met on average.
One commenter stated that the 30 ppm per-gallon standard would be difficult for truck importers to meet due to the fact that Canadian terminals may not always have gasoline with a sulfur content no greater than 30 ppm. The commenter suggested that truck importers be allowed to rely on testing conducted by the foreign gasoline terminal, as discussed above, to meet the average and cap standards like other importers.
We agree that truck importers may have difficulty obtaining gasoline that meets the 30 ppm sulfur standard on a per-gallon basis. Under Canadian regulations, Canadian refiners will be subject to a 150 ppm average standard and a 300 ppm cap in 2004, and in 2005 Canadian refiners will be subject to a 30 ppm average standard and an 80 ppm
While today's rule retains the proposed alternative, with some modifications, it also provides a second alternative approach. Under this second approach, truckers are allowed to meet the national average and cap applicable to other importers, and rely on testing conducted by the foreign gasoline terminal so long as all the other requirements applicable to the proposed alternative approach are complied with. In addition, truckers using this second alternative approach will be subject to more extensive reporting than required for the proposed alternative, since the importer will have to demonstrate compliance with the annual average sulfur standard applicable to other importers.
One commenter urged that truckers should be subject only to the national downstream cap. We cannot agree to this approach as it is not environmentally neutral relative to the national standards in effect for other importers and refiners. If truck importers were required to meet only the downstream cap, sulfur levels for their imported gasoline could be substantially higher than for other importers, which could have a detrimental environmental consequence.
One commenter stated that the 30 ppm per-gallon standard for truck importers should not go into effect until the 30 ppm standard becomes the national average standard for refineries and other importers. We agree. Under today's rule, the per-gallon standards applicable to truck importers under the proposed alternative will be the same sulfur level as the sulfur average standard that applies to other importers (in 2004 there is no average standard; however, truck importers using this alternative compliance approach must meet the corporate pool standard on a per-gallon basis).
Similar provisions as provided above apply to truck importers for gasoline subject to the geographic phase-in area (GPA) standards (see section IV.C. of this preamble for a discussion of GPA standards). However, because of the small volumes of truck-imported gasoline, and the consequent difficulty in meeting corporate pool averages for a trucker who imports gasoline into both the GPA and areas outside the GPA, today's rule requires that for truck importers using the averaging option, the corporate pool average does not have to be met. The 150 ppm average standard and the 300 ppm cap standard apply to gasoline imported by truck into the GPA in 2004 through 2006. For truck importers meeting the per-gallon standard option for gasoline imported into the GPA, the per-gallon standards are 150 ppm for 2004 through 2006.
The NPRM addressed issues associated with gasoline produced by a foreign small refinery with an individual baseline and certified as subject to the refinery's individual interim standard (S-FRGAS), and imported by truck. The proposed requirements for S-FRGAS included segregating the gasoline from all other gasoline from the refinery gate to the U.S., so that compliance with standards can be tracked. For ordinary, non-truck importers, each batch of certified S-FRGAS must be tested at the load port and port of entry. Today's rule finalizes these proposed requirements for S-FRGAS.
However, in the case of gasoline imported by truck, the NPRM acknowledged that the testing and other procedures proposed for certified S-FRGAS may not be feasible. As a result, we proposed an alternative to the requirement for testing every truckload of imported certified S-FRGAS, and to other importer requirements. This alternative approach includes a requirement that small foreign refiners producing any S-FRGAS that will be imported by truck submit a petition to EPA that includes a plan which is designed to ensure that certified S-FRGAS remains segregated from all other gasoline from the refinery to the U.S. Rather than specifying the precise requirements of such a plan in the regulations, we proposed to allow the refiner to develop its own procedures for ensuring that S-FRGAS remains segregated. However, the plan must contain certain elements, such as product transfer documents which identify the origin of the gasoline and prohibit its commingling with any product other than certified S-FRGAS from that refinery.
This approach also requires the refiner of such truck-imported gasoline to receive and maintain all such product shipment documents, including U.S. import documents, for five years and review these to ensure that segregation is maintained until reaching the U.S. To ensure that refiners conduct this review, we proposed to require the refiner's plan to include attest audit procedures to be conducted annually by an independent third party.
We received no comments on this proposal for ensuring the integrity of S-FRGAS imported by truck. Today's final rule adopts the petitioning provision to permit alternative segregation procedures for S-FRGAS imported by truck as proposed since we continue to believe that it will provide flexibility to foreign refiners and to importers and will adequately assure enforceability.
We proposed per-gallon cap standards that would apply to all parties in the distribution system downstream of the refinery and importer level, including pipelines, terminals, oxygenate blenders, distributors, carriers, retailers and wholesale purchaser-consumers. We believe that downstream cap standards and compliance monitoring based on downstream standards are needed to ensure that the sulfur level of gasoline remains below the cap level when dispensed for use in motor vehicles, to avoid adverse emissions consequences that would be caused by the use of gasoline having a sulfur content above the cap level. The following discussion addresses downstream standards generally, downstream standards and requirements for gasoline produced by refineries subject to standards under § 80.240 and 80.270, and downstream standards and requirements for gasoline produced or imported for the geographic phase-in area (GPA).
We proposed that the downstream standards would be more lenient than the refinery-level cap standards so that refiners and importers can produce gasoline that equals the refinery-level cap standard. We did so because it has been EPA's experience that if a refiner produces gasoline that equals, or almost equals a standard, that gasoline may be shown to violate the standard when subsequently tested at a location downstream of the refinery due to testing variability. As a result, parties downstream of the refinery (primarily pipelines) set commercial specifications for the quality of the gasoline they will accept that are more stringent than the standard that applies to the downstream party. This, in effect, forces refiners to produce gasoline that is “cleaner” than the refinery-level standard.
In other fuels programs (for example, the benzene per-gallon standard for RFG) we resolved this concern by announcing enforcement tolerances for fuels standards that apply downstream of the refinery-level, thereby reducing the need for pipelines to set specifications more stringent than the refinery level standards. We believe that having more lenient downstream standards will have the same effect as enforcement tolerances.
In the NPRM we proposed that the values of the downstream cap standards would reflect the testing variability that could reasonably be expected when different laboratories test gasoline for sulfur content; that is, lab-to-lab variability, or reproducibility. Industry commenters supported this approach, and today's rule adopts this approach. For gasoline subject to the 80 ppm refinery-level sulfur cap, the downstream maximum standard is 95 ppm. This difference reflects the reproducibility established by the American Society for Testing and Materials (ASTM).
Because these downstream caps are based on sulfur test reproducibility, we intend to amend the rule in the future if improvements in test precision are made for the designated method. We may also consider amending the rule to make some other method the designated method if a more precise method is available in the future.
Under the proposal, if gasoline produced by a small refiner with a less stringent cap standard is mixed in the distribution system with gasoline subject to the national cap standard, the entire mixture would then be subject to the higher cap standard, even though most of the gasoline, at the refinery level, would be subject to the more stringent national cap standard. We proposed that during the period that small refinery individual standards are in effect, for gasoline that is comprised, in whole or in part, of small refiner gasoline with a higher sulfur cap standard than the national cap standard, product transfer documents (PTDs) would specify that the gasoline is small refiner gasoline and the level of the downstream cap applicable to the gasoline.
The purpose of the proposed provisions was to make it possible to determine the standard that applies to any gasoline downstream of the refinery. If the gasoline contains no small refiner gasoline, the downstream standard would be based on the national cap. If the gasoline is comprised, in whole or in part, of small refiner gasoline subject to a less stringent cap standard, the downstream standard would be based on this less stringent cap standard. As gasoline is mixed and remixed in the fungible distribution system, the percentage of gasoline that is small refinery gasoline will progressively diminish until the fungibly mixed gasoline meets the national downstream cap. Therefore, we proposed in the NPRM that a downstream party may no longer classify gasoline as containing small refiner gasoline if a test result shows the sulfur content of the gasoline is below the applicable national (i.e., not small refiner) downstream cap.
Several commenters suggested that this tracking scheme would be unworkable. Some of these comments were based on the belief that the proposal intended to require segregation of the small refiner gasoline through the distribution system. The proposal was not intended to require that small refiner gasoline must be segregated, and under today's final rule there is no requirement that small refiner gasoline must be segregated from gasoline produced by other refiners. Some commenters also believed that testing by downstream parties would be required under the proposed rule. These commenters were concerned that a downstream testing requirement could be costly and could delay distribution of gasoline. This latter point is addressed later in this discussion. Some commenters stated that the proposed PTD provisions of the downstream enforcement scheme were too complex and that some means other than changing PTD designations should be found to track small refiner gasoline.
Other commenters, including automobile manufacturer trade associations, stated they believed that EPA enforcement and testing downstream of the refinery is necessary to assure that gasoline complies with standards at the retail gasoline pump.
We have carefully considered the comments and we have concluded that the tracking scheme as proposed would not be effective because most pipeline shipments are expected to include some small refiner gasoline (although the amount of small refiner gasoline may comprise less than 1% of the shipment) and therefore, most of the gasoline in the nation might be classified as small refiner gasoline, even though only a small fraction of the supply will actually be small refiner gasoline. Therefore, a downstream cap much less stringent than the national downstream cap would attach to most gasoline produced to meet the national refinery standards, and the scheme would not be effective in monitoring whether the quality of most gasoline is maintained after it enters the gasoline distribution system.
The proposed scheme could lead to other unintended results. The gasolines contained in a fungible mixture in the distribution system may not be fully mixed and homogenous. As a result, a distinct, unmixed, portion of gasoline within a fungible mixture could be small refiner gasoline with a sulfur content above the national downstream cap, while other parts of the fungible mixture would meet the national downstream cap. This is especially true for fungible mixtures in pipelines and could also be true for gasoline in storage tanks. If a test result for a sample collected from part of such a fungible mixture in a pipeline shows compliance with the national downstream cap, under the proposed rule the entire mixture would become subject to the national downstream cap, and the pipeline PTDs could not classify the gasoline as small refiner gasoline. Thus,
Because of these difficulties, we concluded that the proposed scheme must be modified to address these concerns, in order for there to be effective enforcement of the downstream standards. We are concerned that the quality of gasoline will be affected downstream of the refinery. Gasoline may be contaminated with high sulfur blendstocks or other high sulfur products such as distillates after it leaves the refinery gate. There is likely to be an economic incentive for some downstream parties to sell or use gasoline or blendstocks that have a higher sulfur content than the national downstream standard. The inability to monitor downstream compliance would result in environmental degradation that is not intended by the rule, and in an inability to assure a level playing field for all parties in the gasoline distribution industry.
We believe that an effective downstream compliance and enforcement scheme is necessary in order to achieve the full emissions reduction benefits of the rule. Today's rule modifies the proposed tracking scheme so that compliance with the program can be monitored.
Under today's rule, all gasoline downstream of the refiner or importer is subject to the national downstream standard unless a different downstream standard, based on the highest sulfur content of any small refiner/temporary refiner relief gasoline in the gasoline mixture (as determined by the small refiners' batch testing), is supported by PTDs and a test result confirming the presence of small refiner/temporary refiner relief gasoline. The test result must be for gasoline sampled from the downstream facility classifying the gasoline as small refiner gasoline, unless the facility is a trucker, retailer or wholesale purchaser-consumer. We have concluded that this requirement is necessary to monitor compliance with the downstream standards during the period that small refiner/temporary refiner relief standards are in effect, because the vast majority of the gasoline transported by pipelines will be gasoline produced to comply with the national cap,
We believe that the ability to track small refiner gasoline is made even more important due to the geographic phase-in area (GPA) gasoline provisions finalized today.
The only parties required to perform testing in order to demonstrate that a shipment, or tank, of gasoline contains small refiner gasoline are gasoline pipelines and terminals. Where a terminal properly classifies gasoline in its storage tank as small refiner gasoline, and subsequently receives a load of gasoline into that tank, it may not continue to classify the gasoline as small refiner gasoline unless the tank is sampled, and a test demonstrates that the tank still contains small refiner gasoline and the gasoline sulfur content exceeds the national refinery level cap. In 2004 the test result would have to exceed 350 ppm; in 2005, 300 ppm; and starting with 2006, 80 ppm. In the GPA, the test result would have to exceed 350 ppm in 2004, and 300 ppm in 2005 and 2006.
We have concluded that the pipeline and terminal testing provisions are necessary for effective enforcement. We believe that terminals and pipelines will be able to perform sampling and testing that will enable them to identify the presence of small refiner gasoline in a cost-effective manner. These parties have knowledge regarding the mixing of gasoline as it moves from the pipeline and into the terminal tank, and knowledge of the distribution system, that will enable them to make judgments regarding the extent of testing that may be needed to demonstrate whether gasoline meets the national downstream cap. Further, a terminal operator may take additional tests if it believes a tank may contain a stratified portion of small refiner gasoline, despite a test result showing the tank complies with the national downstream cap.
Many terminals may have sufficient reason to believe they are receiving only gasoline meeting the national cap such that they will not normally test each receipt of gasoline. Additionally, even for terminals who receive small refiner gasoline, we do not believe the sampling and testing will be burdensome. This is partly because many terminals already conduct periodic sampling, or even sampling after every delivery of gasoline into storage tanks, at least in the summer VOC or RVP season, to test gasoline for various parameters, which may already include sulfur testing in RFG areas. Field test instruments already exist that are adequate for this testing in 2004 and 2005 when the national downstream cap is 378 ppm and 326 ppm, respectively. Moreover, we believe that because of today's rule, better field test instruments for sulfur analysis at lower levels are likely to be developed in the next few years. Therefore, it will not be necessary for quality assurance samples to be sent to a laboratory for testing. Thus, we do not believe shipments will be held up while terminals await a test result. We also believe that it is likely that these instruments will be available for a cost that will be far less than most laboratory instruments available today.
Under today's rule, retailers are not required to conduct testing. The retailer can demonstrate that the gasoline is properly designated small refiner gasoline subject to a less stringent downstream standard by maintaining PTDs from its suppliers that demonstrate a terminal classified gasoline supplied to the retailer's storage tank as small refiner gasoline.
Consistent with the way today's rule sets downstream sulfur standards for other gasoline, the GPA program downstream standard is determined by adding the ASTM reproducibility applicable to the refinery level sulfur
Because GPA gasoline must be used only within the GPA states,
Gasoline produced for use in all areas of the country outside the GPA may be sold for use in the GPA, including gasoline subject to small refiner standards under section 80.240 of today's rule.
Where GPA gasoline is commingled with other gasoline, the commingled gasoline must be classified as GPA gasoline and used only in the GPA states. Where GPA gasoline is commingled with S-RGAS, the applicable downstream sulfur standard for that gasoline is the greater of the GPA downstream standard or the applicable small refiner/temporary refiner relief standard as determined under section 80.210 of the rule.
Some commenters stated that there should be a lead-time of several months between the implementation date of a new refinery level sulfur standard and the implementation date of the corresponding downstream standard. Based on our experience with other fuels programs, we believe that a one-month lead time will be adequate for gasoline at the terminal level to meet new standards. An additional one month for retailers will give them ample time to comply. Therefore, under today's rule, the 378 ppm downstream sulfur standard (or any applicable small refiner downstream cap standard) is effective February 1, 2004 at the terminal level and March 1, 2004 at the retail level. The 326 ppm downstream sulfur standard is effective February 1, 2005 at the terminal level and March 1, 2005 at the retail level. The 95 ppm downstream standard is effective February 1, 2006 at the terminal level and March 1, 2006 at the retail level (or February 1, 2007, and March 1, 2007, respectively, in the case of gasoline at facilities in the GPA).
EPA believes gasoline advertised as being “low sulfur gasoline” when sold at retail outlets should have a sulfur content of no more than 95 ppm because this is the maximum sulfur level of gasoline at retail outlets that would protect the emission controls of Tier 2 vehicles. We are stating this to inform refiners and other regulated parties, when making advertisement decisions regarding gasoline, that it is EPA's position that effective January 1, 2004, if any retailer represents that gasoline is low sulfur gasoline, or representations to the same effect, the gasoline sulfur content should be no greater than 95 ppm.
We proposed ASTM standard method D 2622-98, “Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-ray Fluorescence Spectrometry,” as the primary method for testing sulfur in gasoline by refiners and importers. This is the designated method under the RFG/CG rule.
Most comments supported the continued use of ASTM D 2622 as the designated method for testing sulfur in gasoline under the various fuels rules, including today's rule. Commenters indicated that most refineries outside of California are currently using ASTM D 2622. Under the California fuels regulations, California refineries currently use ASTM D 5453, as well as ASTM D 2622 and ASTM D 4045. Comments were generally favorable to the proposed use of ASTM D 5453 as an alternate method. However, one California refinery, an automobile manufacturers association and a manufacturer of analytical equipment stated that ASTM D 5453 should be the primary method, primarily due to its greater precision at low sulfur levels. Favorable comments were received to the use of ASTM D 4045, especially for gasoline sulfur content of 10 ppm or less. One commenter suggested that ASTM D 5623-94 should be allowed; one commenter suggested that ASTM D 3120 should be allowed, and one commenter suggested that ASTM D 6428 should be allowed. Several commenters stated that we should utilize a performance based criteria system to determine what test methods can be used.
We have considered the comments carefully. We believe there are a number of test methods for determining the sulfur content of gasoline that may eventually be shown to be as good as, or better than, ASTM D 2622. We also considered that the Agency is likely to issue a proposed rulemaking for a performance-based test method approach that would apply to motor vehicle fuel parameters. This rule, once promulgated, would set forth criteria for determining whether an alternative analytical test method could be used instead of the designated analytical test method for a given fuel parameter and would set forth criteria for correlating alternative analytical test methods to the designated analytical test method.
We believe it is appropriate that alternate analytical methods should be qualified and correlated to the regulatory method according to standardized criteria. Today's rule therefore provides that ASTM D 2622, the recognized standard analytical method for determining sulfur in gasoline, is the sole regulatory method, anticipating that a performance-based testing rule may be issued before 2004, and that under its terms anyone will be able to qualify and correlate additional testing methods. We do not believe this will result in undue hardship for several reasons. First, our current fuels rules already provide that ASTM D 2622 is the sole regulatory method for determining the sulfur content of gasoline. Second, California refiners currently using ASTM D 5453 or ASTM D 4045 will not face any hardship because today's rule allows the use of approved California test methods by California refiners.
We also believe that a standardized approach for determining the appropriateness of alternate test methods, correlation methodology and quality control criteria for alternate test methods would be the most fair approach to the test equipment manufacturers and to the purchasers of testing equipment. It should result in a level playing field for competition among manufacturers of test equipment. We already know that ASTM D 5453 can be purchased for about half the price of ASTM D 2622 equipment, and competition may result in even less expensive equipment.
Some commenters suggested that where a refiner or importer uses ASTM D 2622 to test gasoline, and where the test result is less than 10 ppm, the refiner or importer should be able to report a test result of zero or perhaps use a default value of 5 ppm. This sort of approach has been allowed under the RFG and Anti-dumping Question and Answer Document. However, we disagree with the commenters that this practice is appropriate under the sulfur rule. Under the sulfur rule, with a refiner average standard of 30 ppm, it is important whether a bias is consistently drawn in favor of zero ppm as opposed to 10 ppm. This could artificially increase the number of credits earned or could allow more batches to be produced by the refiner that are near the 80 ppm cap. We believe that any imprecision of sulfur values derived from analysis using ASTM D 2622, will, over the course of numerous batches, average out to near zero. Further, we believe that the precision of ASTM D 2622 is likely to be improved by 2004. Also, by 2004 there may be other methods that will be shown to be precise at low sulfur levels that may be made available for use under a performance-based test method rule. Under today's rule the refiner or importer must report the test result that the test method provides, so long as the result is not less than zero (in which case a result of zero would be reported).
If alternative methods are ultimately made available for use under a performance based rule, refiners and importers who are producing or importing gasoline with low levels of sulfur may desire to use an alternative test method for low sulfur levels, especially if ASTM D 2622 is less precise at such levels. Under today's rule, if any approved alternative method is used for this purpose, a party could not choose to use the test result from ASTM D 2622 when its result is lower, and the test result from the alternative method when its result is lower. For any alternative test method that is eventually approved, if the party uses it for a certain range of sulfur concentrations, and ASTM D 2622 for another range, it must be consistent in such use. For example, if the alternate method were used for test results below 10 ppm, its result would always have to be used for sulfur levels below 10 ppm and ASTM D 2622 would always have to be used for sulfur levels greater than 10 ppm.
We proposed the use of ASTM standard test method D 5623-94
We have reviewed the suitability of ASTM D 5623 and agree that it is not the best method for testing for sulfur content in butane. ASTM D 5623 measures sulfur compounds rather than total elemental sulfur, and the current ASTM 5623 method is specified for liquid fuels, not gaseous fuels.
ASTM D 2784 does not seem to be a better method than ASTM D 5623. Commenters stated that ASTM D 2784 is not the most precise method and that it is not widely used. We believe there may be some difficulty in even obtaining the apparatus for ASTM D 2784. ASTM D 3227 is not appropriate since it is designed for measuring a single sulfur compound, and it is currently designated for testing liquid samples.
We believe that ASTM D 4468 appears to be a good method for testing butane for sulfur levels below 20 ppm. However, dilution would be necessary to test for sulfur levels above 20 ppm. This may be problematical, since it may be difficult to dilute a gaseous fuel. We expect that under today's rule, butane being tested will frequently have sulfur content in excess of 20 ppm. Several other methods exist that might work well for testing for sulfur content of gaseous fuels, but their current scope does not include determination of sulfur in gaseous fuels.
ASTM D 3246-96, which was suggested by API and NPRA as a suitable method, is an appropriate method for measuring gaseous compounds and provides test results for total elemental sulfur. Its range is 1.5 to 100 ppm, which is ideal for testing for the alternative 30 ppm butane sulfur standard applicable to butane blenders promulgated in today's rule.
After considering the strengths and weaknesses of all the available options we believe ASTM D 3246 is the best currently-available method. Therefore, today's rule makes ASTM D 3246 the designated method for testing the sulfur content of butane or other gaseous blendstocks. As discussed above, we anticipate that a performance-based test method rule for motor vehicle fuel parameters may be promulgated before 2004, and that the efficacy of other methods would be demonstrable under that rule. However, if that is not the case, the Agency may reconsider the issue of appropriate alternate test methods in a future rulemaking.
Several commenters urged that alternate test methods be allowed for quality assurance test purposes. Under today's rule, the use of alternate test methods for quality assurance testing for purposes of establishing a defense to liability, for butane quality assurance testing under section 80.340(b)(4), and for determination of whether gasoline is small refiner gasoline, is allowed, so long as the alternate test method is correlated to the regulatory test method, the method is ASTM approved, and the
We proposed in the NPRM that refiners and importers
Several commenters urged that we continue to allow composite sampling and testing for sulfur. Some refiners commented that the requirement to test each batch would raise testing costs. However, one refiner commented that every-batch testing for sulfur would not be a substantial burden so long as every-batch testing for other CG parameters is not required.
We believe that with a refinery gate sulfur cap combined with refinery averaged standards, there is no realistic alternative to every-batch testing. The Agency has no way to know whether a composite sample that is tested and found to meet the applicable refinery cap included a sample from an individual batch of gasoline that was introduced into commerce that exceeded the cap by a factor of 2 or 3. Further, we believe that with averaged standards for refiners and importers, and with multiple cap standards in effect during the phase-in period, monitoring compliance without every-batch testing would be impossible even if we could somehow be assured that no individual batch significantly exceeded the applicable refinery level cap.
We realize that there will be an additional cost associated with testing every batch of CG—for sulfur content (this is already required for RFG). However, we believe less expensive test methods for sulfur content already exist, and may continue to be developed, that will likely be acceptable as alternative methods in the future, as discussed above. Therefore, today's rule retains the requirement for every-batch testing. Under today's final rule, the test results for each batch of gasoline will be used to determine compliance with the applicable refiner/importer cap standard and to calculate the refiner's or importer's annual average sulfur level. Any batch of gasoline that exceeds the applicable sulfur cap cannot be distributed or sold in the U.S. (unless it is exempted from the standards under today's rule, as described in section VI.G., below).
Refiners who use computerized in-line blending methods objected to the proposed requirement for a batch test before the gasoline is released from the refinery. These commenters stated that refiners using the sophisticated in-line blending practice cannot produce a complete batch test until a portion of the batch is already past the refinery gate. These commenters did not urge that we eliminate the requirement for every-batch testing, but urged that the sulfur rule adopt the RFG rule provisions for in-line blending found at 40 CFR 80.65(f)(4), for both RFG and CG.
We believe that the importance of assuring compliance with the refinery level cap is such that the rule must generally require that gasoline must be tested for sulfur content before it leaves the refinery. Based on experience under the RFG rule, we do not believe that the requirement to test each batch before it is released will substantially increase the cost of testing or cause delays in shipments.
However, today's rule recognizes the unique circumstances involved in computerized in-line blending. We believe that with appropriate safeguards, compliance with sulfur standards for gasoline produced by refineries using in-line blending can be assured. Therefore, today's rule incorporates the RFG rule provisions for in-line blending at 40 CFR 80.65(f)(4). Such provisions will be applicable to RFG and CG. However, refineries presently having an in-line blending waiver will be asked to submit additional information under the auditing procedures included in approvals of in-line blending petitions already in place. We will contact individual holders of in-line blending approvals to request information on how sulfur is monitored and how streams of gasoline are distributed in the in-line blending process. If we cannot conclude that the monitoring procedures will assure compliance with sulfur standards, we will revoke the in-line blending approval for that purpose. We believe it is important to ensure that the in-line analyzer technology and the refiner's methodology and procedures are sufficient for the gasoline sulfur levels the refinery will have after this rule is implemented, for both RFG and CG.
Several commenters stated that the proposed rule's requirement to test every batch of CG for sulfur is unnecessary during the period of early credit generation because there is no cap standard in effect during this period, even for those refiners generating credits. We agree that every-batch testing is not essential for CG until the refinery gate per-gallon cap standards go into effect. Thus, today's final rule allows composite sample testing for CG to continue during the period of early credits generation, until January 1, 2004, when a cap standard for sulfur is first imposed on gasoline.
Under the RFG rule, refiners who blend butane or other blendstocks to previously certified gasoline (PCG) must determine the volume and parameter values of the blendstock, including sulfur content, by testing the gasoline before and after blending, and calculating the properties of the blendstock by subtracting the volume and parameter values of the PCG. For CG only, under certain conditions, we have allowed butane blenders to use the parameter specifications of butane as tested by the butane producer. We have allowed this alternative to every-batch testing because of the costs of testing each load of butane. We proposed a similar alternative to every-batch testing for butane blenders in the NPRM, which allows butane blenders to use the sulfur test result of their suppliers, if the butane contains no more than 30 ppm sulfur and if the butane blender undertakes a quality assurance program of periodic sampling and testing to ensure that the supplier's sampling and testing is accurate.
We also proposed to allow refiners that blend other blendstocks into PCG to meet an alternative testing requirement in lieu of testing every batch of gasoline. Provided that the refiner's test result for the sulfur content of each of the blendstocks is less than the national refinery level per-gallon cap standard, a refiner can sample and test each blendstock when received at the refinery, and treat each blendstock receipt as a separate batch for purposes of compliance calculations for the annual average sulfur standard.
Today's rule adopts these provisions. Several commenters urged us to delay the 30 ppm per-gallon cap standard until other refiners must meet a 30 ppm average standard. The proposed 30 ppm per gallon standard was intended to be environmentally neutral in relation to
Sampling methods apply to all parties who conduct sampling and testing under the rule. We proposed to require the use of sampling methods that were proposed in the July 11, 1997
In the NPRM, we proposed a refiner and importer (collectively referred to in this section as “refiner”) sampling and testing program to establish the sulfur compliance of each batch of gasoline produced or imported. We were aware that there were possible drawbacks to a self-testing scheme. For example, a party might sample or test gasoline in a manner that is inconsistent with the required procedures, or employees might inaccurately record the test results by mistake or otherwise. Parties might also attempt to conceal a discovered violation or to save money by not correcting a violation.
To address our concerns about self-testing, we considered an alternative option of requiring independent sampling and testing for all gasoline, including conventional gasoline. We did not propose this requirement for independent sampling and testing for all gasoline because of the costs of such a requirement,
Although there were few comments on this proposal, one commenter, the National Petrochemical & Refiners Association (“NPRA”), did comment extensively on it, and strongly urged the Agency not to finalize it. One of the points raised by the NPRA was that the RFG regulations have their own sample retention and submission requirements, (40 CFR 80.65), so that a sulfur rule provision for RFG batches was not necessary. The Agency continues to believe that sample and retention requirements are useful to ensure compliance with the sulfur standards, but we agree with NPRA that the sample retention and submission requirements found in the RFG rule will serve equally as well for the sulfur rule. Therefore, the final sulfur rule requires all refiners, including those producing RFG, to comply with the sulfur rule's retention requirements. However, any refiner of RFG using an independent laboratory pursuant to 40 CFR 80.65(f), either under the 100% Option or the 10% Option, will be considered to be in compliance with the sulfur rule's retain requirements provided the refiner ensures that the independent laboratory conducting the retain program for the refiner, is in compliance with these requirements. In particular, the refiner must ensure that its independent laboratory sends the appropriate certificate of analysis along with any sample forwarded to EPA. Under the RFG program's 100% Option, the refiner must ensure that its independent laboratory sends the independent lab's certificate of analysis; and under the 10% Option, the refiner must ensure that its independent laboratory sends the refiner's certificate of analysis.
In addition to urging EPA not to finalize the sample retention and submission requirements for RFG gasoline, NPRA urged us not to finalize these requirements for CG as well. NPRA argued that these requirements would not prove useful in deterring non-compliance with the sulfur requirements for this product, primarily because false samples could be forwarded to EPA. The Agency disagrees with NPRA's argument. First, the goal of these requirements is not only to deter cheating but also to reveal inadequacies that exist in refiners' sulfur testing procedures. We do not expect that most non-compliance with the sulfur standards will occur through cheating, but rather through operational problems. Agency enforcement experience under the RFG rule reveals that some refiners' testing procedures are not always accurate in measuring parameters and thus detecting noncompliance. EPA verification testing will expose such testing inaccuracy, enabling the refiner to improve its testing procedures and thus improve its ability to detect, and correct, its own compliance problems. To ensure the effectiveness of these sulfur sample retention and submission requirements, the final rule requires all refiners to provide EPA with the sulfur test result the refiner has obtained for the sample, along with each sample the refiner provides to the Agency under this rule.
EPA will use these retained samples in compliance determinations. Gasoline samples that are forwarded to EPA under the sample retention requirements that are found to be in violation of a refinery cap, will be considered by EPA to be evidence of violations of the cap standard, regardless of the refiner's own test result. In addition, EPA testing of these samples may establish that the refiners' test results are generally incorrect,
While it is true that a party can submit false samples to EPA in order to prevent the Agency from discovering what in actuality is a non-compliant batch of gasoline, we do not believe that there will be many examples of such flagrant cheating. Our enforcement experience indicates that the great majority of parties regulated under the fuels programs work to comply with the regulatory requirements. We believe that the potential penalties for the submission of false samples to the government, and the potential criminal liability which such conduct would subject parties to under to section 113 of the Clean Air Act, will act as significant deterrents to this cheating. Last, to further decrease perceived incentives for such cheating, the regulation specifically requires that the refinery official signing and submitting the refinery's annual sulfur report must make inquiries to verify the correctness of the sampling collection and retention procedures and include with the annual sulfur report a personal certification of the correctness of the procedures used to collect the retained samples. If such certification cannot be made, then the report cannot be timely filed.
NPRA further commented that CG being counted to create early credits under the sulfur rule's ABT program should not be subject to the proposed sample retention and submission requirements. NPRA argues that the lack of a sulfur cap during the early credit timeframe makes such retention and submission unnecessary. The Agency disagrees. During the early credit generation timeframe, refiners participating in the credit program must comply with sulfur averaging requirements, even though sulfur caps are not required to be met. Accurate determination of compliance with the averaging requirements necessitates accurate sulfur testing in the early credit period, just as it does during implementation of the full sulfur program, even though sulfur testing of CG composite samples will be permitted. Hence, the sample retention and submission requirements, whose purpose is to ensure accurate testing and compliance determination, continue to be necessary for the early credit period. The final rule retains the sample retention requirements for CG during the early credit time frame.
NPRA also suggested that in place of the proposed 30 day sample retention requirement, EPA instead should require refiners to maintain samples only from the last three batches of gasoline produced. NPRA argued that this alternative requirement would prove more economical for the refiners, yet would still provide EPA with the ability to test some samples itself. Although the Agency believes that the proposed 30 day retention period would provide a valuable amount of samples to be retained and thus available for testing by EPA, the Agency agrees that a more limited sample retention requirement could provide an acceptable means of confirming refiner testing accuracy and sulfur compliance, while being less burdensome to refiners. We do not believe, however, that retention of samples from only three batches of gasoline would be effective in accomplishing the goal of producing greater testing accuracy. Three samples would not be a great enough number to realistically demonstrate if a pattern of testing irregularities exists or to demonstrate that a significant volume of the refiner's production is covered by the testing verification process. Consequently, instead of the three batch sample retention requirement proposed by this commenter, the Agency has instead required in the final rule that at least the last 20 samples be retained, and that each sample be retained for a minimum of 21 days. The Agency believes this amended requirement addresses NPRA's concern that the amount of days of sample retention be reduced from thirty days, while also providing the Agency with an effective means of assuring a reasonable number of samples, representing a significant period of refining activity, will be available for accuracy testing. We believe the retention requirement is not burdensome given the limited number of samples that must be retained. Further, many refineries already retain samples.
A final comment by NPRA about the sample retention and submission requirements is addressed in the final rule. NPRA raised a concern about the required retention and submission of samples of pressurized blendstock, particularly butane, which would require the use of specialized high-pressure containers. The Agency agrees that there is legitimate concern about the handling, storing and shipping of such samples. We also believe that the final rule's quality assurance testing requirements and the testing requirements for blendstock suppliers provides adequate assurance of the compliance of these blendstocks. Hence, the final sulfur rule does not contain a requirement that samples of pressurized blendstock must be retained.
In the NPRM, the Agency proposed to generally exempt from the requirements of the federal sulfur rule certain gasoline sold or intended for sale in California. For the purpose of program consistency, the gasoline to be exempt in the sulfur rule would meet the same definition of California gasoline as found in the RFG rule (40 CFR 80.81(a)(2)). The exempt gasoline would include all gasoline sold, intended for sale, or made available for sale in California that was also either: produced within California; imported into California from outside the U.S.; or imported into California from another state, provided that the out-of-state refinery did not also produce federal RFG.
Although the NPRM proposed to exempt California gasoline from compliance with the proposed sulfur standards (for reasons discussed elsewhere in this preamble), we did propose two requirements that would apply to some exempt California gasoline. The first would require exempt gasoline produced outside of California but intended for use in California, to be segregated from non-exempt gasoline at all points in the distribution system. The second would require out-of-state producers of exempt gasoline intended for sale in California to create PTDs identifying the product as California gasoline, and would require such PTDs to be provided to all transferees of this gasoline in the distribution system. Requiring such documentation is intended to facilitate enforcement and compliance by identifying gasoline that is not federally regulated. The same PTD requirements currently apply under the RFG program.
One commenter expressed a reservation about the sulfur rule's proposed segregation requirement. The commenter was concerned that the segregation requirement for exempt California gasoline might interfere with the ability of California importers to import into California, non-exempt, federal RFG gasoline that happened to comply with California Air Resources Board (ARB) sulfur requirements, but had not been kept segregated by its out-
The Agency agrees that it would not be beneficial to restrict the flow of complying gasoline into California. However, since the federal and the ARB sulfur control programs provide for differing calculations of standard compliance, and since the standards themselves are not always consistent between the two programs, EPA does not believe that the compliance of gasoline produced for federal purposes will necessarily assure its compliance with ARB program requirements, and vice-versa. Therefore, we believe it is necessary to require the physical segregation of the gasolines produced for the different programs in order to best ensure compliance with our uniquely determined federal sulfur standards. To ensure segregation, it is necessary that refiners and importers designate gasoline batches destined for California as California gasoline and that PTDs identify the gasoline as being for use only in California.
Further, one of the purposes of creating the California exemption in the federal sulfur rule is to ensure the exclusion of California gasoline from the refiner's compliance calculations under the federal rule. This exclusion is necessary to prevent gasoline that is produced to comply with the strict California standards from unfairly effecting the refiner's compliance with the federal requirements, thereby facilitating the production of higher sulfur gasoline for use in a federal market supplied by the refiner. EPA believes that segregation of the two gasolines is necessary because it facilitates accurate identification of the product to be included solely in the federal compliance calculations.
EPA does not believe that requiring the segregation of California gasoline from gasoline produced for the federal market should create a significant restriction in the flow of gasoline to California. The Agency believes that if a California marketer needs to acquire ARB-complying gasoline from out-of-state, the marketer should generally be able to satisfy that need by ordering a batch of California gasoline to be created for it by out-of-state producers. Under this circumstance of the creation of a unique batch of California gasoline, segregation of the gasoline will typically be assured.
In analyzing the above comment on segregation of California gasoline, the Agency realized that the sulfur rule's proposed definition of exempted California gasoline, which paralleled the definition existing in the RFG rule, was not as complete as it should be to properly address the unique needs of the sulfur program. Specifically, the exclusion from the sulfur rule's exemption of out-of-state gasoline sold or intended for sale in California solely because it happens to be produced at a refinery that produces federal RFG gasoline, is not appropriate. Basing an exemption on whether or not an out-of-state refinery produces federal RFG is relevant to the RFG program, but it has no relevance to the sulfur control program. To ensure effective determination of compliance with federal sulfur standards, the final sulfur rule deletes any reference to RFG production in the rule's definition of exempt California gasoline. Hence, the example presented in the comment, in which out-of-state gasoline for sale in California could be considered non-exempt gasoline, would not arise under the expanded definition of California gasoline.
Under the NPRM and the final rule, refineries and importers located in California would be required to meet the federal sulfur standards and other requirements with regard to their “federal” gasoline to be used outside of California. However, we proposed that gasoline produced in California for sale outside of California could be tested for compliance under the federal sulfur rule using the methodologies approved by the ARB, provided that the producer complies with the procedures for such testing as already required under 40 CFR 80.81(h), which permits California test methods not identical to federal test methods to be used for conventional gasoline. Today's rule adopts this provision, as well as the corollary proposed provision that gasoline produced by California refiners for use out-of-state may be tested at off-site testing as already permitted pursuant to 40 CFR 80.81(h) for CG purposes. Both provisions in today's rule should alleviate duplicate testing burdens on California refiners subject to both the federal and California programs, since the test methods acceptable under these alternative provisions in today's rule are also currently used to comply with California requirements. No comments were received on these provisions.
The NPRM proposed that the business practice PTDs that accompany each transfer of custody or title of gasoline that includes gasoline produced by any small refiner subject to sulfur rule individual refinery standards would be required to identify the gasoline as such, including the applicable downstream cap, as an aid to enforcing the national downstream cap. Today's rule adopts the proposed PTD requirement, with modifications regarding how the PTD requirement relates to testing, as described in section VI.C. The requirement for printing information on PTDs has been simplified in the final rule. All parties may use brief codes to identify the small refiner status of the gasoline and to identify the small refiner downstream standard it is subject to. This small refiner gasoline PTD provision is also applied to gasoline subject to individual refinery standards under the temporary refiner relief provision of today's rule.
Under the geographic phase-in program finalized today, gasoline produced or imported for use in the GPA may be used only in the GPA states. Therefore, it is necessary for PTDs for gasoline that is comprised in whole, or in part, of GPA gasoline, to identify the gasoline as such and state that the gasoline may not be distributed or sold for use outside the GPA. Product codes may be used to provide this information, except in the case of transfers to truck carriers, retailers and wholesale purchaser-consumers.
Under today's rule, refiners and importers will be required to keep and make available to EPA certain records that demonstrate compliance with the sulfur program standards and requirements. This includes records pertaining to the generation, use and transfer of credits and allotments. The RFG/CG regulations currently require refiners and importers to retain records that include much of the information required in the sulfur rule. Where this is the case, there is no requirement for duplication of records or information.
Under the final rule, all parties in the gasoline distribution system, including refiners, importers, oxygenate blenders, retailers, and all types of distributors will be required to retain PTDs and records of quality assurance programs (including, where applicable, sulfur test
Parties are required to keep records for a period of five years,
We received comment that the regulations should allow records to be maintained in non-hard copy formats, such as photographic or electronic means. We do not believe that the recordkeeping requirements, as proposed, disallow the retention of records in electronic or photographic form. However, parties that electronically generate and/or maintain records must make available to EPA the hardware and software necessary to review the records, or if requested by EPA, electronic records shall be converted to paper documents.
The sulfur rule, like the RFG/CG rule, requires regulated parties to keep the results of tests conducted on the gasoline. A number of parties previously have asked EPA to clarify whether, under the RFG/CG rule, this recordkeeping requirement requires parties to keep copies of all documents that contain test results. To clarify what the recordkeeping requirements require with regard to test data, we proposed for the RFG/CG rule to add language which specifies that the test result as originally printed by the testing apparatus is required to be kept, or, where no printed result is generated by the testing apparatus, the results as originally recorded by the person who performed the tests. Today's action incorporates this clarification in the sulfur rule. Under this provision, where the test data is initially recorded into a database system and there are no prior written recordings of the data, the information in the database system may serve as the original record of the test data. The final rule also specifies that any record that contains results for a test that are not identical to the results as originally printed by the testing apparatus or recorded by the person who performed the test must also be kept. Although this language was not included in the NPRM, we have concluded it is a logical outgrowth of the proposal regarding recordkeeping for test data, and that it will make the regulation clearer with regard to this requirement. As a result, it is appropriate to include this language in the final rule.
Refiners and importers will be required to submit an annual report that demonstrates compliance with the applicable sulfur standards and data on individual batches of gasoline, including batch volume and sulfur content. The rule requires that refiners and importers report on the generation, use and transfer of credits and allotments. The RFG/CG programs contain similar reporting requirements. Based on our experience with these programs, we believe that requiring an annual sulfur report and batch information will provide an appropriate and effective means of monitoring compliance with the average standards under the sulfur program. The batch data also will serve to verify that each batch of gasoline met the applicable sulfur cap standard when it left the refinery or import facility. The batch data must also show which batches were designated as GPA gasoline, as appropriate.
For the 2004 and 2005 annual averaging periods, refiners will be required to submit a report for the refiner's gasoline production (RFG and conventional gasoline) for all refineries during the averaging period, which demonstrates compliance with the applicable corporate average and per-gallon cap standards. For the 2005 annual averaging period, refiners will also be required to submit a separate report for each refinery, which demonstrates compliance with the refinery average standard. For the 2004 and 2005 annual averaging periods, importers will be required to submit a report for all of the gasoline they import during the averaging period, which demonstrates compliance with the applicable corporate average and per-gallon cap standards. The importer's report for 2005 must also demonstrate compliance with the refinery average (30 ppm) standard. Any refiner who is also an importer must aggregate the refining and importing activities for the purpose of demonstrating compliance with the applicable corporate average standards. Importers of gasoline produced by foreign refiners with individual baselines have additional reporting requirements. For the 2006 averaging period and beyond, corporate average reports are no longer required for either refiners or importers. Refiners will be required to submit an annual report for each refinery (importers for the gasoline they import), which demonstrates compliance with the refinery average and per-gallon cap standards. Refiners or importers producing both GPA gasoline and gasoline for the remainder of the country, must separately report compliance with the different standards. Annual reports, on forms provided by the Agency, must be received by EPA by the last day of February for the prior calendar year.
The annual reports will also provide a vehicle for accounting for any sulfur allotments or credits created, sold or used to achieve compliance during the averaging period. (See Section IV.C. for a discussion of the sulfur allotment and ABT credit programs.) Each refiner or importer choosing to participate in the ABT program will be required to report to the Agency on an annual basis (refiners for each refinery, and importers for the gasoline they import) the applicable sulfur baseline and the annual average gasoline sulfur level produced at that refinery or by that importer (in ppm sulfur) during the averaging period. Credit calculations will be reported, along with an accounting of credits banked, used, traded, acquired or terminated. The credits will be in units of ppm-gallons. The identity of the refiners/refineries and importers involved in these transactions will be reported, along with the registration numbers assigned to them by the Agency under the RFG/CG program (40 CFR 80, subparts D, E, and F).
For years 2000 through 2003, parties who generate early ABT credits will be required to report information relating to the generation of these credits. These early credit reports will only cover credits banked and traded. Beginning in 2004 and beyond, refiners and importers
As discussed above, during the 2004 and 2005 annual averaging periods, refiners for the combined production from all their refineries, and importers for the gasoline they import, will also be required to demonstrate compliance with the applicable corporate average standard. In addition, refiners and importers must demonstrate compliance with the requirements for the generation, use, transfer and termination of allotments. Refiners and importers who trade sulfur allotments to meet the corporate average standard will be required to submit information relating to these transactions. All sulfur allotment transactions must be concluded by the last day of February of the calendar year following the year the allotments were used to meet the corporate average. Information relating to such transactions, including the identity of the refiners and importers involved in the transactions and their EPA registration numbers, must be reported by both parties to the transaction as part of their annual compliance reports.
As discussed in Section IV.C., above, parties that only blend oxygenates into gasoline are not treated as refiners under the sulfur rule, and, as a result, are not subject to the reporting requirements under § 80.370.
Refiners and importers are also required to arrange for a certified public accountant or certified internal auditor to conduct an annual review of the company's records that form the basis of the annual sulfur compliance report (called an “attest engagement”). The purpose of the attest engagement is to determine whether representations by the company are supported by the company's internal records. Attest engagements are already required under the RFG/CG regulations. The refiner's attest engagement under the RFG/CG rule partially encompasses sulfur rule compliance since the attest auditors are already required to verify sulfur results for both CG and RFG. However, the RFG/CG attest engagements do not require the attest auditor to review sulfur credit generation, credit purchases, credit trading or small refiner issues. Because of the complexity of the sulfur credit program and small refiner program, sulfur attest engagement provisions have been adopted by today's rule that require the attest auditor to review sulfur credit generation, credit trading, credit purchasing, credit selling, corporate pool averaging, and small refiner issues. Consistent with the RFG regulations, the attest reports for sulfur are to be included in the presently required attest engagement submitted by May 31 of each year.
The final rule provides for an exemption from the sulfur requirements for gasoline used for research, development and testing purposes. We recognize that there may be legitimate research programs that require the use of gasoline with higher sulfur levels than those allowed under the sulfur rule. As a result, the final rule includes provisions for obtaining an exemption from the prohibitions for persons distributing, transporting, storing, selling or dispensing gasoline that exceeds the standards, where such gasoline is necessary to conduct a research, development or testing program. Parties are required to submit to EPA an application for exemption that describes the purpose and scope of the program and the reasons why use of the higher sulfur gasoline is necessary. In approving any application, EPA will impose reasonable conditions such as recordkeeping, reporting, volume limitations and possible requirements to repair vehicles.
We received comment that the regulations should clarify that suppliers of gasoline used for R&D purposes are exempt from the prohibitions and penalties under the sulfur rule. To clarify this point, we have added a provision which explicitly states that gasoline subject to an R&D exemption is exempt from the provisions of subpart H, so long as the gasoline is used in a way that complies with the terms of the memorandum of exemption. If the R&D exemption is shown to be based on false information or is not properly maintained, parties will be liable for violations of the provisions under subpart H regarding any gasoline covered under the exemption.
We also received comment that the regulations should ensure that vehicles which have been used for testing with high sulfur test fuels are not later returned to the general fleet, or if they are, the vehicles should be required to be restored to their original condition. EPA agrees that it would be improper to permit such vehicles to be used in general use if their emission controls have been rendered inoperative through fueling with high sulfur gasoline. This issue may be effectively addressed through the anti-tampering requirements of section 203(a)(3) of the Clean Air Act, 42 U.S.C. § 7522(a)(3), and is also addressed in today's rule, which provides the Administrator with the power to include appropriate conditions when granting R&D exemptions.
The liability and penalty provisions under the sulfur rule are similar to the liability and penalty provisions of the RFG and other fuels regulations.
The sulfur rule, like other EPA fuels regulations, includes a presumptive liability scheme for violations of prohibited acts. Under this approach, the party in the gasoline distribution system that controls the facility where the violation occurred, and other parties in that gasoline's distribution system (such as the refiner, reseller, and distributor), are presumed liable for the violation.
The final sulfur rule, like the proposal, applies the provisions of section 211(d)(1) of the Clean Air Act (Act) for the collection of penalties. The penalty provisions subject any person who violates any requirement or prohibition of the sulfur rule to a civil penalty of up to $27,500 for every day of each such violation and the amount of economic benefit or savings resulting from the violation. A violation of the applicable average sulfur standard constitutes a separate day of violation for each day in the averaging period. A violation of a sulfur cap standard constitutes a separate day of violation for each day the gasoline giving rise to the violation remained in the gasoline distribution system. The length of time the gasoline in question remained in the distribution system is deemed to be twenty-five days unless there is evidence that the gasoline remained in the gasoline distribution system for fewer than or more than twenty-five days. The penalty provisions are similar to the penalty provisions for violations of the RFG regulations.
After consideration of the comments received, the Agency is adopting regulations that specify the regulated parties who may be subject to liability for causing a violation of the sulfur rule. As proposed, the regulation would have applied to any person, not limited to the parties in the gasoline distribution system whose actions could logically have caused the nonconformity. This provision would have potentially broadened the range of liable parties under the sulfur rule beyond the range established under other fuel programs. EPA believes that the presumptive liability schemes of current fuels regulations have generally been effective and finds no compelling reason to apply the regulatory provision at issue to “any person” rather than to specific parties. Therefore, in the final sulfur rule, the liability sections for the causation violations will specify the regulated parties subject to the liability, and will not encompass unspecified parties. The final rule clarifies that oxygenate blenders are among the specified parties potentially subject to liability. Today's final rule also clarifies that parent corporations are liable for violations of subsidiaries. This is consistent with our interpretation of the RFG rule, as stated in the RFG and Anti-dumping Question and Answer document. Finally, the final rule clarifies that each partner to a joint venture will be jointly and severally liable for the violations at a joint venture facility or by a joint venture operation.
We received several comments on the proposal. Some commenters believe that the Act does not authorize EPA to establish prohibitions against causing another person to commit a prohibited act or causing the presence of non-conforming gasoline to be in the distribution system. These commenters believe that these prohibitions are a departure from the liability scheme under the existing fuels regulations and that they constitute double jeopardy by imposing liability for multiple violations for a single act. The commenters also believe that imposing liability for causing another person to commit a prohibited act extends the limits that Congress placed on liability under section 211 of the Act, since sections 211(d) and 211(k)(5) do not expressly mention imposing liability for causing another person to violate regulations. The commenter also noted that, had Congress intended for such actions to be prohibited, it could have expressly included such a prohibition in section 211. This commenter cites section 211(g) as an example of a statutory provision with such a prohibition. One commenter said that, rather than clarify the presumptive liability scheme, the rule provides no guidance regarding what it means to cause someone to violate a prohibition or cause non-conforming gasoline to be in the distribution system. A commenter also stated that these proposed prohibitions are unnecessary, since EPA has issued violations to multiple parties under current fuels regulations.
EPA disagrees with the comment that the sulfur rule's proposed liability scheme is a marked departure from the liability schemes typically found in the other fuels programs promulgated pursuant to section 211 of the Act and with the comment that the regulations constitute double jeopardy (the double jeopardy issue is addressed in the Response to Comment document). The majority of these programs, including the proposed sulfur rule, contain presumptive liability enforcement structures which impose liability on parties who, through their actions, could logically have caused the fuel nonconformity. The sulfur rule's presumptive liability scheme is thus consistent with the liability schemes of typical prior fuels programs. While EPA has issued notices of violations to multiple parties for violations under current fuels regulations, the Agency believes it is appropriate to clarify that the act of causing another party to violate the regulations is a prohibited act. Therefore, the regulatory language in the sulfur regulations explicitly addresses this issue.
EPA also disagrees with the comment that this provision is inconsistent with Section 211(d) of the Act because Section 211(d) does not mention imposing liability for causing another person to violate the regulations promulgated under Section 211(c). For the reasons described above, EPA is adopting a provision in today's regulations that prohibits causing another entity to violate the standards. This prohibition is a reasonable exercise of EPA's discretion under Section 211(c), and the penalty provision of Section 211(d) apply to violations of the prohibition. The fact that Section 211(d) does not specifically mention causing another person to violate the regulations is therefore irrelevant, such action is itself a violation of the regulations. Moreover, Section 211(d) does not mention any specific violations for which penalties may be assessed, but rather states generally that violations shall result in penalties. Thus, the absence of specific mention of causing another entity to violate the regulations is irrelevant, since all other specific prohibitions in regulations subject to Section 211(d) penalties are similarly not mentioned.
The Agency also disagrees with the comment that the Clean Air Act does not give EPA the authority to establish causation violations under the sulfur rule. We believe that the Act gives us ample authority to categorize the sulfur rule's causative acts,
Section 211(c) gives EPA broad discretion to fashion regulations to control or prohibit the manufacture, introduction into commerce, sale, or offering for sale of fuels once the Agency has made the requisite findings regarding contribution to harmful air pollution or impairment of vehicle emissions control system performance. This includes the discretion to adopt
When one or several of these regulated parties causes another regulated party to violate the rule (or causes nonconforming gasoline to be present in the system), such an act could logically result in the high sulfur gasoline contributing to harmful air pollution or to the impairment of vehicle emission control device performance, which are the adverse impacts that legislative authority under section 211(c) was created to control. Examples of such upstream causative acts include the scenario where a refiner produces high sulfur gasoline which it sells to a distributor. That distributor then resells the nonconforming product to a variety of retail outlets which, in their turn, also violate the rule by selling the high sulfur gasoline to owners of motor vehicles. Another example occurs where a distributor has created high sulfur gasoline by blending high sulfur blendstock into his gasoline. This distributor then makes several different sales of this noncomplying product to a variety of retail outlets, which, in their turn, also violate the rule by selling the product to numerous motor vehicle owners. A third upstream causation scenario could occur if several refiners happen to make nonconforming gasoline. Each then sells its nonconforming product to a different distributor, and a retail outlet which is a customer of both distributors, purchases some of the noncomplying gasoline from both distributors. The retailer then commits a violation by offering this product for sale to its customers.
In some cases, an upstream action has more severe environmental impacts through causing a downstream violation than would occur if the violation was corrected upstream. For example, a refiner may violate the sulfur regulations by shipping gasoline that exceeds the applicable standards when it leaves the refinery. If that violation is corrected before the gasoline reaches the retail outlets, the adverse environmental impacts could be mitigated or avoided. However, if the refiner's violation is not corrected and ultimately causes a number of violations of the standards at retail outlets, the environmental impact would be more severe, since high sulfur gasoline would be introduced into vehicles and impair catalyst performance. Therefore, it is reasonable to consider causing a downstream violation by another party to be a separate violation, since an upstream party's actions can have more severe environmental consequences if they cause downstream parties to violate applicable requirements. For these reasons, it is reasonable to conclude that section 211(c) authorizes the Agency to prohibit and control such causative acts in order to ensure that gasoline ultimately introduced into vehicles meets the low sulfur standards.
Our approach is also reasonable under section 211(c) even though section 211(c) does not expressly prohibit causing another party to violate standards adopted under this subsection. In fact, section 211(c) itself does not contain any express prohibitions, but rather provides EPA authority to regulate fuels and fuel additives, based on certain findings. In contrast, other provisions of section 211, such as section 211(g), do include express prohibitions against certain actions. Thus, under section 211(g), the specified actions are prohibited even in the absence of EPA adopting regulations to codify the prohibitions. In section 211(g), Congress indicated a clear intent to prohibit a specific action (misfueling), without requiring EPA to adopt regulations to implement that prohibition. However, section 211(c) authorizes EPA to establish regulations with certain controls and prohibitions, and, as described above, EPA has the discretion to adopt reasonable measures to ensure that the requirements of such regulations are met.
Moreover, the commenters' assertion that this provision is inconsistent with other subsections of section 211 of the Act is misplaced. First, while the sulfur standards do apply to all gasoline, including gasoline subject to the reformulated gasoline requirements, the sulfur standards are being adopted pursuant to EPA's authority under section 211(c)(1), not under section 211(k). Therefore, section 211(k)(5)'s prohibitions, which describe actions that are violations of section 211(k), are not relevant to the sulfur standards. In addition, the enumeration of specific prohibitions in section 211(k) does not mean that EPA may establish no other prohibited acts with respect to reformulated gasoline; rather, it simply identifies certain actions that “shall be” violations of section 211(k), but does not preclude establishment of other appropriate prohibited acts pursuant to EPA's authority under the Act.
The Agency also disagrees with the argument that the proposed causation violations under the sulfur rule would impose unjustifiable, multiple liability for the commission of a single prohibited act. The Agency is generally not in the best position to know the exact cause of a gasoline nonconformity since so many parties and actions are involved with the sale and transfer of the gasoline. Therefore, for effective enforcement, we must have the ability to assert the liability of all the parties in the system who were connected with the nonconforming gasoline because they each could have caused the violation. Similarly, we must also have the ability to assert upstream liability for the full number of downstream violations a party may be responsible for causing, even if the multiple downstream violations may all ultimately be found to stem from one gasoline sale or transfer on the part of the upstream party. The enforcement possibility exists that the separate downstream violations may each have stemmed from separate actions by that party.
Any party may rebut the presumption of liability for each asserted violation by establishing through affirmative defenses that it did not cause the violation. Moreover, any party against whom EPA institutes an enforcement action may raise equitable factors about its own conduct as part of settlement of the violation enforcement action. In settling fuels matters, the Agency typically takes into account such matters as the volume of nonconforming product that a party was connected with, and the severity and the amount of proscribed activity that the party was actually involved with in causing the violation. We do not believe that either the sulfur rule's liability scheme or its future implementation will be arbitrary or unjustified.
To further alleviate commenters' concern about potential liability for multiple violations under the sulfur rule, we want to clarify that the Agency does not ordinarily attempt to collect separate penalties from an entity for the array of possible standard violations (
In a similar fashion, we do not expect to collect penalties from one party for both types of causation violations for the same amount of gasoline under normal circumstances. A primary Agency purpose in defining the causation violations as two separate prohibited acts (
On the other hand, if we have a violation sample from a distributor, but no samples from its downstream customers, we may assert that the distributor caused the presence of nonconforming gasoline in the distribution system, rather than assert that the distributor caused another party to sell nonconforming product, since we don't have a nonconforming sample from another party's facility. It would be reasonable for us to assert that the distributor caused the presence of nonconforming gasoline in the distribution system since we do have a sample of nonconforming gasoline from the distributor, and provided also that there is evidence that the distributor had sold, transferred, etc. this product to downstream customers.
In summary, the Agency intends to enforce the liability scheme of the sulfur rule in the same reasonable manner that we have enforced the similar liability schemes in our prior fuels regulations. This does not include attempting to penalize a party for multiple variations of noncompliance in regard to the same gasoline unless unusual circumstances make such action appropriate.
We have often used a variety of evidence to establish non-compliance with the requirements imposed under our current fuels regulations. Test results of the content of gasoline have been used to establish violations, both in situations where the sample has been taken from the facility at which the violation occurred, and where the sample has been obtained from other parties' facilities when such test results have had probative value of the gasoline's characteristics at points upstream or downstream. The Agency has also commonly used documentary evidence to establish non-compliance or a party's liability for non-compliance. Typical documentary evidence has included PTDs identifying the gasoline as inappropriate for the facility it is being delivered to, or identifying parties having connection with the non-complying gasoline.
EPA proposed that compliance with the sulfur standards would be determined based on the sulfur level of the gasoline, as measured using the regulatory testing methodologies. We further proposed that any evidence from any source or location could be used to establish the gasoline sulfur level, provided that such evidence is relevant to whether the level would have been in compliance if the regulatory sampling and testing methodology had been correctly performed. In today's action, EPA is adopting the proposed regulatory provision.
Several commenters interpreted this proposed language as evidencing the Agency's intent to make all evidence, including evidence not derived from regulatory test methods, equal in probative value to that from the regulatory test methods. One commenter also stated that the proposed provision is inconsistent with other parts of the proposal because it undercuts the benefits of having clearly defined regulatory test methodologies. EPA disagrees that the regulatory language indicates such an intent, or has such an effect. The regulations provide that compliance with the standards is to be determined using specified test methodologies. While other information may be used, including test results using different test methods, such other information may only be used if it is relevant to determining whether the sulfur level would meet applicable standards had compliance been properly measured using the specified test methodologies. Thus, the regulation adopted today does not result in a situation where any and all evidence carries equal weight in an enforcement action. In fact, the regulation establishes the regulatory test method as the standard against which other evidence is measured. Moreover, since any evidence other than regulatory test results must be relevant to compliance using the test method, EPA disagrees with the commenter who stated that the validity of the sulfur standards can be challenged in any enforcement action because neither EPA nor regulated entities will be able to rely on measurements taken using the regulatory test methods. Rather than causing more confusion regarding compliance with the standard, this provision clarifies that the regulatory test method defines compliance, since other evidence can only be used if it relates to compliance using that test method.
The following is an example of how the Agency believes evidence of standard non-compliance not based on regulatory test results might be used for compliance purposes under today's rule provisions. Under a first scenario, the Agency might not have sulfur results derived from regulatory test methods for a certain amount of gasoline sold by a terminal, yet the terminal's own test results, based on testing using methods other than those specified in the regulations, show an exceedance of the sulfur standard. Under the requirements of today's rule, the evidence from the non-regulatory test method could only be used to establish noncompliance if the terminal's test results are relevant to the determination of the gasoline's sulfur level that would have resulted if the regulatory test method had been used. Thus, the Agency would have to present evidence to link the results of the alternative test method to sulfur levels as measured using the regulatory test method.
Another commenter has suggested that, if the Agency decides to finalize a “credible evidence” provision, it use the language in the current RFG regulations which establishes a presumption that the regulatory testing methods prevail, except in exceptional circumstances. Other commenters also opposed the proposed provision in part because it differs from that in EPA's current fuels regulations. As described above, EPA believes that the provision adopted today does not undercut the importance of the regulatory testing methodologies, since other evidence may be used only as relevant to compliance as measured using the regulatory methods. In addition, as is consistent with the RFG scheme, EPA believes it is appropriate to use such other evidence even in some circumstances where test results using the regulatory test methods do exist, and the provision adopted today clarifies this. EPA also notes that it intends to undertake rulemaking in the near future to revise the current fuels regulations to
The provision adopted today also clarifies that any probative evidence obtained from any source or location may be used to establish non-compliance with requirements other than the sulfur standards, such as recordkeeping requirements and requirements to properly calculate sulfur credits and averages, as well as to establish which parties have facility control or some other basis for liability for sulfur rule non-compliance. Since proof of these elements is not predicated on establishing sulfur levels, whether or not regulatory test methods are used is not significant. Therefore commenters' concern about the use of other evidence undercutting the primacy of the regulatory test methods is not germane to this part of the regulation which is not directed toward standards. This provision is being included in the final sulfur rule to clarify that this rule, as is consistent with our interpretation of our other fuels rules, contemplates the full use of all relevant evidence to establish non-standard violations and rule liability.
EPA disagrees with the commenters who stated that EPA lacks authority under the Clean Air Act to permit the use of any evidence of non-compliance of the sulfur standards other than test results using the regulatory test methods. One commenter notes that the only explicit reference in the Act to the use of “credible evidence” is in section 113(e), which applies only to stationary sources, and that neither section 211 nor section 205 mention “credible evidence.” Finally, the commenter states that the proposed provision is inconsistent with the directive of section 211(k) that EPA determine appropriate measures of and methods for ascertaining the emissions of air pollutants.
EPA disagrees with the comments asserting that the Agency lacks authority to promulgate this provision. While section 113(e) does refer to “credible evidence,” that provision is not relevant to EPA's action today. Moreover, the absence of the explicit use of the term “credible evidence” in sections 205 and 211 does not compel a conclusion that EPA lacks authority to allow the consideration of relevant evidence in determining compliance with the sulfur standards. EPA believes that section 211(c) provides sufficient authority to adopt such a provision. Section 211(c) authorizes the Agency to promulgate regulations for the purpose of prohibiting or controlling the manufacture, introduction into commerce, sale, or offering for sale of fuels or fuel additives where the fuel or additive causes or contributes to air pollution which may reasonably be anticipated to endanger public health or welfare, or where the fuel or additive will impair to a significant degree the performance of emission control devices that are or will be in general use. As described in other sections of this preamble and in the RIA, today's regulation is promulgated pursuant to this authority. Section 211(c) gives EPA broad discretion to fashion regulations to control or prohibit the manufacture, introduction into commerce, sale, or offering for sale of fuels once the Agency has made the requisite findings regarding contribution to harmful air pollution or impairment of vehicle emissions control system performance. This includes the discretion to adopt reasonable regulatory provisions that are necessary and appropriate to ensure that the controls or prohibitions are effective and can be enforced.
To ensure the effectiveness and the ability to adequately enforce the sulfur standards, it is reasonable for EPA to consider evidence other than actual test results using the regulatory test method, where such evidence can be related to the test results. As described above, test results using the regulatory test method are often not available. In such circumstances, it is reasonable to consider other evidence of compliance, such as test results using other methods or commercial documents, if such evidence can be shown to be relevant to determining whether the gasoline would meet the standard if tested using the regulatory methods. This provision would not permit the use of other evidence that is not relevant to such a determination, and is therefore reasonably limited to allow for effective enforcement, without creating uncertainty about compliance.
Finally, EPA disagrees with the commenter's assertion that this provision is inconsistent with section 211(k). First, while the sulfur standards do apply to all gasoline, including gasoline subject to the reformulated gasoline requirements, the sulfur standards are being adopted pursuant to EPA's authority under section 211(c)(1), not under section 211(k). In any case, the directive of section 211(k)(4) that EPA determine through regulation appropriate measures of and methods for ascertaining the emissions of air pollutants explicitly applies only for purposes of section 211(k), and applies for determining the emissions levels of VOCs and toxic air pollutants from baseline vehicles when operating on baseline gasoline, as defined by section 211(k). Thus, the commenter's reference to section 211(k)(4) as inconsistent with the provision adopted today is misplaced, particularly in light of the limited applicability of the language in section 211(k)(4).
As described in the NPRM, the Agency frequently uses a variety of evidence to establish compliance with fuel programs' regulatory requirements and liability for non-compliance. Such evidence has included test results obtained from a variety of sources, including bills of lading, delivery records, manifests, and other commercial documents. The compliance determination provisions included in today's final rule are created to provide the most effective Agency capability to enforce the rule's requirements.
A wide variety of interested parties participated in the rulemaking process that culminates with this final rule. The formal comment period and four public hearings associated with the NPRM provided additional opportunities for public input. EPA also met with a variety of stakeholders, including environmental and public health organizations, oil company representatives, auto company representatives, emission control equipment manufacturers, and states at various points in the process.
We have prepared a detailed Response to Comments document that describes the comments received on the NPRM and presents our response to each of these comments. The Response to Comments document is available in the docket for this rule and on the Office of Mobile Sources internet home page. Comments and our responses are also included throughout this preamble for several key issues.
Under Executive Order 12866 (58 FR 51735, Oct. 4, 1993), the Agency is required to determine whether this regulatory action would be “significant” and therefore subject to review by the Office of Management and Budget (OMB) and the requirements of the Executive Order. The order defines a “significant regulatory action” as any regulatory action that is likely to result in a rule that may:
• Have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities;
• Create a serious inconsistency or otherwise interfere with an action taken or planned by another agency;
• Materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or,
• Raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order.
Pursuant to the terms of Executive Order 12866, EPA has determined that this final rule is a “significant regulatory action” because the vehicle standards, gasoline sulfur standards, and other regulatory provisions, if implemented, would have an annual effect on the economy in excess of $100 million. Accordingly, we have prepared a Final Regulatory Impact Analysis (RIA) which is available in the docket for this rulemaking and at the internet address listed under
The Regulatory Flexibility Act, 5 U.S.C. 601-612, was amended by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), Public Law 104-121, to ensure that concerns regarding small entities are adequately considered during the development of new regulations that affect them. EPA has identified industries subject to this rule and has provided information to, and received comment from, small entities and representatives of small entities in these industries. We have prepared a Final Regulatory Flexibility Analysis (RFA) to evaluate the economic impacts of today's proposal on small entities.
• The number of affected small entities;
• The projected reporting, record keeping, and other compliance requirements of the proposed rule, including the classes of small entities that would be affected and the type of professional skills necessary for preparation of the report or record;
• Other federal rules that may duplicate, overlap, or conflict with the proposed rule; and
• Any significant alternatives to the proposed rule that accomplish the stated objectives of applicable statutes and that minimize significant economic impacts of the proposed rule on small entities.
The Agency convened a Small Business Advocacy Review Panel (the Panel) under section 609(b) of the Regulatory Flexibility Act as added by SBREFA. The purpose of the Panel was to collect the advice and recommendations of representatives of small entities that could be affected by today's proposed rule and to report on those comments and the Panel's findings as to issues related to the key elements of the Regulatory Flexibility Analysis under section 603 of the Regulatory Flexibility Act. The report of the Panel has been placed in the docket for this rulemaking.
The contents of today's final rule and the Final Regulatory Flexibility Analysis reflect the recommendations in the Panel's report. We summarize our outreach to small entities and our responses to the recommendations of the Panel below.
The Regulatory Flexibility Analysis identifies small businesses from the industries in the following table as subject to the provisions of today's rule:
The Final RFA identifies about 15 small petroleum refiners, several hundred small petroleum marketers, and about 15 small certifiers of covered vehicles (belonging to the other categories in the above table) that would be subject to the rule.
The Small Business Advocacy Review Panel was convened by EPA on August 27, 1998. The Panel consisted of representatives of the Small Business Administration (SBA), the Office of Management and Budget (OMB), and EPA. During the development of the proposal, EPA and the Panel were in contact with representatives from the small businesses that would be subject to the provisions of the rule. In addition to verbal comments from industry noted by the Panel at meetings and teleconferences, we received written comments from each of the affected industry segments or their representatives. These comments, alternatives suggested by the Panel to mitigate adverse impacts on small businesses, and issues the Panel requested EPA take additional comment on are contained in the report of the Panel and are summarized below. Today's final rule incorporates the major recommendations of the Panel.
Most of the small refiners stated that if they were required to achieve 30 ppm sulfur levels on average with an 80 ppm per-gallon cap without some regulatory relief, they would be forced out of business. Thus, the Panel devoted much attention to regulatory alternatives to address this concern. Most small refiners strongly supported delaying mandatory compliance for their facilities. On the other hand, most small refiners stated that a phase-in of gasoline sulfur standards would not be helpful because it would be more cost-effective for them to install the maximum technology required for the most stringent sulfur levels that would ultimately be imposed.
The Society of Independent Gasoline Marketers of America (SIGMA) commented that EPA should consider giving relief not only to refiners that meet the SBA definition of small refiner but also to refineries with relatively small production capacity that are owned by large refining companies. This was because a refinery with a small production capacity would operate essentially as an SBA-defined small refiner would. SIGMA also noted that small gasoline marketers would be affected by the closure of any refinery with small production capacity, whether it was owned by a large company or an SBA-defined small refining company.
The Panel recommended that small refiners be given a four to six year period of relief during which less stringent gasoline sulfur requirements would apply. The Panel also advised that EPA specifically request comment on an alternative duration of ten years for the relief period. Small refiners would be assigned interim sulfur standards during this relief period based on their current individual refinery sulfur levels. Following this relief period, small refiners would be required to meet the industry-wide standard, although temporary hardship relief would be available on a case-by-case basis. The Panel concluded that additional time provided to small refiners before compliance with the industry-wide standard was required would allow (1) new sulfur-reduction technologies to be proven-out by larger refiners, (2) the costs of advanced technology units to drop as the volume of their sales increases, (3) industry engineering and construction resources to be freed-up, and (4) the acquisition of the necessary capital by small refiners.
The Panel also concluded that adding gasoline sulfur to the fuel parameters already being sampled and tested by gasoline marketers would likely result in little, if any, additional burden. Therefore, the Panel did not recommend any special provision for gasoline marketers.
EPA's final action on this issue closely follows the Panel's recommendations. You can find a description of the small refiner provisions of today's final rule in Section IV.C.2. above. Comments and our responses on related issues are collected in the Response to Comments document.
Independent commercial importers of vehicles (ICIs) suggested that the new emissions standards be phased-in with the phase-in schedule based on the small vehicle manufacturer's annual production volume. Secondly, the ICIs requested that small testing laboratories be permitted to use older technology dynamometers than proposed for use by the Agency. Finally, the ICIs commented that the certification process should be waived for certain foreign vehicles. Small-volume vehicle manufacturers (SVMs) stated that a phase-in of Tier-2 emissions standards is essential. They further stated that SVMs should not be required to comply until the end of the phase-in period, which should not be before model year 2007. The SVMs also stated that a case-by-case hardship relief provision should be provided for their members. SVMs requested that a credit program be established with incentives for larger manufacturers to make credits available to SVMs in meeting their compliance goals.
Based on the above comments, the Panel advised that EPA consider several alternatives, individually or in combination, for the potential relief that they might provide to small certifiers of vehicles.
The Final Regulatory Flexibility Analysis evaluates the financial impacts of the proposed vehicle standards and fuel controls on small entities. EPA believes that the regulatory alternatives incorporated in today's final rule will provide substantial relief to small business from the potential adverse economic impacts of complying with today's proposed rule.
The information collection requirements (ICRs) associated with today's rule belong to two distinct categories: (1) those that pertain to amendments to the vehicle certification requirements, and (2) those that pertain to requirements for the control of gasoline sulfur content. These information collection requirements are contained in two separate ICR documents according to the category to which they belong.
The ICR in this final rule that pertains to the amendments to the vehicle certification requirements has been submitted for approval to the Office of Management and Budget (OMB) under the
The ICR in this final rule that pertains to the requirements for the control of gasoline sulfur will be submitted for approval to the Office of Management and Budget (OMB) under the
The Agency may not conduct or sponsor an information collection, and a person is not required to respond to a request for information unless the information collection request displays a currently valid OMB control number. The OMB control numbers for EPA's regulations are listed in 40 CFR Part 9 and 48 CFR Chapter 15. The OMB control numbers for the information collection requirements in this rule will be listed in an amendment to 40 CFR part 9 in a subsequent
The information collection requirements under the sulfur control program evolve over time as the program is phased-in. Beginning July 1, 2000, certain requirements apply to parties that voluntarily opt to generate credits for early sulfur reduction under the average banking and trading (ABT) provisions. Many of the requirements do not become applicable until the beginning of the sulfur control program on October 1, 2003, when all refiners are required to meet the sulfur standards. The information collection requirements under the sulfur control program become stable after January 1, 2008, when the optional small refiner provisions expire.
The ICR document for the sulfur control program in this final rule will provide burden estimates for the activities required under the first three years of the program, from July 1, 2000, through June 30, 2003. The burden associated with activities required after June 30, 2003, will be estimated in later ICRs. The initial ICR for the gasoline sulfur control program, however, will provide a qualitative characterization of all of the required activities and associated burdens for the various regulated parties as they develop, and until they become stable after January 1, 2008.
In the ICR associated with the NPRM for this final rule, we estimated that the total burden of the information collection requirements that would be applicable during the first three years of the proposed gasoline sulfur control program would be 42,479 hours and $2,149,865 annually.
• Refiners: 31,231 hours; $1,879,822.
• Importers: 40 hours; $2,067.
• Pipelines: 85 hours; $2,785.
• Terminals: 1,700 hours; $55,700.
• Truckers: 3,333 hours; $118,000.
• Retailers/WPCs: 6,087 hours; $91,298.
• R&D Gasoline Users: 3 hours; $193.
We received few comments on the ICR burden estimates in the proposed sulfur rule. Most regulated parties have been fulfilling reporting, recordkeeping and testing requirements under the reformulated and conventional gasoline regulations. The only negative comments we received related to the batch testing for sulfur content and sample retention for conventional gasoline. We believe the estimated cost of complying with these requirements is somewhat higher than the actual
We estimate that there will be some additional costs and hourly burdens over those estimated in the NPRM associated with certain changes made to the sulfur program from the NPRM to this final rule. In particular, this final rule includes a program which provides for relaxed standards in the early years of the program for refiners and importers who produce or import gasoline for use in certain states in the western U.S. This program requires some additional reporting and recordkeeping burdens for those refiners and importers who participate in the program, since they will be required to submit an application for the program, including a baseline for purposes of establishing their sulfur standard. This program requires gasoline intended for use in the geographic area to be identified on product transfer documents and segregated from other gasoline in the distribution system. This final rule also includes provisions for trading sulfur allotments to provide refiners and importers additional flexibility in meeting the corporate pool average standards. This program requires additional reporting and recordkeeping to track allotment trading activity. In addition, the final rule requires small refiners to submit information regarding their crude oil capacity in order to qualify for the small refiner standards under the rule. Small refiners are also required to submit reports of their progress toward compliance with the sulfur standards. The additional total annual cost and hourly burden over the first three years of the program, as a result of changes made to the program in the final rule, are estimated to add less than one percent to the overall burden estimates contained in the NPRM ICR for the sulfur control program.
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P.L. 104-4, establishes requirements for federal agencies to assess the effects of their regulatory actions on state, local, and tribal governments, and the private sector. Under section 202 of the UMRA, EPA generally must prepare a written statement, including a cost-benefit analysis, for proposed and final rules with “federal mandates” that may result in expenditures to state, local, and tribal governments, in the aggregate, or to the private sector, of $100 million or more for any single year. Before promulgating a rule for which a written statement is needed, section 205 of the UMRA generally requires EPA to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost-effective, or least burdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply when they are inconsistent with applicable law. Moreover, section 205 allows EPA to adopt an alternative that is not the least costly, most cost-effective, or least burdensome alternative if EPA provides an explanation in the final rule of why such an alternative was adopted.
Before we establish any regulatory requirement that may significantly or uniquely affect small governments, including tribal governments, we must develop a small government plan pursuant to section 203 of the UMRA. Such a plan must provide for notifying potentially affected small governments, and enabling officials of affected small governments to have meaningful and timely input in the development of our regulatory proposals with significant federal intergovernmental mandates. The plan must also provide for informing, educating, and advising small governments on compliance with the regulatory requirements.
This rule contains no federal mandates for state, local, or tribal governments as defined by the provisions of Title II of the UMRA. The rule imposes no enforceable duties on any of these governmental entities. Nothing in the rule would significantly or uniquely affect small governments.
EPA has determined that this rule contains federal mandates that may result in expenditures of more than $100 million to the private sector in any single year. EPA believes that today's final rule represents the least costly, most cost-effective approach to achieve the air quality goals of the rule. The cost-benefit analysis required by the UMRA is discussed in Section IV.D. above and in the Draft RIA. See the “Administrative Designation” and Regulatory Analysis' section in today's preamble (VIII.A.) for further information regarding these analyses.
Under Executive Order 13084, EPA may not issue a regulation that is not required by statute, that significantly or uniquely affects the communities of Indian Tribal governments, and that imposes substantial direct compliance costs on those communities, unless the federal government provides the funds necessary to pay the direct compliance costs incurred by the tribal governments, or EPA consults with those governments. If EPA complies by consulting, Executive Order 13084 requires EPA to provide to the Office of Management and Budget, in a separately identified section of the preamble to the rule, a description of the extent of EPA's prior consultation with representatives of affected tribal governments, a summary of the nature of their concerns, and a statement supporting the need to issue the regulation. In addition, Executive Order 13084 requires EPA to develop an effective process permitting elected officials and other representatives of Indian tribal governments “to provide meaningful and timely input in the development of regulatory policies on matters that significantly or uniquely affect their communities.”
Today's rule does not significantly or uniquely affect the communities of Indian Tribal governments. The motor
Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure “meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications.” “Policies that have federalism implications” is defined in the Executive Order to include regulations that have “substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.
Under Section 6 of Executive Order 13132, EPA may not issue a regulation that has federalism implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by State and local governments, or EPA consults with State and local officials early in the process of developing the proposed regulation. EPA also may not issue a regulation that has federalism implications and that preempts State law, unless the Agency consults with State and local officials early in the process of developing the proposed regulation.
Section 4 of the Executive Order contains additional requirements for rules that preempt State or local law, even if those rules do not have federalism implications (
This final rule does not have federalism implications. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. This rule adopts national emissions standards for certain categories of motor vehicles and national standards to control gasoline sulfur. The requirements of the rule will be enforced by the federal government at the national level. Thus, the requirements of section 6 of the Executive Order do not apply to this rule. Although section 6 of Executive Order 13132 does not apply to this rule, EPA did consult with State and local officials in developing this rule. In addition, EPA provided state and local officials an opportunity to comment on the proposed regulations. A summary of concerns raised by commenters, including state and local commenters, and EPA's response to those concerns, is found in the Response to Comments document for this rulemaking.
This final rule preempts State and local controls or prohibitions respecting gasoline sulfur content, pursuant to Section 211(c)(4) of the Clean Air Act. The basis and scope of preemption is described in Section IV.C.1.d of this notice. Although this rule was proposed before the November 2, 1999 effective date of Executive Order 13132, EPA provided State and local officials notice and an opportunity for appropriate participation when it published the proposed rule, as described above. Thus, EPA has complied with the requirements of section 4 of the Executive Order.
Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Section 12(d) of Public Law 104-113, directs EPA to use voluntary consensus standards in its regulatory activities unless it would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (
This rule references technical standards adopted by the Agency through previous rulemakings. No new technical standards are established in today's rule. The standards referenced in today's rule involve the measurement of gasoline fuel parameters and motor vehicle emissions. The measurement standards for gasoline fuel parameters referenced in today's proposal are all voluntary consensus standards. The motor vehicle emissions measurement standards referenced in today's rule are government-unique standards that were developed by the Agency through previous rulemakings. These standards have served the Agency's emissions control goals well since their implementation and have been well accepted by industry. EPA is not aware of any voluntary consensus standards for the measurement of motor vehicle emissions. Therefore, the Agency is using the existing EPA-developed standards found in 40 CFR Part 86 for the measurement of motor vehicle emissions
Executive Order 13045, “Protection of Children from Environmental Health Risks and Safety Risks” (62 FR 19885, April 23, 1997) applies to any rule that (1) is determined to be “economically significant” as defined under Executive Order 12866, and (2) concerns an environmental health or safety risk that EPA has reason to believe may have a disproportionate effect on children. If the regulatory action meets both criteria, section 5-501 of the Order directs the Agency to evaluate the environmental health or safety effects of the planned rule on children, and explain why the planned regulation is preferable to other potentially effective and reasonably feasible alternatives considered by the Agency.
This rule is subject to the Executive Order because it is an economically significant regulatory action as defined by Executive Order 12866 and it concerns in part an environmental health or safety risk that we have reason to believe may have a disproportionate effect on children.
This rulemaking will achieve significant reductions of various emissions from passenger cars and light trucks, primarily NO
The effects of ozone and PM on children's health were addressed in detail in EPA's rulemaking to establish the NAAQS for these pollutants, and we are not revisiting those issues here. We believe, however, that the emission reductions from the strategies established in this rulemaking will further reduce air toxics and the related adverse impacts on children's health. We will be addressing the issues raised by air toxics from motor vehicles and their fuels in a separate rulemaking that we will initiate in the near future under section 202(l) of the Act. That rulemaking will address the emissions of hazardous air pollutants from vehicles and fuels, and the appropriate level of control of HAPs from these sources.
In this final rule, we have evaluated several regulatory strategies for reductions in emissions from passenger cars and light trucks. (See sections IV, V, and VI of this preamble as well as the RIA.) For the reasons described there, we believe that these strategies are preferable under the Clean Air Act to other potentially effective and reasonably feasible alternatives that we considered for purposes of reducing emissions from these sources (as a way of helping areas achieve and maintain the NAAQS for ozone and PM). Moreover, we believe that we have selected for proposal the most stringent and effective control reasonably feasible at this time, in light of the technology and cost requirements of the Act.
The congressional review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the comptroller General of the United States. EPA will submit a report containing this rule and other required information to the U.S. Senate, the U.S. House of representatives, and the Comptroller General of the United States prior to publication of the rule in the
Statutory authority for the vehicle controls set in today's final rule can be found in sections 202, 206, 207, 208, and 301 of the Clean Air Act (CAA), as amended, 42 U.S.C. sections 7521, 7525, 7541, 7542 and 7601.
Statutory authority for the fuel controls set in today's final rule comes from section 211(c) of the CAA (42 U.S.C., section 7545(c)), which allows EPA to regulate fuels that either contribute to air pollution which endangers public health or welfare or which impair emission control equipment. Both criteria are satisfied for the gasoline sulfur controls we are establishing today. Additional support for the procedural and enforcement-related aspects of the fuel's controls in today's final rule, including the record keeping requirements, comes from sections 114(a) and 301(a) of the CAA.
Environmental protection, Air pollution control, Fuel additives, Gasoline, Imports, Incorporation by reference, Labeling, Motor vehicle pollution, Penalties, Reporting and recordkeeping requirements.
Environmental protection, Administrative practice and procedure, Confidential business information, Imports, Labeling, Motor vehicle pollution, Penalties, Reporting and recordkeeping requirements, Research, Warranties.
Environmental protection, Administrative practice and procedure, Confidential business information, Incorporation by reference, Labeling, Motor vehicle pollution, Penalties, Reporting and recordkeeping requirements.
Secs. 114, 211, and 301(a) of the Clean Air Act, as amended (42 U.S.C. 7414, 7545 and 7601(a)).
(d)
(h)
(s)
(gg)
(a)
(1) The sulfur content of gasoline must be determined by use of American Society for Testing and Materials (ASTM) standard method D 2622-98, entitled “Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-ray Fluorescence Spectrometry.”
(2) The sulfur content of butane must be determined by the use of ASTM standard method D 3246-96, entitled “Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry.”
(h)
(a) Refiners and importers who are registered by EPA under § 80.76 are deemed to be registered for purposes of this subpart.
(b) Refiners and importers subject to the standards in § 80.195 who are not registered by EPA under § 80.76 must provide to EPA the information required by § 80.76 by November 1, 2003, or not later than three months in advance of the first date that such person produces or imports gasoline, whichever is later.
(c) Refiners with any refinery subject to the small refiner standards under § 80.240, or refiners subject to the geographic phase-in area (GPA) standards under § 80.216, who are not registered by EPA under § 80.76 must provide to EPA the information required under § 80.76 by December 31, 2000.
(d) Any refiner who plans to generate credits or allotments under § 80.305 or § 80.275 in any year prior to 2004 who is not registered by EPA under § 80.76 must register under § 80.76 no later than September 30 of the year prior to the first year of credit generation. Any refiner who plans to generate credits in 2000 who is not registered by EPA under § 80.76 must register under § 80.76 no later than May 10, 2000.
(a)(1) The gasoline produced by small refiners subject to the standards at § 80.240, and gasoline designated as GPA gasoline under § 80.219(a), are as follows:
(2) The sulfur standards and all compliance calculations for sulfur under this subpart are in parts per million (ppm) and volumes are in gallons.
(3) The averaging period is January 1 through December 31 of each year.
(4) The standards under this paragraph (a) for all imported gasoline shall be met by the importer.
(b)(1) The refinery or importer annual average gasoline sulfur standard is the maximum average sulfur level allowed for gasoline produced at a refinery or imported by an importer during each calendar year starting January 1, 2005.
(2) The annual average sulfur level is calculated in accordance with § 80.205.
(3) The refinery or importer annual average gasoline sulfur standard may be met using credits as provided under § 80.275 or § 80.315.
(4) In 2005 only, the refinery or importer annual average sulfur standard may be met using credits or allotments as provided under § 80.275 or credits as provided under § 80.315.
(c)(1) The corporate pool average gasoline sulfur standards applicable in 2004 and 2005 are the maximum average sulfur levels allowed for a refiner's or importer's gasoline production from all of the refiner's refineries or all gasoline imported by an importer in a calendar year. The corporate pool average standards for a party that is both a refiner and an importer are the maximum average sulfur levels allowed for all the party's combined gasoline production from all refineries and imported gasoline in a calendar year.
(2) The corporate pool average is calculated in accordance with the provisions of § 80.205.
(3) The corporate pool average standard may be met using sulfur allotments under § 80.275.
(4) The corporate pool average standards do not apply to approved small refiners subject to the small refiner gasoline sulfur standards under § 80.240.
(5)(i) Joint ventures, in which two or more parties collectively own and operate one or more refineries, will be treated as a separate refiner under this section.
(ii) One partner to a joint venture may include one or more joint venture refineries in its corporate pool for purposes of complying with the corporate pool average standards. The joint venture will be in compliance for such joint venture refinery(ies) if the partner's corporate pool average meets the corporate pool average standards. The joint venture entity must demonstrate compliance with the corporate pool average standards for any refinery(ies) owned by the joint venture that are not included in one partner's corporate pool.
(d)(1) The per-gallon cap standard is the maximum sulfur level allowed for each batch of gasoline produced or imported starting January 1, 2004.
(2) In 2004 only, a refiner or importer may produce or import gasoline with a per-gallon sulfur content greater than 300 ppm, to a maximum of 350 ppm, provided the following conditions are met:
(i) The refinery or importer becomes subject to an adjusted per-gallon cap standard in 2005, calculated using the following formula:
(ii) The adjusted cap standard calculated under paragraph (d)(2)(i) of this section applies to all gasoline produced at a refinery or imported by an importer during 2005.
(iii) The refinery or importer remains subject to the 30.00 average standard under paragraph (a) of this section for 2005.
(iv) The provisions of this paragraph (d)(2) apply to gasoline designated as GPA gasoline under § 80.219(a).
(v) The provisions of this paragraph (d)(2) do not apply to small refiners as defined in § 80.225.
For the purpose of this subpart, all reformulated and conventional gasoline and RBOB, collectively called “gasoline” unless otherwise specified, is subject to the standards and requirements under this subpart, with the following exceptions:
(a) Gasoline that is used to fuel aircraft, racing vehicles or racing boats that are used only in sanctioned racing events, provided that:
(1) Product transfer documents associated with such gasoline, and any pump stand from which such gasoline is dispensed, identify the gasoline either as gasoline that is restricted for use in aircraft, or as gasoline that is restricted for use in racing motor vehicles or racing boats that are used only in sanctioned racing events;
(2) The gasoline is completely segregated from all other gasoline throughout production, distribution and sale to the ultimate consumer; and
(3) The gasoline is not made available for use as motor vehicle gasoline, or dispensed for use in motor vehicles, except for motor vehicles used only in sanctioned racing events.
(b) California gasoline as defined in § 80.375.
(c) Gasoline that is exported for sale outside the U.S.
(a) The annual refinery or importer average and corporate pool average gasoline sulfur level is calculated as follows:
(b) All annual refinery or importer average or corporate pool average calculations shall be conducted to two decimal places.
(c) A refiner or importer may include oxygenate added downstream from the refinery or import facility when calculating the sulfur content, provided the following requirements are met:
(1) For oxygenate added to conventional gasoline, the refiner or importer must comply with the requirements of § 80.101(d)(4)(ii).
(2) For oxygenate added to RBOB, the refiner or importer must comply with the requirements of § 80.69(a).
(d) Refiners and importers must exclude from compliance calculations all of the following:
(1) Gasoline that was not produced at the refinery;
(2) In the case of an importer, gasoline that was imported as Certified Sulfur-FRGAS;
(3) Blending stocks transferred to others;
(4) Gasoline that has been included in the compliance calculations for another refinery or importer; and
(5) Gasoline exempted from standards under § 80.200.
(e)(1) A refiner or importer may exceed the refinery or importer annual average sulfur standard specified in § 80.195 for a given averaging period for any calendar year through 2010, creating a compliance deficit, provided that in the calendar year following the year the standard is not met, the refinery or importer shall:
(i) Achieve compliance with the refinery or importer annual average sulfur standard specified in § 80.195; and
(ii) Use additional sulfur credits sufficient to offset the compliance deficit of the previous year.
(2) No refiner or importer may have a compliance deficit in any year after 2010. Any deficit that exists in 2010 must be made up in 2011.
(f) For refiners subject to the corporate pool average who produce some GPA gasoline, the refinery average sulfur value for its GPA gasoline shall be the average sulfur value after applying credits.
The sulfur standard for gasoline at any point in the gasoline distribution system downstream from refineries and import facilities, including gasoline at facilities of distributors, carriers, oxygenate blenders, retailers and wholesale purchaser-consumers (“downstream location”), shall be determined in accordance with the provisions of this section.
(a)
(b)
(1) Starting February 1, 2004 the sulfur content of gasoline at any downstream location other than at a retail outlet or wholesale purchaser-consumer facility, and starting March 1, 2004 the sulfur content of gasoline at any downstream location, shall not exceed 378 ppm.
(2) Except as provided in § 80.220(a), starting February 1, 2005 the sulfur content of gasoline at any downstream location other than at a retail outlet or wholesale purchaser-consumer facility, and starting March 1, 2005 the sulfur content of gasoline at any downstream location, shall not exceed 326 ppm.
(3) Except as provided in § 80.220(a), starting February 1, 2006 the sulfur content of gasoline at any downstream location other than at a retail outlet or wholesale purchaser-consumer facility, and starting March 1, 2006 the sulfur content of gasoline at any downstream location, shall not exceed 95 ppm.
(c)
(d)
(1) The gasoline must be comprised in whole or part of S-RGAS.
(2) Product transfer documents applicable to the gasoline when received at that location must represent that the gasoline contains S-RGAS.
(3) Except as provided in paragraph (d)(4) of this section, the gasoline must have been sampled and tested at that location subsequent to the most recent receipt of gasoline at that location, and the test result must show a sulfur content greater than:
(i) 350 ppm starting February 1, 2004;
(ii) 300 ppm starting February 1, 2005; and
(iii) 80 ppm (or in the GPA, 300 ppm) starting February 1, 2006.
(4) This sampling and testing condition does not apply for gasoline at any retail outlet, wholesale purchaser-consumer facility, or contained in any transport truck.
(e)
(i) Identification of the gasoline as being S-RGAS; and
(ii) The downstream standard applicable to the batch of gasoline under paragraph (f) of this section.
(2) Where gasoline in whole or part is classified as S-RGAS when received by the transferor, and where the gasoline transferred meets the conditions under paragraph (d) of this section, the transferor shall provide to the transferee, on each occasion when custody or title to gasoline is transferred, documents that include the following information:
(i) Identification of the gasoline as S-RGAS; and
(ii) The applicable downstream standard under paragraph (c) of this section. This does not apply when gasoline is sold or dispensed for use in motor vehicles at a retail outlet or wholesale purchaser-consumer facility.
(3) No person shall classify gasoline as being S-RGAS except as provided in paragraphs (e)(1) and (e)(2) of this section.
(4) Product codes may be used to convey the information required by paragraphs (e)(1) and (e)(2) of this section if such codes are clearly understood by each transferee.
(f)
(2) Where more than one S-RGAS batch is combined, prior to shipment, at the refinery or import facility where the S-RGAS is produced or imported, the downstream standard applicable to the mixture shall be the highest downstream standard, calculated under paragraph (f)(1) of this section, for any S-RGAS contained in the mixture.
Effective January 1, 2004, oxygenate blenders who blend oxygenate into gasoline downstream of the refinery that produced the gasoline or the import facility where the gasoline was imported, are not subject to the requirements of this subpart applicable to refiners for this gasoline, but are subject to the requirements and prohibitions applicable to downstream parties and the prohibition specified in § 80.385(e).
(a)
(2) Additional counties or tribal lands in states adjacent to the states identified in paragraph (a) of this section will be included in the GPA if any of the following criteria is met:
(i) Approximately 50% or more of the total volume of gasoline in the county or tribal land in 1999, as measured at the terminal(s) and bulk station(s) in the county or tribal land, was received from a refinery or refineries located in the area specified in paragraph (a)(1) of this section; or
(ii) Approximately 50% or more of the total volume of gasoline dispensed in the county or tribal land in 1999 was received from a refinery or refineries located in the area specified in paragraph (a)(1) of this section; or
(iii) Approximately 50% or more of the total commercial and private dispensing outlets in the county or tribal land in 1999 were supplied by gasoline produced by a refinery or refineries located in the area specified in paragraph (a)(1) of this section.
(3) The criteria of paragraphs (a)(2)(i), (ii) and (iii) of this section are without regard to the method of gasoline delivery (e.g, pipeline, truck, rail or barge). The criteria of paragraphs (a)(2)(ii) and (a)(2)(iii) of this section are without regard to whether the gasoline was transported directly from the refinery to the dispensing outlet or distributed through a terminal or bulk station.
(b)
(c)
(a)(1) The refinery or importer annual average sulfur standard for gasoline produced or imported for use in the geographic area under § 80.215 shall be the lesser of:
(i) 150 ppm; or
(ii) The refinery's or importer's 1997/1998 average sulfur level, calculated in accordance with § 80.295, plus 30 ppm.
(2) In the case of any refinery whose actual annual sulfur average decreases to a level lower than the refinery's annual average sulfur standard established under paragraph (a)(1) of this section during the period 2000 through 2003, the standard applicable to that refinery from 2004 through 2006 shall be the lowest average sulfur content for any year in which the refinery generated allotments or credits under § 80.275(a) or § 80.305 plus 30 ppm, not to exceed 150 ppm.
(b) The per-gallon cap standard for gasoline produced or imported for use in the GPA under paragraph (a) of this section shall be 300 ppm, except as specified in § 80.195(d).
(c) The refinery or importer annual average sulfur level is calculated in accordance with the provisions of § 80.205.
(d) The refinery or importer annual average standard under paragraph (a) of this section may be met using sulfur allotments or credits as provided under §§ 80.275 and 80.315.
(e) Gasoline produced by approved small refiners subject to the standards under § 80.240 is not subject to the standards under paragraphs (a) and (b) of this section.
(f)(1) A refiner or importer whose gasoline production or volume of imported gasoline in 2004 or 2005 is comprised of ≥50% of gasoline designated as GPA gasoline under § 80.219 shall not be required to meet the corporate pool average standards under § 80.195 for its gasoline production or imported gasoline during the applicable averaging period.
(2) A refiner or importer whose gasoline production or volume of imported gasoline in 2004 or 2005 is comprised of less than 50% of gasoline designated as GPA gasoline under § 80.219 must meet the corporate pool average standards under § 80.195 for all the refiner's gasoline production or the importer's volume of imported gasoline during the applicable averaging period.
(g) The provisions for compliance deficits under § 80.205(e) do not apply to gasoline subject to the standards under paragraphs (a) and (b) of this section.
(a) To apply for the GPA standards under § 80.216, a refiner or importer must submit an application in accordance with the provisions of § 80.290.
(b) Applications under paragraph (a) of this section must be submitted by December 31, 2000.
(c)(1) If approved, EPA will notify the refiner or importer of each refinery's or the importer's annual average sulfur standard for gasoline produced for use in the GPA for the 2004 through 2006 annual averaging periods.
(2) If disapproved, the refiner or importer must comply with the standards in § 80.195 for gasoline produced for use in the GPA.
(d) If EPA finds that a refiner or importer provided false or inaccurate
The requirements and prohibitions specified in this section apply during the period January 1, 2004 through December 31, 2006.
(a)
(b)
(i) Identification of the gasoline as being GPA gasoline;
(ii) A statement that the gasoline may not be distributed or sold for use outside the geographic phase-in area.
(2) Except for transfers to truck carriers, retailers and wholesale purchaser-consumers, product codes may be used to convey the information required by paragraph (b)(1) of this section if such codes are clearly understood by each transferee.
(3) The requirements under paragraph (b)(1) of this section are in addition to the requirement under § 80.210(e), where appropriate, to identify gasoline as being S-RGAS.
(c)
(i) Selling, offering for sale, dispensing, distributing, storing or transporting GPA gasoline for use outside the geographic phase-in area; and
(ii) Commingling GPA gasoline with gasoline not designated as GPA gasoline unless the mixture is classified as GPA gasoline.
(2) Gasoline not designated as GPA gasoline may be distributed or sold for use in the geographic phase-in area.
(a)
(2) During the period February 1, 2005 through January 31, 2007, the sulfur content of GPA gasoline at any downstream location other than at a retail outlet or wholesale purchaser-consumer facility, and during the period March 1, 2005 through February 28, 2007, the sulfur content of GPA gasoline at any downstream location shall not exceed 326 ppm.
(b)
(a) A
(ii) Employed an average of no more than 1,500 people, based on the average number of employees for all pay periods from January 1, 1998, to January 1, 1999; and
(iii) Had an average crude capacity less than or equal to 155,000 barrels per calendar day (bpcd) for 1998.
(2) For the purpose of determining the number of employees and crude capacity under paragraph (a)(1) of this section, the refiner shall include the employees and crude capacity of any subsidiary companies, any parent company and subsidiaries of the parent company, and any joint venture partners.
(b) The definition under paragraph (a) of this section applies to domestic and foreign refiners. For any refiner owned by a governmental entity, the number of employees as specified in paragraph (a) of this section shall include all employees of the governmental entity.
(c) If, without merger with, or acquisition of, another business unit, a company with approved small refiner status under § 80.235 exceeds 1,500 employees, or a corporate crude capacity of 155,000 bpcd after January 1, 1999, it will be considered a small refiner for the duration of the small refiner program.
(d) Notwithstanding the definition in paragraph (a) of this section, refiners who acquire a refinery after January 1, 1999, or reactivate a refinery that was shutdown or was non-operational between January 1, 1998, and January 1, 1999, may apply for small refiner status in accordance with the provisions of § 80.235.
(a) The following are not eligible for the hardship provisions for small refiners:
(1) Refiners of refineries built after January 1, 1999;
(2) Refiners who exceed the employee or crude oil capacity criteria under § 80.225(a) on January 1, 1999, but who meet these criteria after that date, regardless of whether the reduction in employees or crude capacity is due to operational changes at the refinery or a company sale or reorganization;
(3) Importers; and
(4) Refiners who produce gasoline other than by processing crude oil through refinery processing units.
(b)(1) Refiners who qualify as small under § 80.225, and subsequently employ more than 1,500 people as a result of merger with or acquisition of or by another entity, are disqualified as small refiners. If this occurs the refiner shall notify EPA in writing no later than 20 days following this disqualifying event.
(2) Any refiner who qualifies as small under § 80.225 may elect to meet the standards under § 80.195 by notifying EPA in writing no later than November 15 prior to the year the change will occur.
(3) Any refiner whose status changes under paragraph (b)(1) or (2) of this section shall meet the standards under § 80.195 beginning with the first averaging period subsequent to the status change.
(a) Applications for small refiner status must be submitted to EPA by December 31, 2000, except for applications submitted pursuant to § 80.225(d), which must be submitted by June 1, 2002.
(b) Applications for small refiner status must be sent to: U.S. EPA, Attn: Sulfur Program (6406J), 401 M Street, SW, Washington, DC 20460. For commercial delivery: U.S. EPA, Attn: Sulfur Program (6406J), 501 3rd Street, NW, Washington, DC 20001.
(c) The small refiner status application must contain the following information for the company seeking
(1)(i) A listing of the name and address of each location where any employee worked during the 12 months preceding January 1, 1999; the average number of employees at each location based upon the number of employees for each pay period for the 12 months preceding January 1, 1999; and the type of business activities carried out at each location; or
(ii) In the case of a refiner who acquires a refinery after January 1, 1999, or reactivates a refinery that was shutdown between January 1, 1998, and January 1, 1999, a listing of the name and address of each location where any employee of the refiner worked since the refiner acquired or reactivated the refinery; the average number of employees at any such acquired or reactivated refinery during each calendar year since the refiner acquired or reactivated the refinery; and the type of business activities carried out at each location.
(2) The total corporate crude capacity of each refinery as reported to the Energy Information Administration (EIA) of the U.S. Department of Energy (DOE). The information submitted to EIA is presumed to be correct. In cases where a company disagrees with this information, the company may petition EPA with appropriate data to correct the record within 60 days after the company submits its application for small refiner status.
(3) A letter signed by the president, chief operating or chief executive officer of the company, or his/her designee, stating that the information contained in the application is true to the best of his/her knowledge.
(4) Name, address, phone number, facsimile number and E-mail address (if available) of a corporate contact person.
(d) For joint ventures, the total number of employees includes the combined employee count of all corporate entities in the venture.
(e) For government-owned refiners, the total employee count includes all government employees.
(f) Approval of small refiner status for refiners who apply under § 80.225(d) will be based on all information submitted under paragraph (c) of this section. Where appropriate, the employee and crude oil capacity criteria for such refiners will be based on the most recent 12 months of operation.
(g) EPA will notify a refiner of approval or disapproval of small refiner status by letter.
(1) If approved, EPA will notify the refiner of each refinery's applicable baseline standard and volume, and per-gallon cap under § 80.240.
(2) If disapproved, the refiner must comply with the standards in § 80.195.
(h) If EPA finds that a refiner provided false or inaccurate information on its application for small refiner status, upon notice from EPA the refiner's small refiner status will be void ab initio.
(i) Upon notification to EPA, an approved small refiner may withdraw its status as a small refiner. Effective on January 1 of the year following such notification, the small refiner will become subject to the standards at § 80.195.
(a) The gasoline sulfur standards for an approved small refiner are as follows:
(b) The refinery annual average sulfur standards must be met on an annual calendar year basis for each refinery owned by a small refiner. The refinery annual average sulfur level is calculated in accordance with the provisions of § 80.205.
(c)(1) The refinery annual average standards specified in paragraph (a) of this section apply to the volume of gasoline produced by a small refiner's refinery up to the lesser of:
(i) 105% of the baseline gasoline volume as determined under § 80.250(a)(1); or
(ii) The volume of gasoline produced at that refinery during the averaging period by processing crude oil.
(2) If a refiner exceeds the volume limitation in paragraph (c)(1) of this section during any averaging period, the annual average sulfur standard applicable to the refiner for that averaging period is calculated as follows:
(3) The small refiner average standards under paragraph (a) of this section may be met using sulfur allotments or credits as provided under § 80.275 or § 80.315.
(4) The provisions for compliance deficits under § 80.205(e) do not apply to small refiners subject to the standards under this section.
(d) In the case of any refiner with small refiner status who generates sulfur allotments or credits pursuant to § 80.275(a) or § 80.305, the baseline applicable to that refiner's refinery for purposes of establishing the standard for the refinery under paragraph (a) of this section beginning in 2004 shall be the lowest annual average sulfur content for any year during the period in which the refiner generated allotments or credits.
(a) Any refiner seeking small refiner status must apply for a refinery sulfur baseline by the deadline under § 80.235 for each of the refiner's refineries by providing the following information:
(1) A sulfur baseline and baseline volume for every refinery calculated in accordance with § 80.250.
(2) The following information for each batch of gasoline produced in 1997-1998:
(i) Batch number assigned to the batch under § 80.65(d) or § 80.101(i);
(ii) Volume; and
(iii) Sulfur content.
(3) For any refiner who acquires a refinery after January 1, 1999, or reactivates a refinery that was shut down or non-operational between January 1, 1998, and January 1, 1999, the average sulfur level and average volume of gasoline produced during each year the refinery was in operation after the refinery was acquired or reactivated. Where appropriate, the baseline sulfur level and volume for such refineries will be determined based on the annual average for the most recent year of operation.
(b) The sulfur baseline application must be submitted to the address specified in § 80.235(b).
(a)(1) The small refiner baseline volume is determined for each refinery as follows:
(2) The small refiner sulfur baseline is determined for each refinery as follows:
(b) Foreign refiners who do not have an approved refinery baseline under § 80.94 must follow the procedures specified in § 80.410(b).
(c) If at any time a small refinery baseline is determined to be incorrect, the corrected baseline applies ab initio and the annual average standards and cap standards are deemed to be those applicable under the corrected information.
The requirements of this section apply to any refiner approved for small refiner standards who wishes to be eligible for a hardship extension under § 80.260.
(a)
(b)
(A) Copies of approved permits for construction of the equipment, or the permit application if approval is still pending;
(B) Copies of contracts for design and construction; and
(C) Any available evidence of having secured the necessary financing to complete the required construction;
(ii) If the refiner anticipates any difficulties in meeting its compliance commitments under this section, the refiner must submit a detailed report of all efforts made to date and the factors that may cause delay, including costs, specification of engineering or other design work needed and reasons for delay, specification of equipment needed and any reasons for delay, potential equipment suppliers and history of negotiations, and any other relevant information. If unavailability of equipment is a factor, the report must include a discussion of other options considered and the reasons these other options are not feasible.
(2) By no later than June 1, 2006, the small refiner must submit to EPA evidence that on-site construction has begun and that, absent unforeseen difficulties, the small refiner will be producing complying gasoline by January 1, 2008. If construction has not begun, the refiner must demonstrate that it has made all reasonable efforts to begin construction, that substantial progress is being made to begin construction as soon as possible, and that construction can be completed in time to begin production of gasoline that complies with the standards of § 80.195 by January 1, 2008.
(c)
(d)
(a) An approved small refiner who has filed the reports specified in § 80.255 may apply to EPA for a hardship extension of the small refiner standards for calendar years 2008 and 2009. The application must be submitted in writing no later than January 1, 2007, to U.S. EPA, Attn: Sulfur Program (6406J), 401 M Street, SW, Washington, DC 20460. For commercial (non-postal) delivery: U.S. EPA, Attn: Sulfur Program, 501 3rd Street NW, Washington, DC 20001.
(b) The application must specify the factors that demonstrate a significant economic hardship and must provide a detailed discussion regarding the inability of the refinery to produce gasoline meeting the requirements of § 80.195. Such an application must include, at a minimum, the following information:
(1) Documentation of efforts made to obtain necessary financing, including:
(i) Copies of loan applications for the necessary financing of the construction of appropriate sulfur reduction technology and other equipment procurements or improvements; and
(ii) If financing has been disapproved or is otherwise unsuccessful, documents supporting the basis for that disapproval and evidence of efforts to pursue other means of financing;
(2) A detailed analysis of the reasons the refinery is unable to produce gasoline meeting the standards of
(3) If unavailability of equipment is part of the reason for the inability to comply, a discussion of other options considered, and the reasons these other options are not feasible;
(4) If relevant, a demonstration that a needed or lower cost technology is immediately unavailable, but will be available in the near future, and full information regarding when and from what sources it will be available;
(5) Schematic drawings of the refinery configuration as of January 1, 1999, and as of the date of the hardship extension application, and any planned future additions or changes;
(6) If relevant, a demonstration that a temporary unavailability exists of engineering or construction resources necessary for design or installation of the needed equipment;
(7) If sources of crude oil lower in sulfur than what the refiner is currently using are available, full information regarding the availability of these different crude sources, the sulfur content of those crude sources, the cost of the different crude sources over the past five years, and an estimate of gasoline sulfur levels achievable by the refinery if the lower sulfur crude sources were used;
(8) A discussion of any sulfur reductions that can be achieved from current levels;
(9) The date the refiner anticipates compliance with the standards in § 80.195 can be achieved at its refinery;
(10) An analysis of the economic impact of compliance on the refiner's business (including financial statements from the last 5 years, or for any time period up to 10 years, at EPA's request); and
(11) Any other information regarding other strategies considered, including strategies or components of strategies that do not involve installation of equipment, and why meeting the standards in § 80.195 beginning in 2008 is infeasible.
(c) The hardship extension application must contain a letter signed by the president or the chief operating or chief executive officer of the company, or his/her designee, stating that the information contained in the application is true to the best of his/her knowledge.
(a) EPA will evaluate each application for hardship extension on a case-by-case basis. The factors considered for a hardship extension may include: The refiner's financial position and efforts to obtain capital funding; the refiner's efforts to procure necessary equipment, obtain design and engineering services and construction contractors; the availability of desulfurization equipment; and any other relevant factor. An extension will be granted for a refinery for the 2008 averaging period if the small refiner who owns the refinery adequately demonstrates that severe economic hardship would result if compliance with the standards in § 80.195 is required in 2008, or that compliance with the standard in 2008 is not feasible for reasons beyond the refiner's control, and that the refiner has made the best efforts possible to achieve compliance with the national standards by January 1, 2008. Upon reapplication by the refiner, if EPA determines that further relief is appropriate, EPA may grant a further extension through the 2009 averaging period. In no case will a further extension for the 2009 averaging period be granted unless the refiner demonstrates conclusively that it has financing in place and that it will be able to complete construction and meet the national gasoline sulfur standards no later than December 31, 2009.
(b) EPA may request more information, if necessary, for evaluation of the application. If requested information is not submitted within the time specified in EPA's request, or any extensions granted, the application may be denied.
(c) EPA will notify the refiner of approval or disapproval of hardship extension by letter.
(1) If approved, EPA will also notify the refiner of the date that full compliance with the standards specified at § 80.195 must be achieved or what interim sulfur levels or schedules apply, if any.
(2) If disapproved, beginning January 1, 2008, the refinery is subject to the requirements in § 80.195. Refiners who receive an extension for the 2008 averaging period shall meet the standards in § 80.195 beginning on January 1, 2009, unless EPA grants an extension of the hardship relief for an additional year. If such an additional extension is granted, the refiner shall meet the standards in § 80.195 on January 1, 2010.
(d) Refiners who receive a hardship extension may be required to meet more stringent standards than those which apply to them during 2007, and/or could be required to offset excess sulfur levels. EPA may impose reasonable conditions on an extension, such as requiring segregation of the small refiner's gasoline or requiring the gasoline to be sold for use in older vehicles only.
(a) EPA may permit a refiner to produce and distribute gasoline which does not meet the requirements of this subpart if the refiner demonstrates that:
(1) Unusual circumstances exist that impose extreme hardship and significantly affect ability to comply by the applicable date; and
(2) It has made best efforts to comply with the requirements of this subpart (including making efforts to obtain credits and/or allotments).
(b) Applications must be submitted to EPA by September 1, 2000. Relief may be granted from some or all of the requirements of this subpart, at EPA's discretion; however, EPA reserves the right to deny applications for appropriate reasons, including unacceptable environmental impact. Approval to distribute gasoline which does not meet the requirements of this subpart may be granted for such time period as EPA determines is appropriate, but shall not extend beyond January 1, 2008.
(c)(1) Applications must include a plan demonstrating how the refiner will comply with the requirements of this subpart as expeditiously as possible. The plan shall include a showing that contracts are or will be in place for engineering and construction of desulfurization equipment, a plan for applying for and obtaining any permits necessary for construction, a description of plans to obtain necessary capital, and a detailed estimate of when the requirements of this subpart will be met.
(2) Applications must include a detailed description of the refinery configuration and operations, including, at a minimum, the following information:
(i) The portion of gasoline production that is produced using an FCC unit;
(ii) The refinery's hydrotreating capacity;
(iii) The refinery's total reformer unit throughput capacity;
(iv) The refinery's total crude capacity;
(v) Total crude capacity of any other refineries owned by the same entity;
(vi) Total volume of gasoline production at the refinery;
(vii) Total volume of other refinery products; and
(viii) Geographic location(s) in which gasoline will be sold.
(3) Applications must include, at a minimum, the following information:
(i) Detailed description of efforts to obtain capital for refinery investments;
(ii) Bond rating of entity that owns the refinery; and
(iii) Estimated capital investment needed to comply with the requirements of this subpart by the applicable date.
(4) Applicants must also provide any other relevant information requested by EPA.
(d) EPA may impose any reasonable conditions on waivers granted under this section.
(a)
(2) If the average sulfur content of the gasoline produced at a refinery is less than the refinery's baseline as determined under § 80.295 and is 60 ppm or less, allotments and credits may be generated using the following procedures. This paragraph (a) does not apply to importers.
(i) If the average sulfur content of the gasoline produced at a refinery is less than or equal to 30, and the refinery's sulfur baseline is greater than 120, the following procedures apply:
(ii) If the average sulfur content of the gasoline produced at a refinery is less than or equal to 30, and the refinery's sulfur baseline is greater than 30 but less than or equal to 120, the following procedures apply:
(iii) If the average sulfur content of the gasoline produced at a refinery is less than or equal to 30, and the refinery's sulfur baseline is less than or equal to 30, the following procedures apply:
(iv) If the average sulfur content of the gasoline produced at a refinery is greater than 30, and the refinery's sulfur baseline is greater than 120, the following procedures apply:
(v) If the average sulfur content of the gasoline produced at a refinery is greater than 30, and the refinery's sulfur baseline is less than or equal to 120, the following procedures apply:
(vi) For purposes of the equations under paragraphs (a)(2)(i) through (v) of this section, the following definitions apply:
(b)
(1) If the average sulfur content of the gasoline produced or imported is less than 30 the following procedures apply:
(2) If the average sulfur content of the gasoline produced or imported is equal to or greater than 30 the following procedures apply:
(3) For purposes of the equations under paragraphs (b)(1) and (2) of this section, the following definitions apply:
(c)
(2) Small refiners subject to the standards under § 80.240, and refiners and importers of gasoline designated as GPA gasoline under § 80.219(a), may use sulfur allotments to meet their annual average refinery or importer standards.
(d)
(1) No allotment may be transferred more than twice: The first transfer by the refiner or importer who generated the allotment may only be made to a refiner or importer who intends to use the allotment; if the transferee cannot use the allotment, it may make the second, and final, transfer only to a refiner or importer who intends to use the allotment. In no case may an allotment be transferred more than twice before being used or terminated.
(2) The allotment transferor must apply any allotments necessary to meet the transferor's corporate pool average standard before transferring allotments to any other refiner or importer or before converting allotments into credits.
(3) The transferor must supply to the transferee records indicating the year of generation and type of the allotments, the identity of the refiner or importer who generated the allotments, and the identity of the transferring party, if it is not the same part that generated the allotments.
(4) The transferor must inform the transferee whether any transferred allotments are Type A allotments or Type B allotments, as defined in paragraphs (a) and (b) of this section.
(5) In the case of allotments that have been calculated or created improperly, or are otherwise determined to be invalid, the following provisions apply:
(i) Invalid allotments cannot be used to achieve compliance with the transferee's corporate pool average standard or be converted to credits, regardless of the transferee's good faith belief that the allotments were valid.
(ii) The refiner or importer who used the allotments, and any transferor of the allotments, must adjust their allotment records and reports and sulfur calculations as necessary to reflect the proper allotments.
(iii) Any allotments remaining after correcting for the improperly created allotments must first be applied to correct the invalid transfers before the transferor may transfer any other allotments or before converting allotments into credits.
(e)
(1) Type A allotments may be converted into credits with the same requirements and limitations on use that
(2) Type B allotments may be converted into credits with the same requirements and limitations on use that apply under § 80.315 to credits generated in 2004 and later, based on the year of creation of the allotment.
(f)
(g)
(a)
(i) Refiners who establish a sulfur baseline under § 80.295;
(ii) Foreign refiners with approved baselines under § 80.94, or baselines established in accordance with § 80.410; or
(iii) Small refiners for any refinery subject to the standards under § 80.240, using their small refiner baseline established under § 80.250.
(2) Importers and oxygenate blenders may not generate credits under § 80.305.
(b)
(i) Refiners and importers subject to the standards under § 80.195;
(ii) Refiners and importers of gasoline designated as GPA gasoline under § 80.219, using the lesser of: 150 ppm; or the refiner's or importer's baseline calculated under § 80.295; or the refinery's lowest annual average sulfur content for any year from 2000 through 2003 during which the refiner generated credits (for any party generating credits under both paragraph (b)(1)(i) of this section and this paragraph (b)(1)(ii), such credits must be calculated separately); or
(iii) Small refiners for any refinery subject to the standards under § 80.240, using refinery's standard established under § 80.240.
(2) Generation of credits for all imported gasoline shall be through the importer.
(3) Oxygenate blenders may not generate credits under § 80.310.
(a) The refiner must submit an application to EPA which includes the information required under paragraph (c) of this section no later than September 30 of the year in which the refiner plans to begin generating credits, or the refiner or an importer plans to sell gasoline in the geographic phase-in area in accordance with § 80.217.
(b) The sulfur baseline request must be sent to: U.S. EPA, Attn: Sulfur Program (6406J), 401 M Street SW., Washington, DC 20460. For commercial (non-postal) delivery: U.S. EPA, Attn: Sulfur Program, 501 3rd Street NW., Washington, DC 20001.
(c) The sulfur baseline application must include the following information:
(1) A listing of the names and addresses of all refineries owned by the corporation for which the refiner is applying for a sulfur baseline.
(2) The annual average gasoline sulfur baseline for gasoline produced in 1997-1998, for each refinery for which the refiner is applying for a sulfur baseline, calculated in accordance with § 80.295.
(3) A letter signed by the president, chief operating or chief executive officer, of the company, or his/her delegate, stating that the information contained in the sulfur baseline determination is true to the best of his/her knowledge.
(4) Name, address, phone number, facsimile number and E-mail address of a corporate contact person.
(5) The following information for each batch of gasoline produced in 1997-1998:
(i) Batch number assigned to the batch under § 80.65(d) or § 80.101(i);
(ii) Volume; and
(iii) Sulfur content.
(d) Foreign refiners who do not have an approved refinery baseline under § 80.94 must follow the procedures specified in § 80.410(b).
(e) Within 60 days of receipt of an application under this section, EPA will notify the refiner of approval of the refinery's baseline or of any deficiencies in the application.
(f) If at any time the baseline submitted in accordance with the requirements of this section is determined to be incorrect, EPA will notify the refiner of the corrected baseline.
(g) Any refiner that seeks temporary relief under § 80.270 shall apply for a refinery sulfur baseline in accordance with the provisions of this section and § 80.295, and if applicable, § 80.410(b), no later than September 1, 2000.
(a) A refinery's gasoline sulfur baseline for the purpose of generating credits during years 2000 through 2003 is calculated using the following equation:
(b) Any refiner who, under § 80.65 or § 80.101(d)(4), included oxygenate blended downstream in compliance calculations for 1997-1998 must include this oxygenate in the baseline calculations for sulfur content under paragraph (a) of this section.
(a) Credits must be calculated as follows:
CR
(b) The refiner may include any oxygenates included in its RFG or conventional gasoline volume under §§ 80.65 and 80.101(d)(4), respectively, for the purpose of generating credits.
(c) Credits under this program are in units of “ppm-gallons”.
(d) Refiners may generate credits for gasoline produced during an averaging period only if the annual average sulfur level for the gasoline produced during the averaging period is less than 0.90 of the refiners baseline under § 80.250 or § 80.295.
(e) Credits generated in accordance with paragraph (a) of this section must be identified by the year of creation.
(a) A refiner for any refinery, or an importer, may generate credits in 2004 and thereafter if the annual average sulfur level for gasoline produced or imported for the averaging period is less than the applicable refinery or importer annual average sulfur standard for that refinery or importer in that year.
CR
(c) Credits generated in accordance with this section must be identified by the year of creation.
(a)
(1) Sulfur credits used were generated pursuant to the requirements of this subpart; and
(2) The requirements of paragraphs (b) and (c) of this section are met.
(b)
(i) The credits are generated and reported according to the requirements of this subpart.
(ii) The credits are used in compliance with the limitations regarding the appropriate periods for credit use in this subpart.
(iii) Any credit transfer takes place no later than the last day of February following the calendar year averaging period when the credits are used.
(iv) No credit may be transferred more than twice: The first transfer by the refiner or importer who generated the credit may only be made to a refiner or importer who intends to use the credit; if the transferee cannot use the credit, it may make the second, and final, transfer only to a refiner or importer who intends to use the credit. In no case may a credit be transferred more than twice before being used or terminated.
(v) The credit transferor must apply any credits necessary to meet the transferor's applicable average standard before transferring credits to any other refiner or importer.
(vi) No credits may be transferred that would result in the transferor having a negative credit balance.
(vii) Each transferor must supply to the transferee records indicating the years the credits were generated, the identity of the refiner or importer who generated the credits, and the identity of the transferring party, if it is not the same party that generated the credits.
(2) In the case of credits that have been calculated or created improperly, or are otherwise determined to be invalid, the following provisions apply:
(i) Where a refiner's baseline has been determined to be incorrect under § 80.250(c) or § 80.290(f), any credits generated, banked, used or traded must be adjusted to reflect the corrected baseline.
(ii) Invalid credits cannot be used to achieve compliance with the transferee's averaging standard, regardless of the transferee's good faith belief that the credits were valid.
(iii) The refiner or importer who used the credits, and any transferor of the credits, must adjust their credit records and reports and sulfur calculations as necessary to reflect the proper credits.
(iv) Any properly created credits existing in the transferor's credit balance after correcting the credit balance, and after the transferor applies credits as needed to meet the average standard at the end of the compliance year, must first be applied to correct the invalid transfers before the transferor trades or banks the credits.
(c)
(2) Credits generated in 2004 or later may only be used for demonstrating compliance with standards during an averaging period within five years of the year of generation.
(3) A refiner or importer possessing credits must use all credits prior to falling into compliance deficit under § 80.205(e).
(4) Credits may not be used to meet corporate pool average standards under § 80.195.
(a)
(2) Except as provided in paragraph (a)(3) of this section, the requirements of this section apply beginning January 1, 2004, or January 1 of the first year of allotment or credit generation under § 80.275 or § 80.305, whichever is earlier.
(3) Prior to January 1, 2004, for purposes of meeting the sampling and testing requirements of this section for conventional gasoline, any refiner may, prior to analysis, combine samples of gasoline from more than one batch of gasoline or blendstock and treat such composite sample as one batch of gasoline or blendstock pursuant to the requirements of § 80.101(i)(2).
(4) Any refiner who produces reformulated gasoline or conventional gasoline using computer-controlled in-line blending equipment may meet the testing requirement of paragraph (a)(1) of this section under the terms of an exemption granted under § 80.65(f)(4).
(b)
(1) Manual sampling of tanks and pipelines shall be performed according to the applicable procedures specified in one of the two following methods:
(i) American Society for Testing and Materials (ASTM) method D 4057-95, entitled “Standard Practice for Manual Sampling of Petroleum and Petroleum Products.”
(ii) Samples collected under the applicable procedures in ASTM method D 5842-95, entitled “Standard Practice for Sampling and Handling of Fuels for Volatility Measurement,” may be used for measuring sulfur content if there is no contamination present that could affect the sulfur test result.
(2) Automatic sampling of petroleum products in pipelines shall be performed according to the applicable procedures specified in ASTM method D 4177-95, entitled “Standard Practice for Automatic Sampling of Petroleum and Petroleum Products.”
(c)
(2) Except as provided in § 80.350 and in paragraph (c)(1) of this section, any ASTM sulfur test method for liquefied fuels may be used for quality assurance testing under § 80.400, or to determine whether gasoline qualifies for a S-RGAS downstream standard, if the protocols of the ASTM method are followed and the alternative method is correlated to the method provided in § 80.46(a)(1).
(d)
(2) Except as provided in paragraph (d)(1) of this section, any ASTM sulfur test method for gaseous fuels may be used for quality assurance testing under §§ 80.340(b)(4) and 80.400, if the protocols of the ASTM method are followed and the alternative method is correlated to the method provided in § 80.46(a)(2).
(e)
(a)
(1) Collect a representative portion of each sample analyzed under § 80.330(a), of at least 330 ml in volume;
(2) Retain sample portions for the most recent 20 samples collected, or for each sample collected during the most recent 21 day period, whichever is greater;
(3) Comply with the gasoline sample handling and storage procedures under § 80.330(b) for each sample portion retained; and
(4) Comply with any request by EPA to:
(i) Provide a retained sample portion to the Administrator's authorized representative; and
(ii) Ship a retained sample portion to EPA, within 2 working days of the date of the request, by an overnight shipping service or comparable means, to the address and following procedures specified by EPA, and accompanied with the sulfur test result for the sample determined under § 80.330(a).
(b)
(2) For samples retained by an independent laboratory under paragraph (b) of this section, the test results required to be submitted under paragraph (a) of this section shall be the test results determined under § 80.65(e).
(c)
I certify that I have made inquiries that are sufficient to give me knowledge of the procedures to collect and store gasoline samples, and I further certify that the procedures meet the requirements of the ASTM procedures required under 40 CFR 80.330.
(a) Any refiner who produces gasoline by blending blendstock into PCG must meet the requirements of § 80.330 to sample and test every batch of gasoline as follows:
(1)(i) Sample and test to determine the volume and sulfur content of the PCG prior to blendstock blending.
(ii) Sample and test to determine the volume and sulfur content of the gasoline subsequent to blendstock blending.
(iii) Calculate the volume and sulfur content of the blendstock, by subtracting the volume and sulfur content of the PCG from the volume and sulfur content of the gasoline subsequent to blendstock blending. The blendstock is a batch for purposes of compliance calculations and reporting. For purposes of this paragraph (a), compliance with the applicable cap standard under § 80.195(a) shall be determined based on the sulfur content of the gasoline subsequent to blendstock blending.
(2) In the alternative, a refiner may sample and test each batch of blendstock when received at the refinery to determine the volume and sulfur content, and treat each blendstock receipt as a separate batch for purposes of compliance calculations for the annual average sulfur standard and for reporting. This alternative applies only if every batch of blendstock used at a refinery during an averaging period has a sulfur content that is equal to, or less than, the applicable per-gallon cap standard under §§ 80.195 or 80.216.
(b) Refiners who blend only butane into PCG may meet the sampling and testing requirements by using sulfur test results of the butane supplier, provided that the following requirements are also met:
(1) The sulfur content of the butane received from the butane supplier must not exceed the following sulfur standards on a per-gallon basis as follows:
(i) 120 ppm in 2004, and 30 ppm for 2005 and any subsequent year;
(ii) Except that the per-gallon sulfur content of butane blended to PCG that is designated as GPA gasoline shall not exceed 150 ppm from January 1, 2004, through December 31, 2006.
(2) The refiner obtains test results from the butane supplier that demonstrate that the sulfur content of
(i) Testing for the sulfur content of the butane by the supplier must be subsequent to each receipt of butane into the supplier's storage tank, or the testing must be immediately before transfer of butane to the butane blender.
(ii) The testing must be performed by the method specified in § 80.46(a)(2).
(iii) The butane blender must obtain a copy of the butane supplier's test results, at the time of each transfer of butane to the butane blender, that reflect the sulfur content of each load of butane supplied to the butane blender.
(3) The sulfur content and volume of each batch of gasoline produced is that of the butane the refiner blends into gasoline for purposes of calculating compliance with the standards in §§ 80.195 and 80.216.
(4) The refiner must conduct a quality assurance program of sampling and testing for each butane supplier that demonstrates the butane sulfur content does not exceed the applicable per-gallon sulfur standard in paragraph (b)(1) of this section. The frequency of butane sampling and testing, for each butane supplier, must be one sample for every 500,000 gallons of butane received, or one sample every 3 months, whichever results in more frequent sampling.
(5) If any of the requirements of this section are not met, in whole or in part, for any butane blended into gasoline, that butane is deemed in violation of the gasoline sulfur standards in § 80.195 or § 80.216, as applicable.
Importers who import gasoline into the United States by truck may comply with the following requirements instead of the requirements to sample and test every batch of gasoline under § 80.330, and the annual sulfur average and per-gallon cap standards otherwise applicable to importers under §§ 80.195 and 80.216:
(a)
(1) The applicable average standards, corporate average standards and per-gallon standards under § 80.195(a)(1), except that imported gasoline designated for use in the geographic phase-in area from January 1, 2004, through December 31, 2006 must comply with an average standard of 150 ppm and a per-gallon standard of 300 ppm; or
(2) In 2004, a per-gallon standard of 120 ppm, and in 2005 and subsequent years a per-gallon standard of 30 ppm, except that imported gasoline designated for use in the geographic phase-in area from January 1, 2004, through December 31, 2006 must comply with a per-gallon standard of 150 ppm.
(b)
(1) The sampling and testing shall be performed after each receipt of gasoline into the storage tank, or immediately before each transfer of gasoline to the importer's truck.
(2) The sampling and testing shall be performed using the methods specified in § 80.330(b) and 80.46(a)(1), respectively.
(3) At the time of each transfer of gasoline to the importer's truck for import to the U.S., the importer must obtain a copy of the terminal test result that indicates the sulfur content of the truck load.
(c)
(1) Quality assurance samples must be obtained from the truck-loading terminal and tested by the importer, or by an independent laboratory, and the terminal operator must not know in advance when samples are to be collected.
(2) The sampling and testing must be performed using the methods specified in §§ 80.330(b) and 80.46(a)(1), respectively.
(3) The quality assurance test results for sulfur must differ from the terminal test result by no more than the ASTM reproducibility of the terminal's test results, as determined by the following equation:
(4) The frequency of the quality assurance sampling and testing must be at least one sample for each fifty of an importer's trucks that are loaded at a terminal, or one sample per month, whichever is more frequent.
(d)
(e)
(f)
(g)
(h)
(1) All importer recordkeeping and reporting requirements under §§ 80.365 and 80.370, except as provided in paragraph (h)(2) of this section.
(2) An importer who elects to comply with the alternative standards in paragraph (a)(2) of this section must certify in the annual report whether it is in compliance with the applicable per-gallon batch standard set forth in paragraph (a)(2) of this section, in lieu of providing the information required by § 80.370(a) regarding annual average sulfur content and compliance with the average standard under § 80.195.
(i)
(a)
(1) The product transfer document information required under §§ 80.77, 80.106, 80.210 and 80.219; and
(2) For any sampling and testing for sulfur content required under this subpart:
(i) The location, date, time and storage tank or truck identification for each sample collected;
(ii) The name and title of the person who collected the sample and the person who performed the test;
(iii) The results of the test as originally printed by the testing apparatus, or where no printed result is produced, the results as originally recorded by the person who performed the test; and
(iv) Any record that contains a test result for the sample that is not identical to the result recorded under paragraph (a)(2)(iii) of this section.
(b)
(1) For each batch of gasoline produced or imported:
(i) The batch volume;
(ii) The batch number assigned under § 80.65(d)(3) and the appropriate designation under paragraph (b)(1)(i) of this section; except that if composite samples of conventional gasoline representing multiple batches produced subsequent to December 31, 2003, are tested under § 80.101(i)(2) for anti-dumping compliance purposes, for purposes of this subpart a separate batch number must be assigned to each batch using the batch numbering procedures under § 80.65(d)(3);
(iii) The date of production or importation; and
(iv) If appropriate, the designation of the batch as GPA gasoline under § 80.219, California gasoline under § 80.375, exempt gasoline for research and development under § 80.380, or for export outside the United States.
(2) Information regarding credits and allotments, separately kept for credits and for allotments; separately kept according to the year of creation for the credits and for the allotments; and for credit generation or use starting in 2004, separately kept for GPA gasoline and other gasoline. Information shall be kept separately for different types of allotments and credits generated under §§ 80.275(e)(1), 80.275(e)(2), 80.305 and 80.310:
(i) The number in the refiner's or importer's possession at the beginning of the averaging period;
(ii) The number generated;
(iii) The number used;
(iv) If any were obtained from or transferred to other parties, for each other party its name, its EPA refiner or importer registration number, and the number obtained from, or transferred to, the other party;
(v) The number that expired at the end of the averaging period;
(vi) The number of allotments, by type, that were converted into credits under § 80.275(e);
(vii) The number in the refiner's or importer's possession that will carry over into the subsequent averaging period; and
(viii) Contracts or other commercial documents that establish each transfer of credits and allotments from the transferor to the transferee.
(3) The calculations used to determine the applicable refiner baseline under § 80.250 or § 80.295.
(4) The calculations used to determine compliance with the applicable sulfur average standards of § 80.195, § 80.216, § 80.240, or § 80.270.
(5) The calculations used to determine the number of credits or allotments generated under § 80.305, § 80.310 or § 80.275.
(6) The calculations used to determine any applicable adjusted cap standard under § 80.195(d).
(7) A copy of all reports submitted to EPA under § 80.370.
(c)
(d)
(1)
(2)
(ii) Where early credits are transferred, records relating to such credits shall be kept by both parties for 5 years from the date the credits were transferred, used or terminated, whichever is later.
(e)
Beginning with the 2004 averaging period, or the first year credits or allotments are generated under § 80.275 or § 80.305, whichever is earlier, and continuing for each averaging period thereafter, any refiner or importer shall submit to EPA annual reports that contain the information required in this section, and such other information as EPA may require.
(a)
(1) The EPA importer, or refiner and refinery facility registration numbers;
(2) The applicable baseline, average standard, and adjusted cap standard as follows:
(i) For the years 2000 through 2003, the applicable baseline under § 80.250 or § 80.295.
(ii) For the 2004 averaging period and subsequent averaging periods:
(A) All applicable average standards under § 80.195, § 80.216, § 80.240 or § 80.270;
(B) All applicable adjusted cap standards under § 80.195(d), with the 2005 report identifying both the 2004 and 2005 applicable adjusted cap standards;
(3) The total volume of gasoline produced or imported;
(4) The annual average sulfur content of the gasoline produced or imported;
(5) The annual average sulfur level after inclusion of any credits and allotments;
(6) Information, separately provided, for credits and allotments, and separately by year of creation, as follows:
(i) The number of credits and allotments at the beginning of the averaging period;
(ii) The number of credits and allotments generated;
(iii) The number of credits and allotments used;
(iv) If any credits or allotments were obtained from or transferred to other parties, for each other party its name and EPA refiner or importer registration number, and the number of credits or allotments obtained from or transferred to the other party;
(v) The number of credits and allotments that expired at the end of the averaging period;
(vi) The number of credits and allotments that will carry over into the subsequent averaging period; and
(vii) The number of each type of allotments converted to credits;
(7) For each batch of gasoline produced or imported during the averaging period:
(i) The batch number assigned under § 80.65(d)(3) and the appropriate designation under § 80.365; except that if composite samples of conventional gasoline representing multiple batches produced subsequent to December 31, 2003, are tested under § 80.101(i)(2) for anti-dumping compliance purposes, for purposes of this subpart a separate batch number must be assigned to each batch using the batch numbering procedures under § 80.65(d)(3);
(ii) The date the batch was produced;
(iii) The volume of the batch; and
(iv) The sulfur content of the batch as determined under § 80.330; and
(8) When submitting reports under this paragraph (a), any importer shall exclude certified Sulfur-FRGAS.
(b)
(1) The EPA refiner and refinery registration numbers of each foreign refiner and refinery where the certified Sulfur-FRGAS was produced; and
(2) The total gallons of certified Sulfur-FRGAS and non-certified Sulfur-FRGAS imported from each foreign refiner and refinery.
(c)
(2) If the party submitting the annual report under paragraph (c)(1) of this section is a refiner with more than one refinery or is a refiner who also imports gasoline, then for the purposes of this paragraph, the party shall report the information required for individual refineries and for importers under paragraph (a) of this section, also in the aggregate for all the gasoline produced and imported during the calendar year.
(3) Refiners and importers exempted from corporate pool standards under § 80.216 or § 80.240 are exempt from reporting the information required under paragraphs (c)(1) and (c)(2) of this section.
(d)
(1) Signed and certified as meeting all of the applicable requirements of this subpart by the owner or a responsible corporate officer of the refiner or importer; and
(2) Submitted to EPA no later than the last day of February for the prior calendar year averaging period.
(f)
In appropriate extreme and unusual circumstances (
(a)
(b)
(c)
(1) Each batch of California gasoline must be designated as such by its refiner or importer;
(2) Designated California gasoline must be kept segregated from gasoline that is not California gasoline, at all points in the distribution system;
(3) Designated California gasoline must ultimately be used in the State of California and not used elsewhere;
(4) In the case of California gasoline produced outside the State of California, the transferors and transferees must meet the product transfer document requirements under § 80.81(g); and
(5) Gasoline that is ultimately used in any part of the United States outside of the State of California must comply with the standards and requirements of this subpart, regardless of any designation as California gasoline.
(d)
(1) Use the sampling and testing methods approved in Title 13 of the California Code of Regulations instead of the sampling and testing methods required under § 80.330; and
(2) Determine the sulfur content of gasoline at off site tankage as permitted in § 80.81(h)(2).
Any person may request an exemption from the provisions of this subpart for gasoline used for research, development or testing (“R&D”) purposes by submitting to EPA an application that includes all the information listed in paragraph (b) of this section.
(a)
(1) Have a purpose that constitutes an appropriate basis for exemption;
(2) Necessitate the granting of an exemption;
(3) Be reasonable in scope; and
(4) Have a degree of control consistent with the purpose of the program and EPA's monitoring requirements.
(b)
(1) A statement of the purpose of the program demonstrating that the program has an appropriate R&D purpose.
(2) An explanation of why the stated purpose of the program cannot be achieved in a practicable manner without performing one or more of the prohibited acts under § 80.385.
(3) To demonstrate the reasonableness of the scope of the program:
(i) An estimate of the program's beginning and ending dates;
(ii) An estimate of the maximum number of vehicles and engines involved in the program, and the number of miles and engine hours that will be accumulated on each;
(iii) The sulfur content of the gasoline expected to be used in the program; and
(iv) The quantity of gasoline that exceeds the applicable sulfur standard that is expected to be used in the program.
(4) With regard to control, a demonstration that the program affords EPA a monitoring capability, including at a minimum:
(i) A description of the technical and operational aspects of the program;
(ii) The site(s) of the program (including street address, city, county, State, and ZIP code);
(iii) The manner in which information on vehicles and engines used in the program will be recorded and made available to EPA;
(iv) The manner in which results of the program will be recorded and made available to EPA;
(v) The manner in which information on the gasoline used in the program (including quantity, sulfur content, name, address, telephone number and contact person of the supplier, and the date received from the supplier), will be recorded and made available to EPA;
(vi) The manner in which distribution pumps will be labeled to insure proper use of the gasoline where appropriate;
(vii) The name, address, telephone number and title of the person(s) in the organization requesting an exemption from whom further information on the application may be obtained; and
(viii) The name, address, telephone number and title of the person(s) in the organization requesting an exemption who is responsible for recording and making available the information specified in paragraphs (b)(4)(iii), (iv) and (v) of this section, and the location in which such information will be maintained.
(c)
(2) The R&D gasoline must be designated by the refiner or importer as exempt R&D gasoline.
(3) The R&D gasoline must be kept segregated from non-exempt gasoline at all points in the distribution system of the gasoline.
(4) The R&D gasoline must not be sold, distributed, offered for sale or distribution, dispensed, supplied, offered for supply, transported to or from, or stored by a gasoline retail outlet, or by a wholesale purchaser-consumer facility, unless the wholesale purchaser-consumer facility is associated with the R&D program that uses the gasoline.
(d)
(e)
No person shall:
(a)
(b)
(c)
(d)
(e)
(f)
(a) Compliance with the sulfur standards of this subpart shall be determined based on the sulfur level of the gasoline, measured using the methodologies specified in §§ 80.330(b) and 80.46(a). Any evidence or information, including the exclusive use of such evidence or information, may be used to establish the sulfur level of gasoline if the evidence or information is relevant to whether the sulfur level of gasoline would have been in compliance with the standards if the appropriate sampling and testing methodology had been correctly performed. Such evidence may be obtained from any source or location and may include, but is not limited to, test results using methods other than those specified in §§ 80.330(b) and 80.46(a), business records, and commercial documents.
(b) Determinations of compliance with the requirements of this subpart other than the sulfur standards, and determinations of liability for any violation of this subpart, may be based on information obtained from any source or location. Such information may include, but is not limited to, business records and commercial documents.
(a)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(11)
(12)
(b)
(2) Any refiner, importer, distributor, reseller, carrier, wholesale purchaser-consumer, retailer, or oxygenate blender who caused another person to fail to meet a requirement of this subpart not addressed in paragraph (a) of this section, is liable for causing a violation of that provision.
(a) Any person deemed liable for a violation of a prohibition under § 80.395 (a)(3) through (8), will not be deemed in violation if the person demonstrates that:
(1) The violation was not caused by the person or the person's employee or agent; and
(2) The person conducted a quality assurance sampling and testing program, as described in paragraph (d) of this section. A carrier may rely on the quality assurance program carried out by another party, including the party who owns the gasoline in question, provided that the quality assurance program is carried out properly. Retailers and wholesale purchaser-consumers are not required to conduct quality assurance programs.
(b) In the case of a violation found at a facility operating under the corporate, trade or brand name of a refiner or importer, or a refiner's or importer's marketing subsidiary, the refiner or importer must show, in addition to the defense elements required under paragraphs (a)(1) and (2) of this section, that the violation was caused by:
(1) An act in violation of law (other than the Clean Air Act or this part 80), or an act of sabotage or vandalism;
(2) The action of any refiner, importer, retailer, distributor, reseller, oxygenate blender, carrier, retailer or wholesale purchaser-consumer in violation of a contractual agreement between the branded refiner or importer and the person designed to prevent such action, and despite periodic sampling and testing by the branded refiner or importer to ensure compliance with such contractual obligation; or
(3) The action of any carrier or other distributor not subject to a contract with the refiner or importer, but engaged for transportation of gasoline, despite specifications or inspections of procedures and equipment which are reasonably calculated to prevent such action.
(c) Under paragraph (a) of this section for any person to show that a violation was not caused by that person, or under paragraph (b) of this section to show that a violation was caused by any of the specified actions, the person must demonstrate by reasonably specific showing, by direct or circumstantial evidence, that the violation was caused or must have been caused by another person and that the person asserting the defense did not contribute to that other person's causation.
(d)
(1) A periodic sampling and testing program to ensure the gasoline the person sold, dispensed, supplied, stored, or transported, meets the applicable sulfur standard; and
(2) On each occasion when gasoline is found not in compliance with the applicable sulfur standard:
(i) The person immediately ceases selling, offering for sale, dispensing, supplying, offering for supply, storing or transporting the non-complying product; and
(ii) The person promptly remedies the violation and the factors that caused the violation (for example, by removing the non-complying product from the distribution system until the applicable standard is achieved and taking steps to prevent future violations of a similar nature from occurring).
(3) For any carrier who transports gasoline in a tank truck, the quality assurance program required under this paragraph (d) need not include periodic sampling and testing of gasoline in the tank truck, but in lieu of such tank truck sampling and testing, the carrier shall demonstrate evidence of an oversight program for monitoring compliance with the requirements of this subpart
(a) Any person liable for a violation under § 80.395 is subject to civil penalties as specified in section 205 of the Clean Air Act for every day of each such violation and the amount of economic benefit or savings resulting from each violation.
(b) Any person liable under § 80.395(a)(1) or (2) for a violation of the applicable sulfur averaging standard or causing another party to violate that standard during any averaging period, is subject to a separate day of violation for each and every day in the averaging period. Any person liable under § 80.395(b) for a failure to fulfill any requirement for credit or allotment generation, transfer, use, banking, or deficit correction, is subject to a separate day of violation for each and every day in the averaging period in which invalid credits or allotments are generated or used.
(c)(1) Any person liable under § 80.395(a)(3), (4), (5), or (6) for a violation of an applicable sulfur per gallon cap standard under § 80.195, § 80.210, § 80.216, § 80.220 or § 80.240, a GPA use prohibition under § 80.219(c), or of causing another party to violate a cap standard or a GPA use prohibition, is subject to a separate day of violation for each and every day the non-complying gasoline remains any place in the gasoline distribution system.
(2) Any person liable under § 80.395(a)(8) for causing gasoline to be in the distribution system which does not comply with an applicable sulfur cap standard, a sulfur averaging standard, or a GPA use prohibition, is subject to a separate day of violation for each and every day that the non-complying gasoline remains any place in the gasoline distribution system.
(3) For purposes of paragraph (c) of this section, the length of time the gasoline in question remained in the gasoline distribution system is deemed to be twenty-five days, unless a person subject to liability or EPA demonstrates by reasonably specific showings, by direct or circumstantial evidence, that the non-complying gasoline remained in the gasoline distribution system for fewer than or more than twenty-five days.
(d) Any person liable under § 80.395(b) for failure to meet, or causing a failure to meet, a provision of this subpart is liable for a separate day of violation for each and every day such provision remains unfulfilled.
(a)
(2) A foreign refiner is a person who meets the definition of refiner under § 80.2(i) for a foreign refinery.
(3) A small foreign refiner is a refiner that meets the definition of a small refiner under § 80.225.
(4) “Sulfur-FRGAS” means gasoline produced at a foreign refinery that has been assigned an individual refinery sulfur baseline under §§ 80.250 or 80.295, or has been granted temporary relief under § 80.270, and that is imported into the United States.
(5) “Non-Sulfur-FRGAS” means gasoline that is produced at a foreign refinery that has not been assigned an individual refinery sulfur baseline, gasoline produced at a foreign refinery with an individual refinery sulfur baseline that is not imported into the United States, and gasoline produced at a foreign refinery with an individual sulfur baseline during a year when the foreign refiner has opted to not participate in the Sulfur-FRGAS program under paragraph (c)(3) of this section.
(6) “Certified Sulfur-FRGAS” means Sulfur-FRGAS the foreign refiner intends to include in the foreign refinery's sulfur compliance calculations under § 80.205 pursuant to § 80.240 or § 80.270 or credit calculations under §§ 80.305 or 80.310 and allotment calculations under § 80.275(a), and does include in these compliance calculations when reported to EPA.
(7) “Non-Certified Sulfur-FRGAS” means Sulfur-FRGAS that is not Certified Sulfur-FRGAS.
(b)
(1) The refiner shall follow the procedures specified in §§ 80.91 through 80.93 to establish the volume and sulfur content of gasoline that was produced at the foreign refinery and imported into the United States during 1997 and 1998 for purposes of establishing baselines under § 80.250 or § 80.295.
(2) In making determinations for foreign refinery baselines EPA will consider all information supplied by a foreign refiner, and in addition may rely on any and all appropriate assumptions necessary to make such determinations.
(3) Where a foreign refiner submits a petition that is incomplete or inadequate to establish an accurate baseline, and the refiner fails to cure this defect after a request for more information, EPA will not assign an individual refinery sulfur baseline.
(c)
(1) In the case of Certified Sulfur-FRGAS, the foreign refiner must meet all provisions that apply to refiners under this subpart H.
(2) In the case of Non-Certified Sulfur-FRGAS, the foreign refiner shall meet all the following provisions, except the foreign refiner shall substitute the name Non-Certified Sulfur-FRGAS for the names “reformulated gasoline” or “RBOB” wherever they appear in the following provisions:
(i) The designation requirements in this section;
(ii) The recordkeeping requirements under § 80.365;
(iii) The reporting requirements in § 80.370 and this section;
(iv) The product transfer document requirements in this section;
(v) The prohibitions in this section and § 80.385; and
(vi) The independent audit requirements under § 80.415, paragraph (h) of this section, §§ 80.125 through
(3)(i) Any foreign refiner that generates sulfur credits under § 80.305 during the period 2000 through 2003, or allotments under § 80.275(a) during 2003, and any small refiner generating credits under § 80.310, shall designate all Sulfur-FRGAS as Certified Sulfur-FRGAS for any year that such credits are generated.
(ii) Any foreign refiner that has been assigned an individual sulfur baseline for a foreign refinery under § 80.250 or § 80.295 may elect to classify no gasoline imported into the United States as Sulfur-FRGAS, provided the foreign refiner notifies EPA of the election no later than November 1 of the prior calendar year.
(iii) An election under paragraph (c)(3)(ii) of this section shall:
(A) Apply to an entire calendar year averaging period, and apply to all gasoline produced during the calendar year at the foreign refinery that is used in the United States; and
(B) Remain in effect for each succeeding calendar year averaging period, unless and until the foreign refiner notifies EPA of a termination of the election. The change in election shall take effect at the beginning of the next calendar year.
(d)
(2) On each occasion when any person transfers custody or title to any Sulfur-FRGAS prior to its being imported into the United States, it must include the following information as part of the product transfer document information in this section:
(i) Identification of the gasoline as Certified Sulfur-FRGAS or as Non-Certified Sulfur-FRGAS; and
(ii) The name and EPA refinery registration number of the refinery where the Sulfur-FRGAS was produced.
(3) On each occasion when Sulfur-FRGAS is loaded onto a vessel or other transportation mode for transport to the United States, the foreign refiner shall prepare a certification for each batch of the Sulfur-FRGAS that meets the following requirements:
(i) The certification shall include the report of the independent third party under paragraph (f) of this section, and the following additional information:
(A) The name and EPA registration number of the refinery that produced the Sulfur-FRGAS;
(B) The identification of the gasoline as Certified Sulfur-FRGAS or Non-Certified Sulfur-FRGAS;
(C) The volume of Sulfur-FRGAS being transported, in gallons;
(D) In the case of Certified Sulfur-FRGAS:
(
(
(ii) The certification shall be made part of the product transfer documents for the Sulfur-FRGAS.
(e)
(1)(i) The foreign refiner excludes:
(A) The volume of gasoline from the refinery's compliance calculations under § 80.205; and
(B) In the case of Certified Sulfur-FRGAS, the volume and sulfur content of the gasoline from the compliance calculations under § 80.205 or credit calculations under § 80.305.
(ii) The exclusions under paragraph (e)(1)(i) of this section shall be on the basis of the sulfur content and volumes determined under paragraph (f) of this section; and
(2) The foreign refiner obtains sufficient evidence in the form of documentation that the gasoline was not imported into the United States.
(f)
(i) Inspect the vessel prior to loading and determine the volume of any tank bottoms;
(ii) Determine the volume of Sulfur-FRGAS loaded onto the vessel (exclusive of any tank bottoms present before vessel loading);
(iii) Obtain the EPA-assigned registration number of the foreign refinery;
(iv) Determine the name and country of registration of the vessel used to transport the Sulfur-FRGAS to the United States; and
(v) Determine the date and time the vessel departs the port serving the foreign refinery.
(2) On each occasion Certified Sulfur-FRGAS is loaded onto a vessel for transport to the United States a foreign refiner shall have an independent third party:
(i) Collect a representative sample of the Certified Sulfur-FRGAS from each vessel compartment subsequent to loading on the vessel and prior to departure of the vessel from the port serving the foreign refinery;
(ii) Prepare a volume-weighted vessel composite sample from the compartment samples, and determine the value for sulfur using the methodology specified in § 80.330 by:
(A) The third party analyzing the sample; or
(B) The third party observing the foreign refiner analyze the sample;
(iii) Review original documents that reflect movement and storage of the certified Sulfur-FRGAS from the refinery to the load port, and from this review determine:
(A) The refinery at which the Sulfur-FRGAS was produced; and
(B) That the Sulfur-FRGAS remained segregated from:
(
(
(3) The independent third party shall submit a report:
(i) To the foreign refiner containing the information required under paragraphs (f)(1) and (2) of this section, to accompany the product transfer documents for the vessel; and
(ii) To the Administrator containing the information required under paragraphs (f)(1) and (2) of this section, within thirty days following the date of the independent third party's inspection. This report shall include a description of the method used to determine the identity of the refinery at which the gasoline was produced, assurance that the gasoline remained segregated as specified in paragraph (n)(1) of this section, and a description of the gasoline's movement and storage between production at the source refinery and vessel loading.
(4) The independent third party must:
(i) Be approved in advance by EPA, based on a demonstration of ability to perform the procedures required in this paragraph (f);
(ii) Be independent under the criteria specified in § 80.65(e)(2)(iii); and
(iii) Sign a commitment that contains the provisions specified in paragraph (i) of this section with regard to activities, facilities and documents relevant to
(g)
(ii) Where a vessel transporting Certified Sulfur-FRGAS off loads this gasoline at more than one United States port of entry, and the conditions of paragraph (g)(2)(i) of this section are met at the first United States port of entry, the requirements of paragraph (g)(2) of this section do not apply at subsequent ports of entry if the United States importer obtains a certification from the vessel owner, that meets the requirements of paragraph (s) of this section, that the vessel has not loaded any gasoline or blendstock between the first United States port of entry and the subsequent port of entry.
(2)(i) The requirements of this paragraph (g)(2) apply if:
(A) The temperature-corrected volumes determined at the port of entry and at the load port differ by more than one percent; or
(B) The sulfur value determined at the port of entry is higher than the sulfur value determined at the load port, and the amount of this difference is greater than the reproducibility amount specified for the port of entry test result by the American Society of Testing and Materials (ASTM).
(ii) The United States importer and the foreign refiner shall treat the gasoline as Non-Certified Sulfur-FRGAS, and the foreign refiner shall exclude the gasoline volume and properties from its gasoline sulfur compliance calculations under § 80.205.
(h)
(1) The inventory reconciliation analysis under § 80.128(b) and the tender analysis under § 80.128(c) shall include Non-Sulfur-FRGAS in addition to the gasoline types listed in § 80.128(b) and (c).
(2) Obtain separate listings of all tenders of Certified Sulfur-FRGAS, and of Non-Certified Sulfur-FRGAS. Agree the total volume of tenders from the listings to the gasoline inventory reconciliation analysis in § 80.128(b), and to the volumes determined by the third party under paragraph (f)(1) of this section.
(3) For each tender under paragraph (h)(2) of this section where the gasoline is loaded onto a marine vessel, report as a finding the name and country of registration of each vessel, and the volumes of Sulfur-FRGAS loaded onto each vessel.
(4) Select a sample from the list of vessels identified in paragraph (h)(3) of this section used to transport Certified Sulfur-FRGAS, in accordance with the guidelines in § 80.127, and for each vessel selected perform the following:
(i) Obtain the report of the independent third party, under paragraph (f) of this section, and of the United States importer under paragraph (o) of this section.
(A) Agree the information in these reports with regard to vessel identification, gasoline volumes and test results.
(B) Identify, and report as a finding, each occasion the load port and port of entry parameter and volume results differ by more than the amounts allowed in paragraph (g) of this section, and determine whether the foreign refiner adjusted its refinery calculations as required in paragraph (g) of this section.
(ii) Obtain the documents used by the independent third party to determine transportation and storage of the Certified Sulfur-FRGAS from the refinery to the load port, under paragraph (f) of this section. Obtain tank activity records for any storage tank where the Certified Sulfur-FRGAS is stored, and pipeline activity records for any pipeline used to transport the Certified Sulfur-FRGAS, prior to being loaded onto the vessel. Use these records to determine whether the Certified Sulfur-FRGAS was produced at the refinery that is the subject of the attest engagement, and whether the Certified Sulfur-FRGAS was mixed with any Non-Certified Sulfur-FRGAS, Non-Sulfur-FRGAS, or any Certified Sulfur-FRGAS produced at a different refinery.
(5)(i) Select a sample from the list of vessels identified in paragraph (h)(3) of this section used to transport certified and Non-Certified Sulfur-FRGAS, in accordance with the guidelines in § 80.127, and for each vessel selected perform the following:
(ii) Obtain a commercial document of general circulation that lists vessel arrivals and departures, and that includes the port and date of departure of the vessel, and the port of entry and date of arrival of the vessel. Agree the vessel's departure and arrival locations and dates from the independent third party and United States importer reports to the information contained in the commercial document.
(6) Obtain separate listings of all tenders of Non-Sulfur-FRGAS, and perform the following:
(i) Agree the total volume of tenders from the listings to the gasoline inventory reconciliation analysis in § 80.128(b).
(ii) Obtain a separate listing of the tenders under paragraph (h)(6) of this section where the gasoline is loaded onto a marine vessel. Select a sample from this listing in accordance with the guidelines in § 80.127, and obtain a commercial document of general circulation that lists vessel arrivals and departures, and that includes the port and date of departure and the ports and dates where the gasoline was off loaded for the selected vessels. Determine and report as a finding the country where the gasoline was off loaded for each vessel selected.
(7) In order to complete the requirements of this paragraph (h) an auditor shall:
(i) Be independent of the foreign refiner;
(ii) Be licensed as a Certified Public Accountant in the United States and a citizen of the United States, or be approved in advance by EPA based on a demonstration of ability to perform the procedures required in §§ 80.125 through 80.130 and this paragraph (h); and
(iii) Sign a commitment that contains the provisions specified in paragraph (i) of this section with regard to activities and documents relevant to compliance with the requirements of §§ 80.125 through 80.130, § 80.415 and this paragraph (h).
(i)
(1) Any United States Environmental Protection Agency inspector or auditor will be given full, complete and immediate access to conduct inspections and audits of the foreign refinery.
(i) Inspections and audits may be either announced in advance by EPA, or unannounced.
(ii) Access will be provided to any location where:
(A) Gasoline is produced;
(B) Documents related to refinery operations are kept;
(C) Gasoline or blendstock samples are tested or stored; and
(D) Sulfur-FRGAS is stored or transported between the foreign refinery
(iii) Inspections and audits may be by EPA employees or contractors to EPA.
(iv) Any documents requested that are related to matters covered by inspections and audits will be provided to an EPA inspector or auditor on request.
(v) Inspections and audits by EPA may include review and copying of any documents related to:
(A) Refinery baseline establishment, including the volume and sulfur content, and transfers of title or custody, of any gasoline or blendstocks, whether Sulfur-FRGAS or Non-Sulfur-FRGAS, produced at the foreign refinery during the period January 1, 1997 through the date of the refinery baseline petition or through the date of the inspection or audit if a baseline petition has not been approved, and any work papers related to refinery baseline establishment;
(B) The volume and sulfur content of Sulfur-FRGAS;
(C) The proper classification of gasoline as being Sulfur-FRGAS or as not being Sulfur-FRGAS, or as Certified Sulfur-FRGAS or as Non-Certified Sulfur-FRGAS;
(D) Transfers of title or custody to Sulfur-FRGAS;
(E) Sampling and testing of Sulfur-FRGAS;
(F) Work performed and reports prepared by independent third parties and by independent auditors under the requirements of this section and § 80.415 including work papers; and
(G) Reports prepared for submission to EPA, and any work papers related to such reports.
(vi) Inspections and audits by EPA may include taking samples of gasoline or blendstock, and interviewing employees.
(vii) Any employee of the foreign refiner will be made available for interview by the EPA inspector or auditor, on request, within a reasonable time period.
(viii) English language translations of any documents will be provided to an EPA inspector or auditor, on request, within 10 working days.
(ix) English language interpreters will be provided to accompany EPA inspectors and auditors, on request.
(2) An agent for service of process located in the District of Columbia will be named, and service on this agent constitutes service on the foreign refiner or any employee of the foreign refiner for any action by EPA or otherwise by the United States related to the requirements of this subpart H.
(3) The forum for any civil or criminal enforcement action related to the provisions of this section for violations of the Clean Air Act or regulations promulgated thereunder shall be governed by the Clean Air Act, including the EPA administrative forum where allowed under the Clean Air Act.
(4) United States substantive and procedural laws shall apply to any civil or criminal enforcement action against the foreign refiner or any employee of the foreign refiner related to the provisions of this section.
(5) Submitting a petition for an individual refinery sulfur baseline, producing and exporting gasoline under an individual refinery sulfur baseline, and all other actions to comply with the requirements of this subpart H relating to the establishment and use of an individual refinery sulfur baseline constitute actions or activities that satisfy the provisions of 28 U.S.C. section 1605(a)(2), but solely with respect to actions instituted against the foreign refiner, its agents and employees in any court or other tribunal in the United States for conduct that violates the requirements applicable to the foreign refiner under this subpart H, including conduct that violates Title 18 U.S.C. section 1001 and Clean Air Act section 113(c)(2).
(6) The foreign refiner, or its agents or employees, will not seek to detain or to impose civil or criminal remedies against EPA inspectors or auditors, whether EPA employees or EPA contractors, for actions performed within the scope of EPA employment related to the provisions of this section.
(7) The commitment required by this paragraph (i) shall be signed by the owner or president of the foreign refiner business.
(8) In any case where Sulfur-FRGAS produced at a foreign refinery is stored or transported by another company between the refinery and the vessel that transports the Sulfur-FRGAS to the United States, the foreign refiner shall obtain from each such other company a commitment that meets the requirements specified in paragraphs (i)(1) through (7) of this section, and these commitments shall be included in the foreign refiner's baseline petition.
(j)
(k)
(l) The foreign refiner shall post a bond of the amount calculated using the following equation:
(2) Bonds shall be posted by:
(i) Paying the amount of the bond to the Treasurer of the United States;
(ii) Obtaining a bond in the proper amount from a third party surety agent that is payable to satisfy United States administrative or judicial judgments against the foreign refiner, provided EPA agrees in advance as to the third party and the nature of the surety agreement; or
(iii) An alternative commitment that results in assets of an appropriate liquidity and value being readily available to the United States, provided EPA agrees in advance as to the alternative commitment.
(3) If the bond amount for a foreign refinery increases, the foreign refiner shall increase the bond to cover the shortfall within 90 days of the date the bond amount changes. If the bond amount decreases, the foreign refiner may reduce the amount of the bond beginning 90 days after the date the bond amount changes.
(4) Bonds posted under this paragraph (k) shall:
(i) Be used to satisfy any judicial judgment that results from an administrative or judicial enforcement action for conduct in violation of this subpart H, including where such conduct violates Title 18 U.S.C. section
(ii) Be provided by a corporate surety that is listed in the United States Department of Treasury Circular 570 “Companies Holding Certificates of Authority as Acceptable Sureties on Federal Bonds and Acceptable Reinsuring Companies” (Available from the U.S. Department of the Treasury, Financial Management Service, Surety Bond Branch, 3700 East-West Highway, Room 6A04, Hyattsville, Md. 20782. Also available on the internet at http://www.fms.treas.gov/c570/c570.html); and
(iii) Include a commitment that the bond will remain in effect for at least five (5) years following the end of latest averaging period that the foreign refiner produces gasoline pursuant to the requirements of this Subpart H.
(5) On any occasion a foreign refiner bond is used to satisfy any judgment, the foreign refiner shall increase the bond to cover the amount used within 90 days of the date the bond is used.
(l) [Reserved]
(m)
(n)
(2) No foreign refiner or other person may cause another person to commit an action prohibited in paragraph (n)(1) of this section, or that otherwise violates the requirements of this section.
(o)
(1) Each batch of imported gasoline shall be classified by the importer as being Sulfur-FRGAS or as Non-Sulfur-FRGAS, and each batch classified as Sulfur-FRGAS shall be further classified as Certified Sulfur-FRGAS or as Non-certified Sulfur-FRGAS.
(2) Gasoline shall be classified as Certified Sulfur-FRGAS or as Non-Certified Sulfur-FRGAS according to the designation by the foreign refiner if this designation is supported by product transfer documents prepared by the foreign refiner as required in paragraph (d) of this section, unless the gasoline is classified as Non-Certified Sulfur-FRGAS under paragraph (g) of this section.
(3) For each gasoline batch classified as Sulfur-FRGAS, any United States importer shall perform the following procedures:
(i) In the case of both Certified and Non-Certified Sulfur-FRGAS, have an independent third party:
(A) Determine the volume of gasoline in the vessel;
(B) Use the foreign refiner's Sulfur-FRGAS certification to determine the name and EPA-assigned registration number of the foreign refinery that produced the Sulfur-FRGAS;
(C) Determine the name and country of registration of the vessel used to transport the Sulfur-FRGAS to the United States; and
(D) Determine the date and time the vessel arrives at the United States port of entry.
(ii) In the case of Certified Sulfur-FRGAS, have an independent third party:
(A) Collect a representative sample from each vessel compartment subsequent to the vessel's arrival at the United States port of entry and prior to off loading any gasoline from the vessel;
(B) Prepare a volume-weighted vessel composite sample from the compartment samples; and
(C) Determine the sulfur value using the methodologies specified in § 80.330, by:
(
(
(4) Any importer shall submit reports within thirty days following the date any vessel transporting Sulfur-FRGAS arrives at the United States port of entry:
(i) To the Administrator containing the information determined under paragraph (o)(3) of this section; and
(ii) To the foreign refiner containing the information determined under paragraph (o)(3)(ii) of this section.
(5)(i) Any United States importer shall meet the requirements specified in § 80.195 for any imported gasoline that is not classified as Certified Sulfur-FRGAS under paragraph (o)(2) of this section.
(p)
(i) Certification under paragraph (d)(5) of this section;
(ii) Load port and port of entry sampling and testing under paragraphs (f) and (g) of this section;
(iii) Attest under paragraph (h) of this section; and
(iv) Importer testing under paragraph (o)(3) of this section.
(2) These alternative procedures must ensure Certified Sulfur-FRGAS remains segregated from Non-Certified Sulfur-FRGAS and from Non-Sulfur-FRGAS until it is imported into the United States. The petition will be evaluated based on whether it adequately addresses the following:
(i) Provisions for monitoring pipeline shipments, if applicable, from the refinery, that ensure segregation of Certified Sulfur-FRGAS from that refinery from all other gasoline;
(ii) Contracts with any terminals and/or pipelines that receive and/or transport Certified Sulfur-FRGAS, that prohibit the commingling of Certified Sulfur-FRGAS with any of the following:
(A) Other Certified Sulfur-FRGAS from other refineries;
(B) All Non-Certified Sulfur-FRGAS; or
(C) All Non-Sulfur-FRGAS;
(iii) Procedures for obtaining and reviewing truck loading records and United States import documents for Certified Sulfur-FRGAS to ensure that such gasoline is only loaded into trucks making deliveries to the United States; and
(iv) Attest procedures to be conducted annually by an independent third party that review loading records and import documents based on volume reconciliation, or other criteria, to confirm that all Certified Sulfur-FRGAS remains segregated throughout the distribution system and is only loaded into trucks for import into the United States.
(3) The petition required by this section must be submitted to EPA along with the application for small refiner status and individual refinery sulfur baseline and standards under § 80.240 and this section.
(q)
(1) A foreign refiner fails to meet any requirement of this section;
(2) A foreign government fails to allow EPA inspections as provided in paragraph (i)(1) of this section;
(3) A foreign refiner asserts a claim of, or a right to claim, sovereign immunity in an action to enforce the requirements in this subpart H; or
(4) A foreign refiner fails to pay a civil or criminal penalty that is not satisfied using the foreign refiner bond specified in paragraph (k) of this section.
(r)
(i) A baseline petition has been submitted as required in paragraph (b) of this section;
(ii) EPA has made a provisional finding that the baseline petition is complete;
(iii) The foreign refiner has made the commitments required in paragraph (i) of this section;
(iv) The persons who will meet the independent third party and independent attest requirements for the foreign refinery have made the commitments required in paragraphs (f)(3)(iii) and (h)(7)(iii) of this section; and
(v) The foreign refiner has met the bond requirements of paragraph (k) of this section.
(2) In any case where a foreign refiner uses an individual refinery baseline before final approval under paragraph (r)(1) of this section, and the foreign refinery baseline values that ultimately are approved by EPA are more stringent than the early baseline values used by the foreign refiner, the foreign refiner shall recalculate its compliance, ab initio, using the baseline values approved by EPA, and the foreign refiner shall be liable for any resulting violation of the conventional gasoline requirements.
(s)
(1) Submitted in accordance with procedures specified by the Administrator, including use of any forms that may be specified by the Administrator; and
(2) Be signed by the president or owner of the foreign refiner company, or by that person's immediate designee, and shall contain the following declaration:
I hereby certify: (1) that I have actual authority to sign on behalf of and to bind [insert name of foreign refiner] with regard to all statements contained herein; (2) that I am aware that the information contained herein is being certified, or submitted to the United States Environmental Protection Agency, under the requirements of 40 CFR. Part 80, subpart H, and that the information is material for determining compliance under these regulations; and (3) that I have read and understand the information being certified or submitted, and this information is true, complete and correct to the best of my knowledge and belief after I have taken reasonable and appropriate steps to verify the accuracy thereof.
I affirm that I have read and understand the provisions of 40 CFR Part 80, subpart H, including 40 CFR 80.410 [insert name of foreign refiner]. Pursuant to Clean Air Act section 113(c) and Title 18, United States Code, section 1001, the penalty for furnishing false, incomplete or misleading information in this certification or submission is a fine of up to $10,000, and/or imprisonment for up to five years.
In addition to the requirements for attest engagements that apply to refiners and importers under §§ 80.125 through 80.130, and § 80.410, the attest engagements for importers and refiners must include the following procedures and requirements each year.
(a)
(2) If the year being reviewed is 2004 through 2006 (2007 for refineries with small refiner status) and the refinery or importer produced or imported any GPA gasoline under § 80.216 or the refiner has approved status for a small refinery:
(i) Obtain the refinery's annual sulfur reports for 2000 through 2003; and
(ii) Determine whether the annual average sulfur level for any year credits were generated for 2000 through 2003 was less than the baseline level under paragraph (a)(1) of this section.
(3) If the annual average sulfur content for any year credits were created for 2000 through 2003 was less than the baseline level under paragraph (a)(1) of this section, report as a finding the lowest annual sulfur level as the new baseline value. For GPA gasoline add 30 ppm to obtain the GPA standard, not to exceed 150 ppm.
(4) If the refinery being reviewed is a small refinery and the annual volume under paragraph (b)(2) of this section is greater than the baseline volume, calculate the applicable standard in accordance with § 80.240(c).
(5) Obtain a written representation from the company representative stating the sulfur value that the company used as its baseline and agree that number to paragraphs (a)(1) through (a)(4) of this section and to the reports to EPA.
(b)
(2) Agree the yearly volume of gasoline reported to EPA in the sulfur reports with the inventory reconciliation analysis under § 80.128.
(3) For the years 2004 through 2006, calculate the annual volume and average sulfur level for gasoline classified as GPA gasoline under §§ 80.216 and 80.219, and calculate the annual volume and average sulfur level for gasoline not classified as GPA gasoline, and agree these values with the values reported to EPA.
(4) Except as provided in paragraph (b)(3) of this section, calculate the annual average sulfur level for all gasoline and agree that value with the value reported to EPA.
(5) Obtain and read a copy of the refinery's or importer's sulfur credit report.
(c)
(1) Obtain a written representation from the company representative stating the refinery produces gasoline from crude oil.
(2) Compute and report as a finding the sulfur baseline from paragraph (a) of this section multiplied by 0.9.
(3) Obtain the annual average sulfur level from paragraph (b)(4) of this section.
(4) If the sulfur value under paragraph (c)(3) of this section is less than the sulfur value under paragraph (c)(2) of this section, compute and report as a finding the difference between the annual average sulfur level and the refinery's sulfur baseline from paragraph (a) of this section.
(5) Compute and report as a finding the total number of sulfur credits generated by multiplying the value in paragraph (c)(4) of this section by the volume of gasoline in paragraph (b)(2) of this section, and agree this value with the value reported to EPA.
(d)
(1) Obtain the annual average sulfur level for gasoline not classified as GPA from paragraph (b)(3) of this section.
(2) If the sulfur value under paragraph (d)(1) of this section is less than 30 ppm, compute and report as a finding the difference between the sulfur level under paragraph (d)(1) of this section and 30 ppm.
(3) Compute and report as a finding the total number of sulfur credits generated by multiplying the value calculated in paragraph (d)(2) of this
(4) Obtain the annual average sulfur level for gasoline classified as GPA from paragraph (b)(3) of this section.
(5) If the sulfur value under paragraph (d)(4) of this section is less than the applicable level under § 80.310, compute and report as a finding the difference between the sulfur level under paragraph (d)(4) of this section and the appropriate level in § 80.310 .
(6) Compute and report as a finding the total number of sulfur credits generated by multiplying the value calculated in paragraph (d)(5) of this section by the volume of gasoline classified as GPA in paragraph (b)(3) of this section, and agree this number with the number reported to EPA.
(7) If the refiner has an approved status as a small refinery, obtain the annual average sulfur level for gasoline from paragraph (b)(4) of this section.
(8) If the sulfur value under paragraph (d)(7) of this section is less than the applicable standard under § 80.240, compute and report as a finding the difference between the sulfur level under paragraph (d)(7) of this section and the appropriate standard under § 80.240.
(9) Compute and report as a finding the total number of sulfur credits generated by multiplying the value calculated in paragraph (d)(8) of this section by the volume of gasoline in paragraph (b)(4) of this section, and agree this number with the number reported to EPA.
(e)
(1) Obtain contracts or other documents for all credits transferred to another refinery or importer during the year being reviewed; compute and report as a finding the number and year of creation of credits represented in these documents as being transferred away; and agree with the report to EPA.
(2) Obtain contracts or other documents for all credits received during the year being reviewed; compute and report as a finding the number and year of creation of credits represented in these documents as being received; and agree with the report to EPA.
(f)
(1) Obtain the annual average sulfur level for gasoline not classified as GPA from paragraph (b)(3) of this section.
(2) If the value in paragraph (f)(1) of this section is greater than 30 ppm (or greater than the small refinery standard), compute and report as a finding the difference between 30 ppm (or the standard under § 80.240) and the value in paragraph (f)(1) of this section.
(3) Compute and report as a finding the total sulfur credits required by multiplying the value in paragraph (f)(2) of this section times the volume of gasoline not classified as GPA in paragraph (b)(3) of this section, and agree with the report to EPA.
(4) Obtain the refiner's or importer's representation as to the portion of the deficit under paragraph (f)(3) of this section that was resolved with credits, the portion that was resolved with allotments in 2005 only or that was carried forward as a deficit under § 80.205, and agree with the report to EPA (refineries subject to standards under § 80.240 cannot carry deficits forward).
(g)
(1) Obtain the annual average sulfur level for the refinery's or importer's GPA gasoline from paragraph (b)(3) of this section.
(2) If the value in paragraph (g)(1) of this section is greater than the refinery's or importer's baseline plus 30 ppm under § 80.216, as determined in paragraph (a) of this section or 150 ppm, whichever is less, compute and report as a finding the difference between the annual average sulfur level and the baseline level plus 30 ppm, or 150 ppm, whichever is less.
(3) Compute and report as a finding the total sulfur credits and/or allotments required by multiplying the value in paragraph (g)(2) of this section times the volume of GPA gasoline from paragraph (b)(3) of this section.
(4) Obtain the refiner's or importer's representation as to the portion of the deficit under paragraph (g)(3) of this section that was resolved with credits, or the portion that was resolved with allotments in 2004 or 2005 only (compliance deficits for GPA gasoline cannot be carried forward.
(h)
(1) Obtain a list of all credits in the refiner's or importer's possession at any time during the year being reviewed, identified by the year of creation of the credits.
(2) If the year being reviewed is 2006 and thereafter, except in the case of gasoline produced for use in the GPA and gasoline produced by small refiners, determine whether any credits identified in paragraph (h)(1) of this section or Type A sulfur allotments created under paragraph (i) of this section and converted to credits were created before 2004, and if so, report as a finding this number of expired credits.
(3) If the year being reviewed is 2008 and thereafter, determine whether any credits identified in paragraph (h)(1) of this section or Type B sulfur allotments created under paragraph (i) of this section and converted to credits were created more than 5 years before the year being reviewed, and if so, report as a finding this number of expired credits (for example, unused credits created during the 2004 averaging period expire at the end of the 2009 averaging period).
(i)
(1) Obtain a written representation from the company representative stating the refinery produces gasoline from crude oil.
(2) Obtain the refinery baseline value from paragraph (b)(1) of this section, the annual volume from paragraph (b)(2) of this section and the annual average sulfur level from paragraph (b)(4) of this section.
(3) Based on the annual sulfur level and refinery baseline, determine which equation under § 80.275(a)(2) applies.
(4) Using the applicable equations under § 80.275(a)(2), recalculate the sulfur allotments, by type, and credits and report as a finding.
(j)
(1) Obtain the credits remaining or the credit deficit from the previous year from the refiner's or importer's report to EPA for the previous year.
(2) Compute and report as a finding the net credits remaining at the conclusion of the year being reviewed by totaling:
(i) Credits remaining from the previous year; plus
(ii) Credits generated under paragraphs (c), (d) and (i) of this section; plus
(iii) Allotments generated under paragraph (i) of this section which are converted to credits; plus
(iv) Credits purchased under paragraph (e) of this section; minus
(v) Credits sold under paragraph (e) of this section; minus
(vi) Credits used under paragraphs (f) and (g) of this section; minus
(vii) Credits expiring under paragraph (h) of this section; minus
(viii) Credit deficit from the previous year.
(3) Agree the credits remaining or the credit deficit at the conclusion of the year being reviewed with the report to EPA.
(4) If the refinery or importer had a credit deficit for both the previous year and the year being reviewed, report this fact as a finding.
(k)
(1)
(ii) Compute and report as a finding the company's gasoline volume subject to corporate pool standards and average sulfur level for gasoline subject to corporate pool standards, and agree with the values reported to EPA.
(2)
(ii) For 2005, if the corporate pool average is less than 90 ppm, compute and report as a finding the number and type of sulfur allotments generated in accordance with the applicable provisions under § 80.275(b).
(iii) If the refiner or importer produced and imported 50% or more of its gasoline for GPA use in 2004 or 2005, no allotments can be generated in that year.
(3)
(ii) Obtain contracts or other documents for all allotments received during the year being reviewed; compute and report as a finding the number of allotments represented in these documents as being received; and agree with the report to EPA.
(4)
(ii) For 2005, if the corporate pool average is greater than 90 ppm, compute and report as a finding the number of allotments required by multiplying the amount the corporate pool average is above 90 ppm times the corporate pool volume, and agree with the report to EPA.
(iii) Obtain the number of allotments used to meet standards for GPA gasoline determined in paragraph (g) of this section.
(5)
(A) Generated under paragraphs (i)(4) and (k)(2) of this section; plus
(B) Purchased under paragraph (k)(3) of this section; minus
(C) Sold under paragraph (k)(3) of this section; minus
(D) Used under paragraph (k)(4) of this section for demonstrating compliance with the corporate pool average.
(ii) Report as a finding any allotments generated in 2003 or 2004 that are used to meet the corporate pool standards in 2005 that were not reduced to 50% of their original value.
(iii) If the company's net allotments remaining are less than zero, report this fact as a finding.
42 U.S.C. 7521, 7522, 7524, 7525, 7541, 7542, 7601(a).
a. redesignating the existing paragraph (c) as paragraph (c)(1),
b. adding new paragraphs (c)(2), (c)(3), (c)(5), (c)(6) and (c)(7), and adding and reserving paragraph (c)(4), and
c. revising paragraph (d).
The revisions and additions read as follows:
(c)(1) * * *
(2)(i) The provisions of paragraph (c)(1) of this section notwithstanding, nonconforming light-duty vehicles and light light-duty trucks (LDV/LLDTs) modified in model years 2004, 2005 or 2006 must meet the FTP exhaust emission standards of bin 9 in Tables S04-1 and S04-2 in 40 CFR 86.1811-04 and the evaporative emission standards for light-duty vehicles and light light-duty trucks specified in 40 CFR 86.1811-04(e)(5).
(ii) Nonconforming LDT3s and LDT4s (HLDTs) and medium-duty passenger vehicles (MDPVs) modified in model years 2004 through 2006 must meet the FTP exhaust emission standards of bin 10 in Tables S04-1 and S04-2 in 40 CFR 86.1811-04 and the applicable evaporative standards specified in 40 CFR 86.1811-04(e)(5). For 2004 model year HLDTs and MDPVs where modifications commence on the first vehicle of a test group before December 21, 2003, this requirement does not apply to the 2004 model year. ICIs opting to bring all of their 2004 model year HLDTs and MDPVs into compliance with the exhaust emission standards of bin 10 in Tables S04-1 and S04-2 in 40 CFR 86.1811-04, may use the optional higher NMOG values for their 2004-2006 model year LDT2s and 2004-2008 LDT4s.
(iii) Nonconforming LDT3s and LDT4s (HLDTs) and medium-duty passenger vehicles (MDPVs) modified in model years 2007 and 2008 must meet the FTP exhaust emission standards of bin 8 in Tables S04-1 and S04-2 in 40 CFR 86.1811-04 and the applicable evaporative standards specified in 40 CFR 86.1811-04(e)(5).
(iv) Nonconforming LDV/LLDTs modified in model years 2007 and later and nonconfoming HLDTs and MDPVs modified in model years 2009 and later must meet the FTP exhaust emission standards of bin 5 in Tables S04-1 and S04-2 of 40 CFR 86.1811-04, and the evaporative standards specified in 40 CFR 86.1811(e)(1) through (e)(4).
(v) ICIs are exempt from the Tier 2 and the interim non-Tier 2 phase-in intermediate percentage requirements for exhaust, evaporative and refueling emissions described in 40 CFR 86.1811-04.
(3)(i) As an option to the requirements of paragraph (c)(2) of this section, independent commercial importers may elect to meet lower bins in Tables S04-1 and S04-2 of 40 CFR 86.1811-04 than
(ii) Where an ICI desires to obtain a certificate of conformity using a bin higher than specified in paragraph (c)(2) of this section, but does not have sufficient credits to cover vehicles produced under such certificate, the Administrator may issue such certificate if the ICI has also obtained a certificate of conformity for vehicles certified using a bin lower than that required under paragraph (c)(2) of this section. The ICI may then produce vehicles to the higher bin only to the extent that it has generated sufficient credits from vehicles certified to the lower bin during the same model year.
(4) [Reserved]
(5) Except for the situation where an ICI desires to bank, sell or use NO
(6) ICIs using bins higher than those specified in paragraph (c)(2) of this section must monitor their production so that they do not produce more vehicles certified to the standards of such bins than their available credits can cover. ICIs must not have a credit deficit at the end of a model year and are not permitted to use the deficit carryforward provisions provided in 40 CFR 86.1860-04(e).
(7) The Administrator may condition the certificates of conformity issued to ICIs as necessary to ensure that vehicles subject to paragraph (c) of this section comply with the appropriate average NO
(d) Except as provided in paragraph (c) of this section, ICI's must not participate in emission-related programs for emissions averaging, banking and trading, or nonconformance penalties.
42 U.S.C. 7401-7671q.
(b) * * *
(4) * * *
(e) The standards described in this section do not apply to diesel-fueled medium-duty passenger vehicles (MDPVs) that are subject to regulation under subpart S of this part, except as specified in subpart S of this part. The standards described in this section also do not apply to diesel engines used in such MDPVs, except as specified in the regulations in subpart S of this part. The term “medium-duty passenger vehicle” is defined in § 86.1803.
(e) The standards described in this section do not apply to Otto-cycle medium-duty passenger vehicles (MDPVs) that are subject to regulation under subpart S of this part, except as specified in subpart S of this part. The standards described in this section also do not apply to Otto-cycle engines used in such MDPVs, except as specified in subpart S of this part. The term “medium-duty passenger vehicle” is defined in § 86.1803.
This section includes text that specifies requirements that differ from § 86.113-94. Where a paragraph in § 86.113-94 is identical and applicable to this section, this will be indicated by specifying the corresponding paragraph
(a)
(2) For light-duty vehicles, light-duty trucks and medium-duty passenger vehicles certified for 50 state sale, and for Tier 2 and interim non-Tier 2 vehicles whose certification is carried over from the NLEV program or carried across from the California LEV I program, “California Phase 2” gasoline having the specifications listed in the table in this section may be used in exhaust emission testing as an option to the specifications in paragraph (a)(1) of this section. If a manufacturer elects to utilize this option, the manufacturer must conduct exhaust emission testing with gasoline having the specifications listed in the table in this paragraph (a)(2) and in the case of interim non-Tier 2 LDV/Ts and interim non-Tier 2 MDPVs whose certification is carried over from the NLEV program or carried across from California LEV I program certification the Administrator must also conduct exhaust emission testing with gasoline having the specifications listed in the table in this paragraph (a)(2) . However, the Administrator may use or require the use of test fuel meeting the specifications in paragraph (a)(1) of this section for certification confirmatory testing, selective enforcement auditing and in-use testing for all other vehicles. All fuel property test methods for this fuel are contained in Chapter 4 of the California Regulatory Requirements Applicable to the National Low Emission Vehicle Program (October, 1996). These requirements are incorporated by reference (see § 86.1). The table follows:
(3)(i) Unless otherwise approved by the Administrator, unleaded gasoline representative of commercial gasoline that will be generally available through retail outlets must be used in service accumulation. For model years 2004 and later, and unless otherwise approved by the Administrator, this gasoline must have a minimum sulfur content of 15 ppm. Unless otherwise approved by the Administrator, where the vehicle is to be used for evaporative emission durability demonstration, such fuel must contain ethanol as required by § 86.1824-01(a)(2)(iii). Leaded gasoline must not be used in service accumulation.
(ii) Unless otherwise approved by the Administrator, the octane rating of the gasoline used must be no higher than 1.0 Retail octane number above the lowest octane rating that meets the fuel grade the manufacturer will recommend to the ultimate purchaser for the relevant production vehicles. If the manufacturer recommends a Retail octane number rather than a fuel grade, then the octane rating of the service accumulation gasoline can be no higher than 1.0 Retail octane number above the recommended Retail octane number. The service accumulation gasoline must also have a minimum sensitivity of 7.5 octane numbers, where sensitivity is defined as the Research octane number minus the Motor octane number.
(iii) The Reid Vapor Pressure of the gasoline used must be characteristic of the motor fuel used during the season in which the service accumulation takes place.
(4) The specification range of the gasoline to be used under this paragraph (a) must be reported in accordance with §§ 86.094-21(b)(3) and 86.1844-01.
(b) through (g) [Reserved]. For guidance see § 86.113-94.
(f)* * *
(1)* * *
(ii)* * *
(C) Regardless of other requirements in this section relating to the testing of HLDTs, for Tier 2 HLDTs, the test weight basis for FTP and SFTP testing (both US06 and SC03), if applicable, is the vehicle curb weight plus 300 pounds. For MDPVs certified to standards in bin 11 in Tables S04-1 and 2 in § 86.1811-04, the test weight basis must be adjusted loaded vehicle weight (ALVW) as defined in this part.
Gasoline having the following specifications will be used by the Administrator except that the Administrator will not use gasoline having a sulfur specification higher than 0.0045 weight percent. Gasoline having the specifications set forth in the table in this section, or substantially equivalent specifications approved by the Administrator, may be used by the manufacturer except that the octane specification does not apply. In lieu of using gasoline having these specifications, the manufacturer may, for certification testing, use gasoline having the specifications specified in § 86.113-04 provided the cold CO emissions are not decreased. Documentation showing that cold CO emissions are not decreased must be maintained by the manufacturer and must be made available to the Administrator upon request. The table listing the cold CO fuel specifications described in the text in this section follows:
(f) The provisions of this subpart are not applicable to 2004 or later model year vehicles, except where specific references to provisions of this subpart are made in conjunction with provisions applicable to such vehicles.
a. revising the first sentence of paragraph (a),
b. adding one sentence to the end of paragraph (c)(1),
c. revising the first sentence of paragraph (e), and
d. adding paragraphs (f), (g) and (h).
These revisions and additions read as follows:
(a) Except as otherwise indicated, the provisions of this subpart apply to new 2001 and later model year Otto-cycle and diesel cycle light-duty vehicles, light-duty trucks and medium-duty passenger vehicles, including multi-fueled, alternative fueled, hybrid electric, and zero emission vehicles. * * *
(c) * * * (1) * * * A 2004 or later model year heavy-duty vehicle optionally certified as a light-duty truck under this provision must comply with all provisions applicable to MDPVs including exhaust and evaporative emission standards, test procedures, on-board diagnostics, refueling standards, phase-in requirements and fleet average standards under 40 CFR Part 85 and this part.
(e)
(f)
(g)
(h)
(1) Is an “incomplete truck” as defined in this subpart; or
(2) Has a seating capacity of more than 12 persons; or
(3) Is designed for more than 9 persons in seating rearward of the driver's seat; or
(4) Is equipped with an open cargo area (for example, a pick-up truck box or bed) of 72.0 inches in interior length or more. A covered box not readily accessible from the passenger compartment will be considered an open cargo area for purposes of this definition.
HCHO—Formaldehyde.
HEV—Hybrid electric vehicle.
HLDT—Heavy light-duty truck. Includes only those trucks over 6000 pounds GVWR (LDT3s and LDT4s).
HLDT/MDPV—Heavy light-duty trucks and medium-duty passenger vehicles.
LDV/LLDT—Light-duty vehicles and light light-duty trucks. Includes only those trucks rated at 6000 pounds GVWR or less (LDT1s and LDT2s).
LDV/T—Light-duty vehicles and light-duty trucks. This term is used collectively to include, or to show that a provision applies to, all light-duty vehicles and all categories of light-duty trucks, i.e.
LDT1, LDT2, LDT3 and LDT4.
LEV—Low Emission Vehicle.
MDPV—Medium-duty passenger vehicle.
NLEV—Refers to the National Low Emission Vehicle Program. Regulations governing this program are found at subpart R of this part.
NMOG—Non-methane organic gases.
RAF—Reactivity adjustment factor.
SULEV—Super Ultra Low Emission Vehicle.
TLEV—Transitional Low Emission Vehicle.
ULEV—Ultra Low Emission Vehicle.
ZEV—Zero Emission Vehicle.
(a) Except as required under paragraph (b) of this section or permitted under paragraphs (d), (e) and (f) of this section, the full useful life for all LDVs, LDT1s and LDT2s is a period of use of 10 years or 120,000 miles, whichever occurs first. For all HLDTs and MDPVs, full useful life is a period of 11 years or 120,000 miles, whichever occurs first. This full useful life applies to all exhaust, evaporative and refueling emission requirements except for standards which are specified to only be applicable at the time of certification.
(b) Manufacturers may elect to optionally certify a test group to the Tier 2 exhaust emission standards for 150,000 miles to gain additional NO
(c) Where intermediate useful life exhaust emission standards are
(d) Where cold CO standards are applicable, the useful life requirement for compliance with the cold CO standard only, is 5 years or 50,000 miles, whichever occurs first.
(e) Where LDVs, LDT1s and LDT2s of the 2003 or earlier model years are certified to Tier 2 exhaust emission standards for purposes of generating early Tier 2 NO
(f) For interim non-Tier 2 LDV/LLDTs, the useful life requirement for exhaust, evaporative and refueling emissions is 10 years or 100,000 miles, whichever occurs first.
a. revising paragraph (a);
b. adding paragraph (b)(8);
c. redesignating the text of paragraph (d) after the paragraph heading as (d)(1); and
d. adding paragraph (d)(2).
The revisions and additions read as follows:
(a)(1) Except as provided by paragraph (a)(2) of this section, all light-duty vehicles, light-duty trucks and MDPVs must be equipped with an onboard diagnostic (OBD) system capable of monitoring, for each vehicle's useful life, all emission-related powertrain systems or components. All systems and components required to be monitored by these regulations must be evaluated periodically, but no less frequently than once per Urban Dynamometer Driving Schedule as defined in Appendix I, paragraph (a), of this part, or similar trip as approved by the Administrator.
(2) Diesel fueled chassis-certified MDPVs and engine-certified diesel engines used in MDPVs, are subject to the requirements of this section only if the exhaust emission certification of the applicable test group is being carried across from a California configuration to which California OBD-II requirements are applicable.
(b) * * *
(8)
(i) The manufacturer must equip each HEV with a maintenance indicator consisting of a light that must activate automatically by illuminating the first time the minimum performance level is observed for each battery system component. Possible battery system components requiring monitoring are: battery water level, temperature control, pressure control, and other parameters critical for determining battery condition.
(ii) The manufacturer must equip “off-vehicle charge capable HEVs” with a useful life indicator for the battery system consisting of a light that must illuminate the first time the battery system is unable to achieve an all-electric operating range (starting from a full state-of-charge) which is at least 75 percent of the range determined for the vehicle in the Urban Driving Schedule portion of the All-Electric Range Test (see the California Exhaust Emission Standards and Test Procedures for 2003 and Subsequent Model Zero-Emission Vehicles, and 2001 and Subsequent Model Hybrid Electric Vehicles, in the Passenger Car, Light-Duty Truck and Medium-Duty Vehicle Classes. These requirements are incorporated by reference (see § 86.1).
(iii) The manufacturer must equip each HEV with a separate odometer or other device subject to the approval of the Administrator that can accurately measure the mileage accumulation on the engines used in these vehicles.
(d)
(2)(i) For interim non-Tier 2 and Tier 2 LDV/LLDTs and HLDT/MDPVs, vehicles produced through the 2007 model year, upon a manufacturer's written request, EPA will consider allowing the use of an on-board diagnostic system during the certification process, that functions properly on low-sulfur gasoline, but indicates sulfur-induced passes when exposed to high sulfur gasoline.
(ii) For interim non-Tier 2 and Tier 2 LDV/LLDTs and HLDT/MDPVs, if vehicles produced through the 2007 model year exhibit illuminations of the emission control diagnostic system malfunction indicator light due to high sulfur gasoline, EPA will consider, upon a manufacturer's written request, allowing modifications to such vehicles on a case-by-case basis so as to eliminate the sulfur induced illumination.
(a) * * *
(3) * * *
(vi) The exhaust emission standards to which the test group is certified, and for test groups having different in-use standards, the corresponding exhaust emission standards that the test group must meet in use. In lieu of this requirement, manufacturers may use the standardized test group name designated by EPA;
(e) For each test group of Tier 2 LDV/LLDTs and HLDT/MDPVs and interim non-Tier 2 LDV/LLDTs and HLDT/MDPVs the manufacturer must submit, with the Part II certification application, an engineering evaluation demonstrating to the satisfaction of the Administrator that a discontinuity in emissions of non-methane organic gases, carbon monoxide, oxides of nitrogen and formaldehyde measured on the Federal Test Procedure (subpart B of this part) does not occur in the temperature range of 20 to 86 degrees F. For diesel vehicles, the engineering evaluation must also include particulate emissions.
* * * For Tier 2 and interim non-Tier 2 vehicles, this section also applies to hybrid electric vehicles and zero emission vehicles. Unless otherwise specified, requirements and provisions of this subpart applicable to methanol fueled vehicles are also applicable to Tier 2 and interim non-Tier 2 ethanol fueled vehicles.
(f) * * * Interim non-Tier 2 LDV/Ts may be certified to applicable Tier 1 exhaust emission standards at high altitude as set forth in §§ 86.1811-01, 86.1812-01, 86.1813-01, 86.1814-02 and 86.1815-02. Requirements to meet emission standards at high altitude are optional for interim non-Tier 2 MDPVs.
(i) * * *
(6) * * * For Tier 2 and interim non-Tier 2 vehicles, this provision does not
(13)
(ii) Such calibrations must not unnecessarily reduce the NMHC+NO
(iii) If reductions in control system NMHC+NO
(iv) A/C-on specific “open-loop” or “commanded enrichment” air-fuel enrichment strategies (as defined below), which differ from A/C-off “open-loop” or “commanded enrichment” air-fuel enrichment strategies, may not be used, with the following exceptions: Cold-start and warm-up conditions, or, subject to Administrator approval, conditions requiring the protection of the vehicle, occupants, engine, or emission control hardware. Other than these exceptions, such strategies which are invoked based on manifold pressure, engine speed, throttle position, or other engine parameters must use the same engine parameter criteria for the invoking of this air-fuel enrichment strategy and the same degree of enrichment regardless of whether the A/C is on or off. “Open-loop” or “commanded” air-fuel enrichment strategy is defined as enrichment of the air to fuel ratio beyond stoichiometry for the purposes of increasing engine power output and the protection of engine or emissions control hardware. However, “closed-loop biasing,” defined as small changes in the air-fuel ratio for the purposes of optimizing vehicle emissions or driveability, must not be considered an “open-loop” or “commanded” air-fuel enrichment strategy. In addition, “transient” air-fuel enrichment strategy (or “tip-in” and “tip-out” enrichment), defined as the temporary use of an air-fuel ratio rich of stoichiometry at the beginning or duration of rapid throttle motion, must not be considered an “open-loop” or “commanded” air-fuel enrichment strategy.
(14) “
(A) Such strategies are substantially employed during the FTP or SFTP;
(B) Such strategies are demonstrated not to significantly reduce vehicle NMHC+NO
(C) Such strategies are demonstrated to be necessary to protect the vehicle occupants, engine, or emission control hardware.
(ii) If the manufacturer proposes to use a “lean-on-cruise” calibration strategy, the manufacturer must specify the circumstances under which such a calibration would be used, and the reason or reasons for the proposed use of such a calibration.
(o) Unless otherwise approved by the Administrator, manufacturers must measure NMOG emissions in accordance with the California Non-Methane Organic Gas Test Procedures. These procedures are incorporated by reference (see § 86.1).
(p) For gasoline and diesel-fueled Tier 2 and interim non-Tier 2 vehicles, manufacturers may measure non-methane hydrocarbons (NMHC) in lieu of NMOG. Manufacturers must multiply NMHC measurements from gasoline vehicles by an adjustment factor of 1.04 before comparing with the NMOG standard to determine compliance with that standard. Manufacturers may use other factors to adjust NMHC results to more properly represent NMOG results. Such factors must be based upon comparative testing of NMOG and NMHC emissions and be approved in advance by the Administrator.
* * * This section does not apply to 2004 and later model year vehicles, except as specifically referenced by § 86.1811-04.
(a)
(2) This section also applies to LDVs, LDTs and MDPVs of model years prior to 2004, when manufacturers certify such vehicles to Tier 2 exhaust emission requirements to utilize alternate phase-in schedules, as allowed under paragraph (k)(6) of this section, and/or to earn early NO
(3) Except where otherwise specified, this section applies instead of §§ 86.1811-01, 86.1812-01, 86.1813-01, 86.1814-01, 86.1814-02, 86.1815-01, and 86.1815-02.
(4) Except where otherwise specified, the provisions of this section apply equally to LDVs and all categories of LDTs, and to all MDPVs. Numerous provisions are applicable equally to HLDTs and MDPVs, as reflected by the term HLDT/MDPV. Numerous provisions apply equally to LDVs and LLDTs as reflected by the term LDV/LLDT.
(5) The exhaust emission standards and evaporative emission standards of this section apply equally to certification and in-use LDVs, LDTs and MDPVs, unless otherwise specified.
(b)
(2) Interim non-Tier 2 HLDTs tested to Tier 1 SFTP standards, must be tested on an adjusted loaded vehicle weight (ALVW) basis, as that term is defined in this subpart, during the SC03 element of the SFTP.
(3) Except as required in paragraphs (b)(2) and (b)(4) of this section, interim non-Tier 2 HLDT/MDPVs may be tested on an ALVW basis or an LVW basis to demonstrate compliance with any exhaust or evaporative emission standard set forth in this Part.
(4) MDPVs certified to bin 11 standards from Tables S04-1 and -2 must be tested on an ALVW basis to demonstrate compliance with any exhaust emission standard set forth in this part.
(c)
(1) For a given test group a manufacturer desires to certify to operate only on one fuel, the manufacturer must select a set of standards from the same bin (line or row) in Table S04-1 of this section for non-methane organic gases (NMOG), carbon monoxide (CO), oxides of nitrogen (NO
(2) For a given test group of flexible-fueled, bi-fuel or dual fuel vehicles when operated on the alcohol or gaseous fuel they are designed to use, manufacturers must select a bin of standards from Table S04-1 of this section and the corresponding bin in Table S04-2, if any. When these flexible-fueled, bi-fuel or dual fuel vehicles are certified to operate on gasoline or diesel fuel, the manufacturer may choose to comply with the next numerically higher applicable NMOG standard, if any, above the bin which contains the standards selected for certification on the gaseous or alcohol fuel.
(3)(i) For a given test group of flexible-fueled, bi-fuel or dual fuel vehicles certified to bin 10 in Table S04-1, when operated on the alcohol or gaseous fuel they are designed to use, manufacturers may choose to comply with a NMOG standard of 0.230 for LDV/LLDTs or 0.280 g/mi for HLDT/MDPVs at full useful life and corresponding intermediate life standards of 0.160 g/mi and 0.195 g/mi, respectively.
(ii) For a given test group of flexible-fueled, bi-fuel or dual fuel vehicles certified to bin 8 in Table S04-1, when operated on the alcohol or gaseous fuel they are designed to use, manufacturers may choose to comply with a NMOG standard of 0.156 g/mi for LDV/LLDTs and 0.180 for HLDT/MDPVs at full useful life and corresponding intermediate life standards of 0.125 g/mi and 0.140 g/mi, respectively.
(4)(i) For bins where intermediate life standards are applicable, a manufacturer may elect not to comply with such standards. Except as permitted in paragraph (c)(4)(iv) of this section, the manufacturer must certify such vehicles to a useful life of 15 years or 150,000 miles, whichever occurs first, for LDV/LLDTs and HLDT/MDPVs.
(ii) A manufacturer electing not to comply with intermediate life standards, as permitted in paragraph (c)(4)(i) of this section, may not generate additional NO
(iii) For bins where intermediate life standards are not applicable, or are specified to be optional by paragraph (c)(4)(iv) of this section, a manufacturer may generate additional NO
(iv) For diesel vehicles certified to bin 10, intermediate life standards are optional regardless of whether the manufacturer certifies the test group to a full useful life of 120,000 miles or 150,000 miles.
(5) In a given model year, an individual vehicle may not be included in both the Tier 2 program and an interim program.
(6) Tables S04-1 and S04-2 follow:
(d)
(ii) During a phase-in year, the manufacturer must comply with the 0.07 g/mi fleet average standard for the required phase-in percentage for that year as specified in paragraph (k)(1) of this section, or for the alternate phase-in percentage as permitted under paragraph (k)(6) of this section.
(2)
(3)
(e)
(1)
(2)
(3)
(i) For gasoline-fueled, diesel-fueled and methanol-fueled LDVs, LDTs and MDPVs: 0.20 grams hydrocarbon per gallon (0.053 grams per liter) of fuel dispensed.
(ii) For liquefied petroleum gas-fueled LDV, LDTs and MDPVs: 0.15 grams hydrocarbon per gallon (0.04 grams per liter) of fuel dispensed.
(iii) Refueling standards for HLDTs are subject to the phase-in requirements found in § 86.1810-01(k). MDPVs must also comply with the phase-in requirement in § 86.1810-01(k) and must be grouped with HLDTs to determine phase-in compliance.
(4)
(5)
(ii) MDPVs not certified to meet the evaporative emission standards in this paragraph (e) as permitted under the phase-in schedule of paragraph (k) of this section, must meet applicable evaporative emission standards for heavy-duty vehicles in § 86.099-10.
(6) In cases where applicable California emission standards are as stringent or more stringent than applicable standards specified under this paragraph (e), the Administrator may accept data indicating compliance with California standards to
(f)
(2)(i) Manufacturers must calculate their applicable full useful life SFTP standards for NMHC+NO
(ii)(A) Manufacturers must determine compliance with NMHC+NO
(B) The results of the calculation in paragraph (f)(2)(ii)(A) of this section must be rounded to one more decimal place than the applicable standard calculated in paragraph (f)(2)(i) of this section and then compared with that standard.
(3) For interim non-Tier 2 gasoline, diesel and flexible-fueled LDT3s and LDT4s, manufacturers may, alternatively, meet the gasoline-fueled vehicle SFTP standards found in §§ 86.1814-02 and 86.1815-02, respectively.
(4) Interim non-Tier 2 gasoline, diesel and flexible-fueled LDV/LLDTs certified to bin 10 FTP exhaust emission standards from Table S04-1 in paragraph (c) of this section may meet the gasoline Tier 1 SFTP requirements found at § 86.1811-01(b).
(5) SFTP standards for PM are not applicable to interim non-Tier 2 LDV/Ts. For Tier 2 LDV/Ts, the 4000 mile PM standard is equal to the full life PM standard calculated under paragraph (f)(2) of this section. The requirements of this paragraph (f)(5) also apply to Tier 2 flexible fuel vehicles when operated on gasoline or diesel fuel. (See regulations in § 86.1829-01(b)(1)(iii)(B) regarding data submittal for PM results for gasoline vehicles.)
(6)(i) In lieu of complying with 4000 mile SFTP standards described in this paragraph, diesel LDV/LLDTs through model year 2006, may comply instead with intermediate life SFTP standards derived from Tier 1 intermediate life SFTP standards for gasoline vehicles.
(ii) To calculate intermediate life SFTP standards, substitute intermediate life Tier 1 FTP and SFTP values from Tables S04-5 and S04-6 in this paragraph (f), as appropriate, for the full life values in the equation in paragraph (f)(2)(i) of this section. Substitute the applicable intermediate life standards for the full life current FTP standard. If there is no applicable intermediate life standard use the full life current FTP standard.
(iii) A manufacturer of diesel LDV/LLDTs must declare which option it will use (4,000 mile or intermediate life standards) in Part I of its certification application.
(g)
(1) For LDVs and LDT1s, the standard is 10.0 grams per mile CO.
(2) For LDT2s, LDT3s and LDT4s, and MDPVs the standard is 12.5 grams per mile CO.
(3) These standards do not apply to interim non-Tier 2 MDPVs.
(h)
(1) Hydrocarbons: 100 ppm as hexane, for certification and SEA testing; 220 ppm as hexane, for in-use testing.
(2) Carbon monoxide: 0.5% for certification and SEA testing; 1.2% for in-use testing.
(3) These standards do not apply to interim non-Tier 2 MDPVs.
(i) Idle CO standards and references to such standards in this subpart, do not apply to any 2004 or later model year LDV, LDT, or MDPV or to any LDV, LDT or MDPV certified to Tier 2 standards before model year 2004 for purposes of generating early NO
(j)
(k)
(2) Manufacturers must also comply with the phase-in requirements in Tables S04-7 and S04-8 of this paragraph (k) for the evaporative emission requirements contained in paragraph (e) of this section.
(3) Manufacturers may opt to use different LDV/LLDTs and HLDT/MDPVs to meet the phase-in requirements for evaporative emissions and FTP exhaust emissions, provided that the manufacturer meets the minimum applicable phase-in requirements in Table S04-7 and Table S04-8 of this paragraph (k) for both FTP exhaust and evaporative emissions. A LDV, LDT or MDPV counted toward compliance with any phase-in requirement for FTP exhaust or evaporative standards, must comply with all applicable Tier 2 exhaust requirements or all applicable evaporative requirements, respectively, described in this section.
(4) LDVs, LDTs and MDPVs not certified to meet the Tier 2 FTP exhaust requirements during model years 2004-2008, as allowed under this subpart, are subject to the provisions of paragraph (l) of this section.
(5)
(ii) Small volume manufacturers, as defined in this part, are exempt from the HLDT/MDPV exhaust and evaporative phase-in requirement for model year 2008 in Table S04-8 of this section but must comply with the 100% requirement for the 2009 model year. Small volume manufacturers are also exempt from the HLDT/MDPV interim fleet average NO
(iii) Small volume manufacturers must comply with the FTP exhaust emission standards from Tables S04-1 and 2 of paragraph (c) of this section for all HLDT/MDPVs of model years 2004 and later, except that 2004 model year HLDTs may comply with Tier 1 exhaust emission standards subject to the provisions of paragraph (l)(2)(vii) of this section, and 2004 model year MDPVs may comply with heavy-duty vehicle standards subject to the provisions of paragraph (l)(2)(viii) of this section. Small volume manufacturers must also comply with the 0.20 g/mi fleet average NO
(6)(i) A manufacturer may elect an alternate phase-in schedule that results in 100% phase-in for LDV/LLDTs by 2007. Alternate phase-in schedules must produce a sum of at least 250% when the percentages of LDV/LLDTs certified to Tier 2 requirements for each model year from 2001 through 2007 are summed. As an example, a 10/25/50/65/100 percent phase-in that began in 2003 would have a sum of 250 percent and would be acceptable. However, a 10/25/40/70/100 percent phase-in that began the same year would have a sum of 245 percent and would not be acceptable.
(ii) A manufacturer electing this option for LDV/LLDTs may calculate its compliance with the evaporative standards in paragraph (e)(1) of this section separately from its compliance with Tier 2 exhaust standards, provided that the phase-in schedules for each separately produce a sum of at least 250 percent when calculated as described in paragraph (k)(6)(i) of this section. A vehicle counted towards compliance with any phase-in requirement for the Tier 2 exhaust standards or the evaporative standards in paragraph (e)(1) of this section, must comply with all applicable Tier 2 exhaust standards or all evaporative standards, as applicable, described in this section.
(iii) In addition to the requirements of paragraphs (k)(6)(i) and (ii) of this section, except as permitted in paragraph (k)(6)(vii) of this section, a manufacturer of LDV/LLDTs electing to use an alternate phase-in schedule for compliance with the Tier 2 exhaust standards or the evaporative standards in paragraph (e)(1) of this section must ensure that the sum of the percentages of vehicles from model years 2001 through 2004, meeting such exhaust or evaporative standards, as applicable, is at least 25%.
(iv) A manufacturer may elect an alternate phase-in schedule that results in 100% phase-in for HLDT/MDPVs by 2009. The requirements of paragraphs (k)(6)(i) through (k)(6)(ii) of this section apply, except that for HLDT/MDPVs, the calculation described in paragraphs (k)(6)(i) and (k)(6)(ii) of this section may cover model years 2001 through 2009 and must produce a sum of at least 150%.
(v) A manufacturer electing to use any alternate phase-in schedule permitted under this section must provide in its Application for Certification for the first year in which it intends to use such a schedule, and in each succeeding year during the phase-in, the intended phase-in percentages for that model year and the remaining phase-in years along with the intended final sum of those percentages as described in this paragraph (k)(6). This information may be included with the information required under § 86.1844-01(d)(13). In its year end annual reports, as required under § 86.1844-01(e)(4) the manufacturer must include sufficient information so that the Administrator can verify compliance with the alternative phase-in schedule established under paragraph (k)(6) of this section.
(vi) Under an alternate phase-in schedule, the projected phase-in percentage is not binding for a given model year, provided the sums of the actual phase-in percentages that occur meet the appropriate total sums as required in paragraph (k)(6) of this section, and provided that 100% actual compliance is reached for the appropriate model year, either 2007 or 2009, as described in paragraph (k)(6) of this section.
(vii) A manufacturer unable to meet the 25% requirement in paragraph (k)(6)(iii) of this section, must:
(A) Ensure that the sum of the percentages of vehicles for model years 2001 through 2004, meeting such exhaust or evaporative standards, as applicable, is at least 20%.
(B) Subtract that sum of percentages for model years 2001 through 2004 from 25%, and multiply the unrounded result by 2.
(C) Round the product from paragraph (k)(6)(vii)(B) of this section to the nearest 0.1% and add that to 50%. That sum becomes the required phase-in percentage for the 2005 model year.
(D) Comply with the phase-in percentage for the 2005 model year determined in paragraph (k)(6)(vii)(C) of this section.
(E) Comply with a minimum phase-in percentage for the 2006 model year determined by the following equation:
(7)(i) Sales percentages for the purpose of determining compliance with the phase-in of the Tier 2 requirements and the phase-in of the evaporative standards in paragraph (e)(1) of this section, must be based upon projected U.S. sales of LDV/LLDTs and HLDT/MDPVs of the applicable model year by the manufacturer to the point of first sale. Such sales percentages must be rounded to the nearest one tenth of a percent, and must not include vehicles and trucks projected to be sold to points of first sale in California or a state that has adopted California requirements for that model year as permitted under section 177 of the Act.
(ii) Alternatively, the manufacturer may petition the Administrator to allow actual volume produced for U.S. sales to be used in lieu of projected U.S. sales for purposes of determining compliance with the phase-in percentage requirements under this section. The manufacturer must submit its petition within 30 days of the end of the model year to the Vehicle Programs and Compliance Division. For EPA to approve the use of actual volume produced for U.S. sales, the manufacturer must establish to the satisfaction of the Administrator, that actual production volume is functionally equivalent to actual sales volume of LDV/LLDTs and HLDT/MDPVs sold in states other than California and states that have adopted California standards.
(iii) Manufacturers must submit information showing compliance with all phase-in requirements of this section
(l)
(ii) The provisions of paragraphs (c) (1), (2) and (3) of this section apply to flexible-fueled, dual fuel and multi-fuel interim non-Tier 2 LDV/LLDTs.
(iii) Only manufacturers that comply with the applicable FTP standards in Tables S04-1 and 2 of paragraph (c) of this section for all of their 2004 model year HLDTs and declare their intention to comply with the 2004 model year 25% phase-in requirement to the 0.20 g/mi interim fleet average NO
(iv) The provisions of paragraph (c)(4) of this section apply to interim non-Tier 2 vehicles.
(2)
(ii) Except as permitted under paragraphs (l)(2) (vii) and (viii) of this section, HLDTs and MDPVs of model years 2004-2008 that are not used to meet the Tier 2 FTP phase-in requirements including the Tier 2 fleet average NO
(iii) Manufacturers may choose the bin of full useful life standards and corresponding intermediate life standards to which they certify test groups of HLDTs and MDPVs, subject to the requirements in paragraph (l)(3)(ii) of this section. Manufacturers may include HLDT/MDPVs in the interim program that are not used to meet the Tier 2 fleet average NO
(iv)
(v)(A) A manufacturer may elect an alternate phase-in schedule, beginning as early as the 2001 model year, that results in 100% compliance by 2007 with the fleet average NO
(B) If a manufacturer elects not to bring all of its HLDT/MDPVs into compliance with the interim requirements in 2004 as permitted under paragraphs (l)(2)(vii) and
(viii) of this section, it may still use an alternate phase-in schedule to attain 100% compliance with the interim fleet average NO
(vi) The provisions of paragraphs (c) (1), (2) and (3) of this section apply to flexible-fueled, dual fuel and multi-fuel interim non-Tier 2 HLDT/MDPVs.
(vii) For 2004 model year HLDT test groups whose model year commences before December 21, 2003, the manufacturer may exempt such HLDTs from compliance with any requirements applicable to interim non-Tier 2 HLDTs, and such HLDTs must be produced in accordance with standards and requirements in §§ 86.1814-02 and §§ 86.1815-02. Such HLDTs must also meet the refueling emission standards
(viii) For 2004 model year heavy-duty vehicles whose model year commences before December 21, 2003, the manufacturer may exempt such vehicles from compliance with any requirements applicable to interim non-Tier 2 MDPVs. Exempted vehicles will not be considered MDPVs and must be produced in accordance with standards and requirements in § 86.099-10. Exempted vehicles are also exempted from refueling emission standards.
(ix) For 2004 model year HLDT and MDPV test groups whose model year commences on or after December 21, 2003, the manufacturer must comply with all interim non-Tier 2 requirements in this section.
(A) All such vehicles, but not more than 25% of the manufacturer's total sales of 2004 model year HLDT/MDPVs must meet the interim non-Tier 2 fleet average NO
(B) All such vehicles but not more than 40% of the manufacturer's 2004 model year HLDT/MDPVs must comply with the refueling requirements in paragraph (e)(3) of this section.
(x) Only those manufacturers that comply with the interim non-Tier 2 FTP standards for all of their 2004 model year HLDTs and declare their intention to comply with the 2004 model year 25% phase-in requirement to the fleet average interim NO
(xi) Only those manufacturers that comply with the interim non-Tier 2 FTP standards for all of their 2004 model year MDPVs, and declare their intention to comply with the 2004 model year 25% phase-in requirement to the fleet average interim NO
(A) Use the exhaust emission standards of bin 11 in Tables S04-1 and S04-2 of paragraph (c) in this section for MDPVs through model year 2008;
(B) For diesel-fueled vehicles, certify the engines in such vehicles, through model year 2007, to provisions in this part 86 applicable to diesel-fueled heavy-duty engines of the appropriate model year. Such diesel fueled vehicles must not be included in any count or determination of compliance with the phase-in requirements applicable to interim non-Tier 2 MDPVs; and
(C) Use the optional higher NMOG values for interim LDT4s certified to bin 10 standards that are shown in Tables S04-1 and 2.
(xii) Manufacturers electing to comply with the provisions of paragraph (l)(2)(xi) of this section must declare their intention to comply with the 2004 model year 25% phase-in requirement to the fleet average interim NO
(xiii) Where diesel-fueled heavy-duty engines are used as permitted under paragraph (l)(2)(xi)(B) of this section, such engines must be treated as a separate averaging set—MDPV HDDEs— under the averaging, banking and trading provisions applicable to heavy-duty diesel engines. Only NO
(3)
(ii) Manufacturers must comply with a fleet average full useful life NO
(iii) Manufacturers must determine their compliance with these interim fleet average NO
(iv) Manufacturers may generate, bank, average, trade and use interim non-Tier 2 NO
(m)
(2) Flexible-fueled and dual-fuel Tier 2 and interim non-Tier 2 vehicles must be certified to NMOG exhaust emission standards both for operation on gasoline and on any alternate fuel they are designed to use. Manufacturers may measure NMHC in lieu of NMOG when flexible-fueled and dual-fuel vehicles are operated on gasoline, subject to the requirements of § 86.1810(p).
(n)
(o)
(2) Manufacturers must not apply reactivity adjustment factors (RAFs) to NMOG measurements. See § 86.1841.
(p)
(2) These standards apply only to LDV/LLDTs produced up through the 2008 model year, and HLDT/MDPVs produced up through the 2010 model year. These standards are subject to other limitations described in paragraph (p)(3) of this section.
(3) For the first model year and also for the next model year after that, in which a test group of vehicles is certified to a bin of standards to which it has not previously been certified, the standards in Table S04-10 of this paragraph (p) apply for purposes of in-use testing only. The standards apply equally to all LDV/Ts and MDPVs subject to the model year limitation in paragraph (p)(2) of this section. Table S04-10 follows:
(4) For diesel vehicles certified to bin 10, separate in-use standards apply for NO
(q)
(i) Defer 100% compliance with the fleet average NO
(ii) Defer 100% compliance with the evaporative emission standards and/or fleet average NO
(iii) Defer 100% compliance with the requirements that interim HLDTs and MDPVs comply with applicable emission standards shown in Tables S04-1 and S04-2, until 2005;
(iv) Defer 100% compliance with the fleet average NO
(v) Defer 100% compliance with the the evaporative emission standards and/or fleet average NO
(2) Applications for relief must be in writing and must:
(i) Be submitted before the earliest date of noncompliance;
(ii) Include evidence that the manufacturer will incur severe economic hardship if relief is not granted;
(iii) Include evidence that the noncompliance will occur despite the best efforts of the manufacturer to comply; and
(iv) Include evidence that the manufacturer has made every reasonable effort to purchase credits to address the noncompliance, where applicable.
(r)
(2) The NMOG credit must be determined through a two-step process.
(i) The first step must determine the ozone reduction potential of the direct ozone reducing device, the ozone reduction potential of exhaust NMOG reductions beyond Bin 5 of the Tier 2 standards, and the ratio of the two methods of reducing ambient ozone levels. The requirements for this step are described in paragraph (r)(3) of this section.
(ii) The second step must demonstrate and certify the relevant performance characteristics of the specific ozone reducing device. The requirements for this step are described in paragraph (r)(4) of this section.
(3) The ozone reduction potential of the direct ozone reducing device and the ozone reduction potential of exhaust NMOG reductions beyond Bin 5 of the Tier 2 standards must be estimated using procedures which are approved by the Administrator in advance. At a minimum:
(i) The modeling must utilize an urban airshed model using up-to-date chemical and meteorological simulation techniques;
(ii) Four local areas must be modeled: New York City, Chicago, Atlanta and Houston;
(iii) The ozone episodes to be modeled must meet the selection criteria established by EPA for State ozone SIPs;
(iv) Photochemical and dispersion modeling must follow that used by EPA to project the ozone impacts of this rule, or its equivalent;
(v) Emission projections must be made for calendar year 2007 and be consistent with those used by EPA in support of this final rule, or reflect updates approved by EPA;
(vi) Baseline emissions (emissions prior to use of the direct ozone reducing device or the VOC emission reductions) must include the benefits of the Tier 2 emission and sulfur standards; as well as all other emission controls assumed in EPA's ozone modeling of the benefits of the Tier 2 and sulfur standards, as described in the Final Regulatory Impact Analysis to the Tier 2 and Sulfur Rule;
(vii) The ozone benefit of the direct ozone reducing device must assume a radiator area of 0.29 square meters, an air flow velocity through the radiator of 40% of vehicle speed, and an ozone reduction efficiency of 80%, or other
(viii) The ozone level of the air entering the direct ozone reducing device must be assumed to be 40% less than that existing in the grid cell where the vehicle is located;
(ix) The ozone benefit of VOC emission reductions must be modeled by assuming that all Tier 2 LDVs, LDTs and MDPVs meet an exhaust NMOG standard of 0.055 g/mi or lower instead of a 0.09 g/mi NMOG standard;
(x) The ozone reducing device must be assumed to be present on all of the Tier 2 LDVs, LDTs and MDPVs modeled as meeting the more stringent NMOG standard described in paragraph (r)(3)(ix) of this section;
(xi) The relationship between changes in exhaust NMOG emission standards and in-use VOC emissions must be determined sufficiently far in the future to ensure that the change in ozone being modeled is sufficiently large to allow comparison with the impact of the ozone reducing device;
(xii) LDV, LDT and MDPV emissions must be modeled using the updated Tier 2 emission model developed by EPA as part of the Tier 2 rulemaking (available from EPA upon request) or MOBILE6, once this model is available;
(xiii) The ozone benefit of the direct ozone reducing device must be the reduction in the peak one-hour ozone level anywhere in the modeled region on the day when ozone is at its highest;
(xiv) The NMOG credit in each local area must be the reduction in peak one hour ozone associated with use of the direct ozone reducing device divided by the reduction in peak one hour ozone associated with the more stringent exhaust NMOG emission standard multiplied by the reduction the exhaust NMOG standard (in g/mi) modeled in paragraph (r)(3)(ix) of this section; and
(xv) The NMOG credit applicable to the generic direct ozone reducing device modeled in paragraph (r)(3)(vii) of this section must be determined by arithmetically averaging the NMOG credit determined in paragraph (r)(3)(xiv) of this section for each of the four local areas.
(4) The manufacturer must submit data, using procedures which have been approved by the Administrator in advance, that demonstrate the following aspects of the device being certified:
(i) The air flowrate through the device as a function of vehicle speed;
(ii) The ozone reduction efficiency of the device over the useful life of the vehicle for a range of vehicle speeds and ozone levels;
(iii) The method through which the onboard diagnostic system will detect improper performance.
(5) The NMOG credit for the specific application of this technology tested under the provisions of paragraph (r)(4) of this section is the four-area NMOG credit determined in paragraph (r)(3)(xv) of this section scaled based on the performance of the specific application tested under the provisions of paragraph (r)(4) of this section relative to those assumed in paragraph (r)(3)(vii) of this section. This scaling must assume a linear relationship between the NMOG credit and three aspects of the direct ozone reducing device: radiator area, average air flow through the radiator relative to vehicle speed, and ozone reduction efficiency and the NMOG credit. The NMOG credit must be rounded to the nearest 0.001 g/mi. For example, if the NMOG credit determined in paragraph (r)(3)(xv) of this section was 0.01 g/mi and the specific direct ozone reducing device being certified had an area of 0.20 square meters, an air flow velocity of 30% of vehicle speed and an ozone reducing efficiency of 70%, and the generic ozone reducing device simulated in the ozone model under paragraph (r)(3)(vii) of this section had an area of 0.29 square meters, an air flow velocity of 40% of vehicle speed and an ozone reducing efficiency of 80%, the NMOG credit applicable to the specific device being certified would be:
* * * This section does not apply to 2004 and later model year vehicles, except as specifically referenced by § 86.1811-04.
* * * This section does not apply to 2004 and later model year vehicles, except as specifically referenced by § 86.1811-04.
* * * This section does not apply to 2004 and later model year vehicles, except as specifically referenced by § 86.1811-04.
* * * This section does not apply to 2004 and later model year vehicles, except as specifically referenced by § 86.1811-04.
This section applies to gasoline-, methanol-, liquefied petroleum gas-, and natural gas-fueled LDV/Ts and MDPVs. * * *
(a) * * *
(2) * * *
(iii) For gasoline fueled vehicles certified to meet the evaporative emission standards set forth in § 86.1811-04(e)(1), any service accumulation method for evaporative emissions must employ gasoline fuel for the entire service accumulation period which contains ethanol in, at least, the highest concentration permissible in gasoline under federal law and that is commercially available in any state in the United States. Unless otherwise approved by the Administrator, the manufacturer must determine the appropriate ethanol concentration by selecting the highest legal concentration commercially available during the calendar year before the one in which the manufacturer begins its service accumulation. The manufacturer must also provide information acceptable to the Administrator to indicate that the service accumulation method is of sufficient design, duration and severity to stabilize the permeability of all non-metallic fuel and evaporative system components to the service accumulation fuel constituents.
(iv) For flexible-fueled, dual-fueled, multi-fueled, ethanol-fueled and methanol-fueled vehicles certified to
(v) A manufacturer may use other methods, based upon good engineering judgment, to meet the requirements of paragraphs (a)(2) (iii) and (iv) of this section, as applicable. These methods must be approved in advance by the Administrator and meet the objectives of paragraphs (a)(2) (iii) and (iv) of this section, as applicable: to provide assurance that the permeability of all non-metallic fuel and evaporative system components will not lead to evaporative emission standard exceedance under sustained exposure to commercially available alcohol-containing fuels for the useful life of the vehicle.
(e) Unless otherwise approved by the Administrator, a manufacturer of hybrid electric vehicles must create separate test groups based on both the type of battery technology employed by the HEV and upon features most related to their exhaust emission characteristics.
(b) * * * (1) * * *
(iii) * * *
(E) In lieu of testing a gasoline or diesel fueled Tier 2 or interim non-Tier 2 vehicle for formaldehyde emissions when such vehicles are certified based upon NMHC emissions, a manufacturer may provide a statement in its application for certification that such vehicles comply with the applicable standards. Such a statement must be based on previous emission tests, development tests, or other appropriate information.
(d)(1) Beginning in the 2004 model year, the exhaust emissions must be measured from all LDV/T exhaust emission data vehicles tested in accordance with the federal Highway Fuel Economy Test (HWFET; 40 CFR part 600, subpart B). The oxides of nitrogen emissions measured during such tests must be multiplied by the oxides of nitrogen deterioration factor computed in accordance with § 86.1823-01 and subsequent model year provisions, and then rounded and compared with the applicable emission standard in § 86.1811-04. All data obtained from the testing required under this paragraph (d) must be reported in accordance with the procedures for reporting other exhaust emission data required under this subpart.
(2) In the event that one or more emission data vehicles fail the applicable HWFET standard in § 86.1811-04, the manufacturer may submit to the Administrator engineering data or other evidence showing that the system is capable of complying with the standard. If the Administrator finds, on the basis of an engineering evaluation, that the system can comply with the HWFET standard, he or she may accept the information supplied by the manufacturer in lieu of the test data.
(3) The provisions of paragraphs (d)(1) and (d)(2) of this section do not apply to MDPVs.
(b) Fleet average NO
(b) * * *
(1) * * *
(i) The optional small-volume manufacturers certification procedures apply to LDV/Ts and MDPVs produced by manufacturers with U.S. sales, including all vehicles and engines imported under provisions of 40 CFR 85.1505 and 85.1509 (for the model year in which certification is sought) of fewer than 15,000 units (LDV/Ts, MDPVs, heavy-duty vehicles and heavy-duty engines combined).
(c) * * *
(2) * * *
(iii) The provisions of § 86.1845-01(c)(2) and § 86.1845-04(c)(2) that require one vehicle of each test group during high mileage in-use verification testing to have a minimum odometer mileage of 75 percent of the full useful life mileage for Tier 1 and NLEV LDV/Ts, or 90,000 (or 105,000) miles for Tier 2 and interim non-Tier 2 vehicles, do not apply.
(c) Manufacturers of vehicles equipped with periodically regenerating trap oxidizer systems must propose a procedure for testing and certifying such vehicles including SFTP testing for the review and approval of the Administrator. The manufacturer must submit its proposal before it begins any service accumulation or emission testing. The manufacturer must provide with its submittal, sufficient documentation and data for the Administrator to fully evaluate the operation of the trap oxidizer system and the proposed certification and testing procedure.
(d) The provisions of paragraphs (a) and (b) of this section also apply to MDPVs.
(a) * * *
(1) * * *
(iii) For the SFTP composite standard of NMHC+NO
(e) Unless otherwise approved by the Administrator, manufacturers must not use Reactivity Adjustment Factors (RAFs) in their calculation of the certification levels of any pollutant, regardless of the fuel used in the test vehicle.
(d) * * *
(15) For HEVs, unless otherwise approved by the Administrator, the information required by the “California Exhaust Emission Standards and Test Procedures for 2003 and Subsequent Model Zero-Emission Vehicles, and 2001 and Subsequent Model Hybrid Electric Vehicles, in the Passenger Car, Light-Duty Truck and Medium-duty Vehicle Classes” must be supplied. These procedures are incorporated by reference (see § 86.1).
(16) (i) For Tier 2 and interim non-Tier 2 vehicles beginning with the 2004 model year, a statement indicating that the manufacturer has conducted an engineering analysis of the complete exhaust system to ensure that the exhaust system has been designed:
(A) To facilitate leak-free assembly, installation and operation for the full useful life of the vehicle; and
(B) To facilitate that such repairs as might be necessary on a properly maintained and used vehicle can be performed in such a manner as to maintain leak-free operation, using tools commonly available in a motor vehicle dealership or independent repair shop for the full useful life of the vehicle.
(ii) The analysis must cover the exhaust system and all related and attached components including the air injection system, if present, from the engine block manifold gasket surface to a point sufficiently past the last catalyst and oxygen sensor in the system to assure that leaks beyond that point will not permit air to reach the oxygen sensor or catalyst under normal operating conditions.
(iii) A “leak-free” system is one in which leakage is controlled so that it will not lead to a failure of the certification exhaust emission standards in-use.
(iv) The provisions of paragraphs (d)(16)(i) and (ii) do not apply to vehicles whose certification is carried over from the NLEV program or carried across from the Cal LEV I program.
(e) * * *
(6) The NMOG/NMHC and HCHO to NMHC ratios established according to § 86.1845-04.
(i) For exhaust emission testing for Tier 2 and interim non-Tier 2 vehicles, if approved by the Administrator in advance, manufacturers may submit exhaust emission test data generated under California test procedures to comply with any certification and in-use testing requirements under this subpart. The Administrator may require supporting information to establish that differences between California and Federal exhaust testing procedures and fuels will not produce significant differences in emission results. The Administrator may require that in-use testing be performed using Federal test fuels as specified in § 86.113-04(a)(1).
a. revising paragraph (a),
b. revising paragraph (c)(2), and
c. adding paragraph (f).
The revisions and additions read as follows:
(a)
(2) Unless otherwise approved by the Administrator, no emission measurements made under the requirements of this section may be adjusted by Reactivity Adjustment Factors (RAFs).
(3) Upon a manufacturer's written request, prior to in-use testing, that presents information to EPA regarding pre-conditioning procedures designed solely to remove the effects of high sulfur in gasoline from vehicles produced through the 2007 model year, EPA will consider allowing such procedures on a case-by-case basis. EPA's decision will apply to manufacturer in-use testing conducted under this section and to any in-use testing conducted by EPA.
(c) * * *
(2) Vehicle mileage:
(i) All test vehicles must have a minimum odometer mileage of 50,000 miles. At least one vehicle of each test group must have a minimum odometer mileage of 75 percent of the full useful life mileage. See § 86.1838-01(c)(2) for small volume manufacturer mileage requirements; or
(ii) For engine families certified for a useful life of 150,000 miles, at least one vehicle must have a minimum odometer mileage of 105,000 miles. See § 86.1838-01(c)(2) for small volume manufacturer mileage requirements.
(f)(1) A manufacturer may conduct in-use testing on a test group by measuring NMHC exhaust emissions rather than NMOG exhaust emissions. The measured NMHC exhaust emissions must be multiplied by the adjustment factor used for certification of the test group, or another adjustment factor acceptable to the Administrator, to determine the equivalent NMOG exhaust emission values for the test vehicle. The equivalent NMOG exhaust emission value must be used in place of the measured NMOG exhaust emission value in determining the exhaust NMOG results. The equivalent NMOG exhaust emission values must be compared to the NMOG exhaust emission standard from the emission bin to which the test group was certified.
(2) For flexible-fueled LDVs, LDTs and MDPVs certified to NMOG standards, the manufacturer may request from the Administrator the use of a methanol (M85) or ethanol (E85) NMOG exhaust emission to gasoline NMHC exhaust emission ratio which must be established during certification for each emission data vehicle for the applicable test group. The results must be submitted to the Administrator in the Part II application for certification. After approval by the Administrator, the measured gasoline NMHC exhaust emissions must be multiplied by the M85 or E85 NMOG to gasoline NMHC ratio submitted in the application for certification for the test group to determine the equivalent NMOG exhaust emission values for the test vehicle. The equivalent NMOG exhaust emission value must be used in place of the measured NMOG exhaust emission value in determining the exhaust NMOG results. The equivalent NMOG exhaust emission values must be compared to the NMOG exhaust emission standard from the vehicle emission standard bin to which the test group was certified.
(3) If the manufacturer measures NMOG it must also measure and report HCHO emissions. As an alternative to measuring the HCHO content, if the manufacturer measures NMHC as permitted in paragraph (f)(1) of this section, the Administrator may approve,
(a)
(2) Except for vehicles certified under the NLEV provisions of subpart R of this part or unless otherwise approved by the Administrator, no emission measurements made under the requirements of this section may be adjusted by Reactivity Adjustment Factors (RAFs).
(3) For purposes of this section, the term vehicle includes light-duty vehicles, light-duty trucks and medium-duty vehicles.
(4) Upon a manufacturer's written request, prior to in-use testing, that presents information to EPA regarding pre-conditioning procedures designed solely to remove the effects of high sulfur in gasoline from vehicles produced through the 2007 model year, EPA will consider allowing such procedures on a case-by-case basis. EPA's decision will apply to manufacturer in-use testing conducted under this section and to any in-use testing conducted by EPA.
(c) * * *
(7) For Tier 2 and interim non-Tier 2 vehicles, all certificates of conformity issued are conditional upon compliance with all provisions of §§ 86.1811-04, 86.1860-04, 86.1861-04 and 86.1862-04 both during and after model year production.
(i) Failure to meet the fleet average NO
(ii) Failure to comply fully with the prohibition against selling credits that it has not generated or that are not available, as specified in § 86.1861-04, will be considered to be a failure to satisfy the terms and conditions upon which the certificate(s) was (were) issued and the vehicles sold in violation of this prohibition will not be covered by the certificate(s).
(iii) Failure to comply fully with the phase-in requirements of § 86.1811-04, will be considered to be a failure to satisfy the terms and conditions upon which the certificate(s) was (were) issued and the vehicles sold which do not comply with Tier 2 or interim non-Tier 2 requirements, up to the number needed to comply, will not be covered by the certificate(s).
(iv) For paragraphs (c)(7)(i) through (iii) of this section:
(A) The manufacturer must bear the burden of establishing to the satisfaction of the Administrator that the terms and conditions upon which the certificate(s) was (were) issued were satisfied.
(B) For recall and warranty purposes, vehicles not covered by a certificate of conformity will continue to be held to the standards stated or referenced in the certificate that otherwise would have applied to the vehicles.
(a) The fleet average standards referred to in this section are the corporate fleet average standards for FTP exhaust NO
(b)(1) Each manufacturer must comply with the applicable fleet average NO
(2) During a phase-in year, the manufacturer must comply with the applicable fleet average NO
(c)(1)(i) Each manufacturer must separately compute the sales weighted averages of the individual NO
(ii) For model years up to and including 2008, manufacturers must compute separate NO
(2)(i) For model years up to and including 2008, if a manufacturer certifies its entire U.S. sales of Tier 2 or interim non-Tier 2 LDV/LLDTs or interim non-Tier 2 HLDT/MDPVs, to full useful life bins having NO
(ii) For model years after 2008, if a manufacturer certifies its entire U.S. sales of Tier 2 vehicles to full useful life bins having NO
(d) The sales weighted NO
(1) Showing that its sales weighted average NO
(2) If the sales weighted average is not at or below the applicable fleet average standard, by obtaining and applying sufficient Tier 2 NO
(i) Manufacturers may not use NMOG credits generated under the NLEV program in subpart R of this part to meet any Tier 2 or interim non-Tier 2 NO
(ii) Tier 2 NO
(iii) Interim non-Tier 2 NO
(iv) Interim non-Tier 2 NO
(e) (1) Manufacturers that cannot meet the requirements of paragraph (d) of this section, may carry forward a credit deficit for three model years, but must not carry such deficit into the fourth year. When applying credits to reduce or eliminate a deficit under the fleet average standard for interim LDV/LLDTs or interim HLDT/MDPVs, that has been carried forward into a year subsequent to its generation, a manufacturer may apply credits from Tier 2 LDV/LLDTs or Tier 2 HLDT/MDPVs, respectively, as well as from the appropriate group of interim vehicles. A manufacturer must not use interim credits to reduce or eliminate any NO
(2) A manufacturer carrying a credit deficit into the third year must generate or obtain credits to offset that deficit and apply them to the deficit at a rate of 1.2:1, (i.e. deficits carried into the third model year must be repaid with credits equal to 120 percent of the deficit).
(3) A manufacturer must not bank credits for future model years or trade credits to another manufacturer during a model year into which it has carried a deficit.
(f)
(i) Their Tier 2 LDV/LLDT and Tier 2 HLDT/MDPV fleet average NO
(ii) Their combined Tier 2 LDV/T and MDPV fleet average NO
(iii) Their interim non-Tier 2 LDV/LLDT fleet average NO
(iv) Their interim non-Tier 2 HLDT/MDPV fleet average NO
(2) The equation for computing fleet average NO
(3) The results of the calculation in paragraph (f)(2) of this section must be rounded as required by § 86.1837-01.
(4) When approved in advance by the Administrator, the numerator in the equation in paragraph (f)(2) of this section may be adjusted downward by the product of the number of HEVs from each NO
(g)
(2)(i) For any test group certified to the optional 15 year/150,000 mile useful life, the manufacturer may generate additional NO
(ii) The manufacturer must calculate these extra NO
(3) A manufacturer electing not to comply with applicable intermediate life standards as permitted under § 86.1811-04(c)(4) may not generate additional credits from vehicles certified to a useful life of 15 years/150,000 miles; except that, for bins where such intermediate life standards do not exist or are specifically deemed to be optional in § 86.1811-04(c)(4), the manufacturer may generate additional
(h)
(1) When computing the fleet average Tier 2 NO
(2) [Reserved]
44. Section 86.1861-04 is added to read as follows:
(a)
(2) Credits generated according to the calculation in paragraph (b)(1) of this section may be banked for future use or traded to another manufacturer.
(3) NO
(4) If a manufacturer calculates that it has negative credits (debits or a credit deficit) for a given model year, it must obtain sufficient credits, as required under § 86.1860-04(e)(2), from vehicles produced by itself or another manufacturer in a model year no later than the third model year following the model year for which it calculated the credit deficit. (Example: if a manufacturer calculates that it has a NO
(5) A small volume manufacturer that has opted not to meet all phase-in requirements as permitted under § 86.1811-04(k)(5), must:
(i) Demonstrate compliance or obtain appropriate credits to comply with the 0.30 g/mi. fleet average NO
(ii) Demonstrate compliance or obtain appropriate credits to comply with the 0.07 g/mi. fleet average NO
(iii) Demonstrate compliance or obtain appropriate credits to comply with the 0.20 g/mi. fleet average interim NO
(6)(i) Manufacturers may not use NO
(ii) Manufacturers may not use NMOG credits generated by vehicles certified to the NLEV requirements of subpart R of this part to comply with any NO
(iii) Manufacturers may not use NO
(iv) Manufacturers may not use NO
(v) Manufacturers may not use NO
(vi) Manufacturers may not use NO
(vii) Manufacturers may not use NO
(viii) Manufacturers may not use NO
(7) Manufacturers may bank Tier 2 NO
(8) There are no property rights associated with NO
(b)
(2) Where the result of the calculation in paragraph (b)(1) of this section is a negative number, the manufacturer must generate negative NO
(c)
(ii) Manufacturers may certify HLDT/MDPVs to the Tier 2 FTP exhaust standards in § 86.1811-04 for model years 2001-2007 in order to bank credits for use in the 2008 and later model years. Such vehicles must also meet applicable SFTP exhaust emission standards specified in § 86.1811-04.
(iii) This process is referred to as “early banking” and the resultant credits are referred to as ”early credits”. In order to bank early credits, a manufacturer must comply with all exhaust emission standards and requirements applicable to Tier 2 LDV/LLDTs and/or HLDT/MDPVs, as applicable, except as allowed under paragraph (c)(4) of this section.
(2) To generate early credits, a manufacturer must separately compute
(3) Early HLDT/MDPV credits may not be applied to LDV/LLDTs before the 2009 model year. Early LDV/LLDT credits may not be applied to HLDT/MDPVs before the 2009 model year.
(4) Manufacturers may generate early Tier 2 credits from LDVs, LDT1s and LDT2s that are certified to a full useful life of 100,000 miles, provided that the credits are prorated by a multiplicative factor of 0.833 (the quotient of 100,000/120,000). Where a manufacturer has both 100,000 and 120,000 mile full useful life vehicles for which it desires to bank early credits, it must compute the credits from each group of vehicles separately and then add them together.
(5) Manufacturers may bank early credits for later use to meet the Tier 2 fleet average NO
(6) Early credits must not be used to comply with the fleet average NO
(7) Nothing in this section prevents the use of the NMOG values of 2003 and earlier model year LDV/LLDTs from being used in calculations of the NMOG fleet average and subsequent NMOG credit generation, under subpart R of this part.
(d)
(e)
(2)(i) Failure to meet the requirements of paragraphs (a) through (d) of this section and of this paragraph (e), within the required timeframe for offsetting debits will be considered to be a failure to satisfy the conditions upon which the certificate(s) was issued and the individual noncomplying vehicles not covered by the certificate must be determined according to this section.
(ii) If debits are not offset within the specified time period, the number of vehicles not meeting the fleet average NO
(iii) EPA will determine the vehicles for which the condition on the certificate was not satisfied by designating vehicles in those test groups with the highest certification NO
(3) If a manufacturer ceases production of LDV/Ts and MDPVs or is purchased by, merges with or otherwise combines with another manufacturer, the manufacturer continues to be responsible for offsetting any debits outstanding within the required time period. Any failure to offset the debits will be considered to be a violation of paragraph (e)(1) of this section and may subject the manufacturer to an enforcement action for sale of vehicles not covered by a certificate, pursuant to paragraph (e)(2) of this section.
(4) For purposes of calculating the statute of limitations, a violation of the requirements of paragraph (e)(1) of this section, a failure to satisfy the conditions upon which a certificate(s) was issued and hence a sale of vehicles not covered by the certificate, all occur upon the expiration of the deadline for offsetting debits specified in paragraph (e)(1) of this section.
(f)
(2) A manufacturer may not sell credits that are not available for sale pursuant to the provisions in paragraphs (a)(2) and (a)(7) of this section.
(3) In the event of a negative credit balance resulting from a transaction, both the buyer and seller are liable, except in cases involving fraud. EPA may void
(4)(i) If a manufacturer transfers a credit that it has not generated pursuant to paragraph (b) of this section or acquired from another party, the manufacturer will be considered to have generated a debit in the model year that the manufacturer transferred the credit. The manufacturer must offset such debits by the deadline for the annual report for that same model year.
(ii) Failure to offset the debits within the required time period will be considered a failure to satisfy the conditions upon which the certificate(s) was issued and will be addressed pursuant to paragraph (e) of this section.
(g)
(1) Provisions for early banking under paragraph (c) of this section do not apply.
(2) The fleet average NO
(3) Interim non-Tier 2 NO
45. Section 86.1862-04 is added to read as follows:
(a)
(i) Model year;
(ii) Applicable fleet average NO
(iii) Fleet average NO
(iv) All values used in calculating the fleet average NO
(2) The manufacturer producing any LDV/Ts or MDPVs subject to the provisions in this subpart must establish, maintain, and retain the following information in adequately organized and indexed records for each LDV/T or MDPV subject to this subpart:
(i) Model year;
(ii) Applicable fleet average NO
(iii) EPA test group;
(iv) Assembly plant;
(v) Vehicle identification number;
(vi) NO
(vii) Information on the point of first sale, including the purchaser, city, and state.
(3) The manufacturer must retain all records required to be maintained under this section for a period of eight years from the due date for the annual report. Records may be retained as hard copy or reduced to microfilm, ADP diskettes, and so forth, depending on the manufacturer's record retention procedure; provided, that in every case all information contained in the hard copy is retained.
(4) Nothing in this section limits the Administrator's discretion to require the manufacturer to retain additional records or submit information not specifically required by this section.
(5) Pursuant to a request made by the Administrator, the manufacturer must submit to the Administrator the information that the manufacturer is required to retain.
(6) EPA may void
(b)
(2) When a manufacturer calculates compliance with the fleet average NO
(3) For each applicable fleet average NO
(i) Name of credit provider;
(ii) Name of credit recipient;
(iii) Date the transfer occurred;
(iv) Quantity of credits transferred; and
(v) Model year in which the credits were earned.
(4) Unless a manufacturer reports the data required by this section in the annual production report required under § 86.1844-01(e) and subsequent model year provisions, a manufacturer must submit an annual report for each model year after production ends for all affected vehicles and trucks produced by the manufacturer subject to the provisions of this subpart and no later than May 1 of the calendar year following the given model year. Annual reports must be submitted to: Director, Vehicle Programs and Compliance Division, U.S. Environmental Protection Agency, 2000 Traverwood, Ann Arbor, Michigan 48105.
(5) Failure by a manufacturer to submit the annual report in the specified time period for all vehicles and trucks subject to the provisions in this section is a violation of section 203(a)(1) of the Clean Air Act for each subject vehicle and truck produced by that manufacturer.
(6) If EPA or the manufacturer determines that a reporting error occurred on an annual report previously submitted to EPA, the manufacturer's credit or debit calculations will be recalculated. EPA may void erroneous credits, unless transferred, and must adjust erroneous debits. In the case of transferred erroneous credits, EPA must adjust the selling manufacturer's credit or debit balance to reflect the sale of such credits and any resulting generation of debits.
(c)
These estimates are projections for the guidance of potential applicants. The Department is not bound by any estimates in this notice.
States receiving grants under this program may use the grant funds to pay part or all of the cost of advanced placement test fees for low-income individuals who (1) are enrolled in an advanced placement class; and (2) plan to take an advanced placement test. In addition, SEAs in States in which no eligible low-income individual is required to pay more than a nominal fee to take advanced placement tests in core subjects may use grant funds for activities directly related to increasing (a) the enrollment of low-income individuals in advanced placement courses; (b) the participation of low-income individuals in advanced placement tests; and (c) the availability of advanced placement courses in schools serving high-poverty areas (hereinafter referred to as “section 810(d)(1) activities”). Examples of section 810(d)(1) activities may include, but are not limited to, projects that provide student access to advanced placement courses online, and professional development institutes designed to prepare teachers to teach advanced placement courses. An SEA may apply for funds under this program both to assist it in meeting the requirement that no eligible low-income student in the State be required to pay more than a nominal fee to take advanced placement tests in core subjects and for section 810(d)(1) activities.
(a)
To implement this priority, the Department intends to fund, at some level, all applications (1) meeting the minimum REQUIREMENTS FOR APPROVAL OF APPLICATIONS described in the application package; and (2) proposing to use grant funds for the purpose of paying part or all of the cost of advanced placement test fees on behalf of eligible low-income individuals in the State. For applications that propose to use grant funds to pay advanced placement test fees and to support section 810(d)(1) activities, the section of the application proposing to use grant funds for section 810(d)(1) activities will be evaluated based on the SELECTION CRITERIA described in the application package (
(b)
The Department intends to allocate approximately $4 million of the funds available under this program to States for the purpose of paying advanced placement test fees on behalf of eligible low-income individuals. The Department intends to allocate approximately $11 million to States to support section 810(d)(1) activities. In determining grant award amounts, the Department will consider, among other things, the number of children in the State eligible to be counted under section 1124(c) of the Elementary and Secondary Education Act of 1965, in relation to the number of such children in all States.
The Secretary uses the selection criteria published in 34 CFR 75.209 and 75.210 to evaluate the section of the application that proposes to use grant funds to support section 810(d)(1) activities. The application package includes the SELECTION CRITERIA and the points assigned to each criterion.
The Education Department General Administrative Regulations (EDGAR) in 34 CFR Parts 75, 77, 79, 80, 81, 82, 85, 86, and 99. Title VIII, Part B of the Higher Education Amendments of 1998 (1998 Amendments), 20 U.S.C. 1070a-11, note.
The following definitions and other provisions are taken from the Advanced Placement Incentive Program authorizing statute, in Title VIII, Part B of the 1998 Amendments. They are repeated in this application notice for the convenience of the applicant.
As used in this section:
(a) The term
To date, the Secretary has approved advanced placement tests administered by The College Board and International Baccalaureate Organisation. As part of the grant application process, applicants may request approval of tests from other educational entities that provide comparable programs of rigorous academic courses and testing through which students may earn college credit.
(b) The term
Under section 402A(g)(2) of the HEA, the term
The SEA shall disseminate information regarding the availability of test fee payments under this program to eligible individuals through secondary school teachers and guidance counselors (20 U.S.C. 1070a-11, note (b)).
Funds provided under this program must be used to supplement and not supplant other non-Federal funds that are available to assist low-income individuals in paying advanced placement test fees (20 U.S.C. 1070a-11, note (d)(2)).
For Applications or Information Contact: Frank B. Robinson, U.S. Department of Education, School Improvement Programs, 400 Maryland Avenue, SW., Room 3C153, Washington, DC 20202-6140. Telephone (202) 260-2669. Internet address: frank—robinson@ed.gov
Individuals who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 between 8 a.m. and 8 p.m., Eastern time, Monday through Friday.
Individuals with disabilities may obtain this document in an alternate format (
You may view this document, as well as all other Department of Education documents published in the
To use the PDF, you must have the Adobe Acrobat Reader Program with Search, which is available free at either of the previous sites. If you have questions about using the PDF, call the U.S. Government Printing Office toll free at 1-888-293-6498; or in the Washington, DC area at (202) 512-1530.
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20 U.S.C. 1070a-11, note.
1-101. It is the policy of the Government of the United States to provide equal employment opportunity in Federal employment for all qualified persons and to prohibit discrimination against employees based on protected genetic information, or information about a request for or the receipt of genetic services. This policy of equal opportunity applies to every aspect of Federal employment.
1-102. The head of each Executive department and agency shall extend the policy set forth in section 1-101 to all its employees covered by section 717 of Title VII of the Civil Rights Act of 1964, as amended (42 U.S.C. 2000e-16).
1-103. Executive departments and agencies shall carry out the provisions of this order to the extent permitted by law and consistent with their statutory and regulatory authorities, and their enforcement mechanisms. The Equal Employment Opportunity Commission shall be responsible for coordinating the policy of the Government of the United States to prohibit discrimination against employees in Federal employment based on protected genetic information, or information about a request for or the receipt of genetic services.
1-201. Definitions.
1-202. In discharging their responsibilities under this order, departments and agencies shall implement the following nondiscrimination requirements.
1-301. The following exceptions shall apply to the nondiscrimination requirements set forth in section 1-202.
1-401. The head of each department and agency shall take appropriate action to disseminate this policy and, to this end, shall designate a high level official responsible for carrying out its responsibilities under this order.
1-402. Nothing in this order shall be construed to:
1-403. This order clarifies and makes uniform Administration policy and does not create any right or benefit, substantive or procedural, enforceable at law by a party against the United States, its officers or employees, or any other person.