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Agricultural Marketing Service, USDA.
Final rule.
The Department of Agriculture (USDA) is adopting, as a final rule, an interim final rule establishing final free and restricted percentages for domestic inshell hazelnuts for the 2006-2007 marketing year under the Federal marketing order for hazelnuts grown in Oregon and Washington. This rule continues in effect the final free and restricted percentages of 8.2840 percent and 91.7160 percent, respectively. The percentages allocate the quantity of domestically produced hazelnuts which may be marketed in the domestic inshell market (free) and the quantity of domestically produced hazelnuts that must be disposed of in outlets approved by the Board (restricted). Volume regulation is intended to stabilize the supply of domestic inshell hazelnuts to meet the limited domestic demand for such hazelnuts with the goal of providing producers with reasonable returns. This rule was recommended unanimously by the Hazelnut Marketing Board (Board), which is the agency responsible for local administration of the marketing order.
Barry Broadbent or Gary Olson, Northwest Marketing Field Office, Marketing Order Administration Branch, Fruit and Vegetable Programs, AMS, USDA, 1220 SW Third Avenue, Suite 385, Portland, OR 97204; Telephone: (503) 326-2724, Fax: (503) 326-7440, or e-mail:
Small businesses may request information on complying with this regulation by contacting Jay Guerber, Marketing Order Administration Branch, Fruit and Vegetable Programs, AMS, USDA, 1400 Independence Avenue, SW., STOP 0237, Washington, DC 20250-0237; Telephone: (202) 720-2491, Fax: (202) 720-8938, or e-mail:
This rule is issued under Marketing Agreement No. 115 and Marketing Order No. 982, both as amended (7 CFR part 982), regulating the handling of hazelnuts grown in Oregon and Washington, hereinafter referred to as the “order.” The 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.”
USDA is issuing this rule in conformance with Executive Order 12866.
This rule has been reviewed under Executive Order 12988, Civil Justice Reform. It is intended that this action apply to all merchantable hazelnuts handled during the 2006-2007 marketing year beginning July 1, 2006. This action applies to all 2006-2007 marketing year restricted hazelnuts until they are properly disposed of in accordance with marketing order requirements. 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 USDA 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, USDA 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 USDA's ruling on the petition, provided an action is filed not later than 20 days after the date of the entry of the ruling.
This rule continues in effect free and restricted percentages which allocate the quantity of domestically produced hazelnuts which may be marketed in domestic inshell markets (free) and hazelnuts which must be exported, shelled, or otherwise disposed of by handlers (restricted). The Board met and, after determining that volume regulation would tend to effectuate the declared policy of the Act, developed a marketing policy to be employed for the duration of the 2006-2007 marketing year. Volume regulation is intended to stabilize the supply of domestic inshell hazelnuts to meet the limited domestic demand for such hazelnuts with the goal of providing producers with reasonable returns. Based on an estimate of the domestic inshell trade demand and total supply of domestically produced hazelnuts available for the 2006-2007 marketing year, the Board voted unanimously at their November 15, 2006, meeting to recommend to USDA that the final free and restricted percentages for the 2006-2007 marketing year be established at 8.2840 percent and 91.7160 percent, respectively.
The Board's authority to recommend volume regulation and use computations to determine the allocation of hazelnuts to individual markets is specified in § 982.40 of the order. Under the order's provisions, free and restricted market allocations of hazelnuts are expressed as percentages of the total hazelnut supply subject to regulation. The percentages are derived by dividing the estimated domestic inshell trade demand (computed by formula) by the Board's estimate of the total domestically produced supply of hazelnuts that are expected to be available over the course of the marketing year.
Inshell trade demand, the key component of the marketing policy, is
As required by the order, prior to September 20 of each marketing year, the Board meets to establish its marketing policy for that year. If the Board determines that volume control would tend to effectuate the declared policy of the Act, the Board then follows a procedure, specified by the order, to compute and announce preliminary free and restricted percentages. The preliminary free percentage releases 80 percent of the adjusted inshell trade demand that handlers may ship to the domestic market. The purpose of releasing only 80 percent of the inshell trade demand under the preliminary stage of regulation is to guard against any potential underestimate of crop size. The preliminary free percentage is expressed as a percentage of the total hazelnut supply subject to regulation, where total supply is the sum of the estimated crop production less the three-year average disappearance plus the undeclared carry-in from the previous marketing year.
On August 22, 2006, the National Agricultural Statistics Service (NASS) released an estimate of 2006 hazelnut production for the Oregon and Washington area at 41,000 dry orchard-run tons. NASS uses an objective yield survey method to estimate hazelnut production which has historically been very accurate.
On August 24, 2006, the Board met for the purpose of (1) Determining if volume control regulation would tend to effectuate the declared policy of the Act; (2) estimating the total available supply and the domestic inshell trade demand for hazelnuts; (3) establishing preliminary free and restricted marketing percentages for the 2006-2007 marketing year; and (4) authorizing market outlets for restricted hazelnuts.
After discussion, the Board unanimously determined that volume regulation is necessary to effectively market the industry's 2006 crop and would tend to effectuate the declared policy of the Act. The determination was based on (1) The large size of the 2006 hazelnut crop; (2) the inability of the domestic inshell market to absorb such a large crop; (3) the projected record-setting world hazelnut crop and the probability of an oversupplied world market; and (4) the average price paid to Oregon-Washington growers has not exceeded the parity price in any one of the past 18 years.
The Board then estimated the total available supply for the 2006 crop year to be 39,234 tons. The Board arrived at that quantity by using the crop estimate compiled by NASS (41,000 tons) and then adjusting that estimate to account for disappearance and carry-in. The order requires the Board to reduce the crop estimate by the average disappearance over the preceding three years (1,792 tons) and to increase it by the amount of undeclared carry-in from previous years' production (26 tons).
In the calculation, disappearance is defined as the difference between the estimated orchard-run production and the actual supply of merchantable product available for sale by handlers. Disappearance can consist of (1) Unharvested hazelnuts; (2) culled product (nuts that are delivered to handlers but later discarded); (3) product used on the farm, sold locally, or otherwise disposed of by producers; and (4) statistical error in the orchard-run production estimate.
Undeclared carry-in is defined as hazelnuts that were produced in a previous marketing year but were not subject to regulation because they were not shipped during that marketing year. Undeclared carry-in is subject to regulation during the current marketing year and is accounted for as such by the Board.
Additionally, the Board estimated domestic inshell trade demand for the 2006-2007 marketing year to be 3,067 tons. The Board arrived at this estimate by taking the average of the domestic inshell trade acquisitions for the 2002-2005 marketing years (2,775 tons) and then reducing that quantity by the declared carry-in from last year's crop (124 tons). The trade acquisition data for the 2005-2006 marketing year was omitted from the Board's calculations, as allowed by the order, after it was determined to be abnormal due to crop and marketing conditions.
The declared carry-in represents product regulated under the order during a preceding marketing year but not shipped during that year. This inventory must be accounted for when estimating the quantity of product to make available to adequately supply the market.
After establishing estimates for total available hazelnut supply and domestic inshell trade demand, the Board used those estimates to compute and announce preliminary free and restricted percentages of 5.4055 percent and 94.5945 percent, respectively. The Board computed the preliminary free percentage by multiplying the adjusted inshell trade demand by 80 percent and dividing the result by the estimate of the total available supply subject to regulation (2,651 tons × 80 percent/39,234 tons = 5.4055 percent). The preliminary free percentage initially released 2,121 tons of hazelnuts from the 2006-2007 supply for domestic inshell use. The Board authorized the preliminary restricted percentage (37,113 tons) to be exported or shelled for the domestic kernel markets.
Under the order, the Board must meet again on or before November 15 to review and revise the preliminary estimate of the total available supply of hazelnuts and to recommend interim final and final free and restricted percentages. Initially, when establishing preliminary free and restricted percentages, the Board utilizes a pre-harvest objective yield survey, compiled by NASS on behalf of the Board, to estimate the upcoming crop size. After the hazelnut harvest has concluded, usually sometime in October, information is available directly from handlers to more accurately estimate crop size. The Board may use this information to amend their preliminary estimate of total available supply before calculating the interim final and final percentages.
Interim final percentages are calculated in the same way as the preliminary percentages but release 100 percent of the inshell trade demand, effectively releasing the additional 20 percent held back at the preliminary stage. Final free and restricted percentages may release up to an additional 15 percent of the average trade acquisitions of inshell hazelnuts for desirable carryout, to provide an adequate carryover of product into the following season. The order requires that final free and restricted percentages be effective 30 days prior to the end of the marketing year, or earlier, if recommended by the Board and approved by USDA. The Board is allowed to combine the interim final and the final stages of the marketing policy, if marketing conditions so warrant, by recommending final
The Board met on November 15, 2006, and reviewed and approved an amended marketing policy and recommended the establishment of final free and restricted percentages. During the meeting, the Board revised the crop estimate in the marketing policy to 38,688 tons (from 41,000 tons), which reflects the results of post-harvest handler survey information compiled by the Board. In addition, the Board decided that market conditions were such that the immediate release of an additional 15 percent of the three-year average trade acquisitions to allow for desirable carryout will not adversely affect the 2006-2007 domestic inshell market. Final percentages were recommended at 8.2840 percent free and 91.1760 percent restricted. The final free percentage releases 3,067 tons of inshell hazelnuts from the 2006-2007 supply for domestic use, which includes 416 tons for desirable carryout. Accordingly, since the final percentages were recommended for immediate release, no recommendations for interim final free and restricted percentages were necessary.
The final marketing percentages are based on the Board's final production estimate and the following supply and demand information for the 2006-2007 marketing year:
In addition to complying with the provisions of the order, the Board also considered USDA's 1982 “Guidelines for Fruit, Vegetable, and Specialty Crop Marketing Orders” (Guidelines) when making its computations in the marketing policy. This volume control regulation provides a method to collectively limit the supply of inshell hazelnuts available for sale in domestic markets. The Guidelines provide that the domestic inshell market has available a quantity equal to 110 percent of prior years' shipments before allocating supplies for the export inshell, export kernel, and domestic kernel markets. This provides for a plentiful supply of inshell hazelnuts for consumers and for market expansion, while retaining the mechanism for dealing with oversupply situations. The established final percentages make available approximately 416 additional tons to encourage increased sales. The total free supply for the 2006-2007 marketing year is estimated to be 3,067 tons of hazelnuts, which is 127 percent of the average of the last three prior years' sales and exceeds the goal of the Guidelines.
Pursuant to requirements set forth in the Regulatory Flexibility Act (RFA), the Agricultural Marketing Service (AMS) has considered the economic impact of this action on small entities. Accordingly, AMS has prepared this final 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 the 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.
Small agricultural producers are defined by the Small Business Administration (13 CFR 121.201) as those having annual receipts of less than $750,000, and small agricultural service firms are defined as those having annual receipts of less than $6,500,000. There are approximately 700 producers of hazelnuts in the production area and approximately 18 handlers subject to regulation under the order. Using statistics compiled by NASS, the average value of production received by producers in 2004 and 2005 was $57,912,000. Using those estimates, the average annual hazelnut revenue per producer would be approximately $82,700. The level of sales of other crops by hazelnut producers is not known. In addition, based on Board records, about 83 percent of the handlers ship under $6,500,000 worth of hazelnuts on an annual basis. In view of the foregoing, it can be concluded that the majority of hazelnut producers and handlers may be classified as small entities.
Board meetings are widely publicized in advance of the meetings and are held in a location central to the production area. The meetings are open to all industry members and other interested persons who are encouraged to participate in the deliberations and voice their opinions on topics under discussion. Thus, Board recommendations can be considered to represent the interests of small business entities in the industry.
Currently, U.S. hazelnut production is allocated among three main market
The inshell hazelnut market can be characterized as having limited and inelastic demand with a very short primary marketing period. On average, 79 percent of domestic inshell hazelnut shipments occur between October 1 and November 30, primarily to supply holiday nut demand. The inshell market is, therefore, prone to oversupply and correspondingly low grower prices in the absence of supply restrictions. This volume control regulation provides a method for the U.S. hazelnut industry to limit the supply of domestic inshell hazelnuts available for sale in the continental U.S. and thereby mitigate market oversupply conditions.
Many years of marketing experience led to the development of the current volume control procedures. These procedures have helped the industry solve its marketing problems by keeping inshell supplies in balance with domestic needs. Volume controls ensure that the domestic inshell market is fully supplied while protecting the market from the negative effects of oversupply.
Although the domestic inshell market is a relatively small portion of total hazelnut sales (averaging 10 percent of total shipments for 1996-2005), it remains a profitable market segment. The volume control provisions of the marketing order are designed to avoid oversupplying this particular market segment, because that would likely lead to substantially lower grower prices. The other market segments, export inshell and kernels, are expected to continue to provide good outlets for U.S. hazelnut production into the future. Adverse climatic conditions that negatively impacted hazelnut production in the other hazelnut producing regions of the world in 2004 and 2005 have corrected and the total world supply in 2006-2007 is predicted to increase dramatically. Product prices in the world market have trended downward in the expectation of the greater supply. While the U.S. hazelnut industry continues to experience high demand for their large sized and high quality product, the prices that producers receive are tied to the global market. In light of the anticipated world oversupply situation, regulation of the domestic inshell market is important to the U.S. hazelnut industry to insulate that specialty market from the supply related challenges of the world hazelnut market.
In Oregon and Washington, high hazelnut production years typically follow low production years (a historically consistent pattern). The 2005 crop of 27,600 tons was 16 percent below the 32,685 ton average for the 1995-2004 period, while the preliminary NASS estimate for 2006 is 25 percent higher. The lowest production (15,000 tons in 1998) and highest production (49,500 tons in 2001) were 47 and 151 percent, respectively, of the 10 year average.
This cyclical trait also leads to an inversely corresponding cyclical price pattern for hazelnuts. Grower price, however, does not fluctuate to the extent of production. The lower level of variability of price versus the variability of production provides an illustration of the order's price-stabilizing impact. The coefficient of variation (a standard statistical measure of variability; “CV”) for hazelnut production over the most recent 10-year period is 0.36. In contrast, the coefficient of variation for hazelnut grower prices over the same period is 0.19, about half of the CV for production. The lower level of variability of price versus the variability of production provides an illustration of the order's price-stabilizing impact.
Comparing grower revenue to cost is useful in highlighting the impact on growers of recent product and price levels. A recent hazelnut production cost study from Oregon State University estimated cost-of-production per acre to be approximately $1,340 for a typical 100-acre hazelnut enterprise. Average grower revenue per bearing acre (based on NASS acreage and value of production data) equaled or exceeded that typical cost level less than half the time from 1995 to 2004. Average grower revenue was below typical costs in the other years. While crop size has fluctuated, volume regulations contribute to orderly marketing and market stability by moderating the variation in returns for all producers and handlers, both large and small.
While the level of benefits of this rulemaking is difficult to quantify, the stabilizing effects of volume regulation impact both small and large handlers positively by helping them maintain and expand markets even though hazelnut supplies fluctuate widely from season to season. This regulation provides equitable allotment of the most profitable market, the domestic inshell market. That market is available to all handlers, regardless of size.
As an alternative to this regulation, the Board discussed not regulating the marketing of the 2006 hazelnut crop. However, without any regulation in effect, the Board believes that the industry would tend to oversupply the inshell domestic market. The 2006 hazelnut crop is larger than last year's crop and 22 percent above the ten-year average. The unregulated release of 38,688 tons on the domestic inshell market could easily oversupply the small, but lucrative domestic inshell market. The Board believes that any oversupply would completely disrupt the market, causing producer returns to decrease dramatically.
Section 982.40 of the order establishes a procedure and computations for the Board to follow in recommending to USDA establishment of preliminary, interim final, and final percentages of hazelnuts to be released to the free and restricted markets each marketing year. The program results in a plentiful supply of hazelnuts for consumers and for market expansion while retaining the mechanism for dealing with oversupply situations.
Hazelnuts produced under the order comprise virtually all of the hazelnuts produced in the U.S. This production represents, on average, less than 2 percent of total U.S. production of all tree nuts, and less than 7 percent of the world's hazelnut production.
Last season, 85 percent of the domestically produced hazelnut kernels were marketed in the domestic market and 15 percent were exported. Domestically produced kernels generally command a higher price in the domestic market than imported kernels. The industry is continuing its efforts to develop and expand other markets with emphasis on the domestic kernel market. Small business entities, both producers and handlers, benefit from the expansion efforts resulting from this program.
Inshell hazelnuts produced under the order compete well in export markets because of their high quality. Based on Board statistics, Europe has historically been the primary export market for U.S. produced inshell hazelnuts. Shipments have also been relatively consistent, not varying much from the 10 year average of 4,958 tons. Recent years, though, have seen a significant increase in export destinations. Last season, inshell shipments to Europe totaled 4,622 tons, representing just 38 percent of exports, with the largest share going to Germany. Inshell shipments to Southwest Pacific countries, and Hong Kong in particular, have increased dramatically in the past
There are some reporting, recordkeeping, and other compliance requirements under the order. The reporting and recordkeeping burdens are necessary for compliance purposes and for developing statistical data for maintenance of the program. The information collection requirements are currently approved by the Office of Management and Budget under OMB No. 0581-0178, Vegetable and Specialty Crops. The forms require information which is readily available from handler records and which can be provided without data processing equipment or trained statistical staff. As with all Federal marketing order programs, reports and forms are periodically reviewed to reduce information requirements and duplication by industry and public sector agencies. This rule does not change those requirements.
The AMS is committed to complying with the E-Government Act, to promote the use of the Internet and other information technologies to provide increased opportunities for citizen access to Government information and services, and for other purposes.
In addition, USDA has not identified any relevant Federal rules that duplicate, overlap, or conflict with this rule.
Further, the Board's meetings were widely publicized throughout the hazelnut industry and all interested persons were invited to attend the meetings and participate in Board deliberations. Like all Board meetings, those held on August 24 and November 15, 2006, were public meetings and all entities, both large and small, were able to express their views on this issue.
An interim final rule concerning this action was published in the
A small business guide on complying with fruit, vegetable, and specialty crop marketing agreements and orders may be viewed at:
After consideration of all relevant material presented, including the information and recommendation submitted by the Board and other available information, it is hereby found that finalizing the interim final rule, without change, as published in the
Filberts, Hazelnuts, Marketing agreements, Nuts, Reporting and recordkeeping requirements.
Federal Aviation Administration (FAA), Department of Transportation (DOT).
Final rule.
We are adopting a new airworthiness directive (AD) for the products listed above. This AD results from mandatory continuing airworthiness information (MCAI) issued by an airworthiness authority of another country to identify and correct an unsafe condition on an aviation product. The MCAI describes the unsafe condition as un-damped extension of the main landing gear (MLG), potentially leading to loss of side stay integrity and then MLG collapse. We are issuing this AD to require actions to correct the unsafe condition on these products.
This AD becomes effective June 5, 2007.
The Director of the Federal Register approved the incorporation by reference of certain publications listed in this AD as of June 5, 2007.
You may examine the AD docket on the Internet at
Tim Backman, Aerospace Engineer, International Branch, ANM-116, FAA, Transport Airplane Directorate, 1601 Lind Avenue, SW., Renton, Washington 98057-3356; telephone (425) 227-2797; fax (425) 227-1149.
The FAA is implementing a new process for streamlining the issuance of ADs related to MCAI. This streamlined process will allow us to adopt MCAI safety requirements in a more efficient manner and will reduce safety risks to the public. This process continues to allow all FAA AD issuance processes to meet legal, economic, Administrative Procedure Act, and
This AD references the MCAI and related service information that we considered in forming the engineering basis to correct the unsafe condition. The AD contains text copied from the MCAI and for this reason might not follow our plain language principles.
We issued a notice of proposed rulemaking (NPRM) to amend 14 CFR part 39 to include an AD that would apply to the specified products. That NPRM was published in the
We gave the public the opportunity to participate in developing this AD. We received no comments on the NPRM or on the determination of the cost to the public.
We reviewed the available data and determined that air safety and the public interest require adopting the AD as proposed.
We have reviewed the MCAI and related service information and, in general, agree with their substance. But we might have found it necessary to use different words from those in the MCAI to ensure the AD is clear for U.S. operators and is enforceable in a U.S. court of law. In making these changes, we do not intend to differ substantively from the information provided in the MCAI and related service information.
We might also have required different actions in this AD from those in the MCAI in order to follow our FAA policies. Any such differences are described in a separate paragraph of the AD. These requirements, if any, take precedence over the actions copied from the MCAI.
We estimate that this AD will affect 28 products of U.S. registry. We also estimate that it will take about 10 work-hours per product to comply with this AD. The average labor rate is $80 per work-hour. Required parts will cost about $0 per product. Where the service information lists required parts costs that are covered under warranty, we have assumed that there will be no charge for these parts. As we do not control warranty coverage for affected parties, some parties may incur costs higher than estimated here. Based on these figures, we estimate the cost of this AD to the U.S. operators to be $22,400, or $800 per product.
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs,” describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We determined that this AD will not have federalism implications under Executive Order 13132. This AD 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.
For the reasons discussed above, I certify that this AD:
(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) 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.
We prepared a regulatory evaluation of the estimated costs to comply with this AD and placed it in the AD Docket.
You may examine the AD docket on the Internet at
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.
49 U.S.C. 106(g), 40113, 44701.
(a) This airworthiness directive (AD) becomes effective June 5, 2007.
(b) None.
(c) This AD applies to Airbus Model A330 airplanes, and Model A340-200 and -300 series airplanes, certificated in any category; all serial numbers fitted with MLG (main landing gear) retraction link Part Number (PN) 201489311 (LH (left-hand) side) or PN 201489312 (RH (right-hand) side).
(d) The MCAI states that during full-scale fatigue tests, the retraction link failed on the latest growth production standard MLG (main landing gear) prior to its expected life limit. Investigations confirm that the root cause of this premature fracture is due to high lug stress. The retraction link is included in the ALS (Airworthiness Limitation section) Part 1—Safe Life Airworthiness Limitation Item—and currently limited to 35,200 flight cycles (FC). Its fracture causes un-damped extension of the MLG, potentially leading to loss of side stay integrity and then MLG collapse, which constitutes an unsafe condition. The aim of the MCAI is to mandate the reduced retraction link life limit and replacement of any retraction link that has exceeded this new limit.
(e) Unless already done, do the following actions.
(1) Prior to the accumulation of 8,300 total landings on the retraction link assembly or within 39 days after the effective date of this AD, whichever occurs later, replace the retraction link assembly in accordance with the instructions defined in Airbus All Operators Telex A330-32A3208, dated October 18, 2006; or Airbus All Operators Telex A340-32A4252, dated October 18, 2006; as applicable.
(2) Within 39 days after the effective date of this AD, report to Airbus the life accumulation information of each retraction link assembly affected by this AD in accordance with Airbus All Operators Telex A330-32A3208, dated October 18, 2006; or Airbus All Operators Telex A340-32A4252, dated October 18, 2006; as applicable.
This reduced life limit will be incorporated within the next revision of the Airbus A330/A340 ALS Part 1.
(f) The following provisions also apply to this AD:
(1)
(2)
(3)
(g) Refer to MCAI European Aviation Safety Agency Emergency Airworthiness Directive 2006-0324-E, dated October 20, 2006; and Airbus All Operators Telex A330-32A3208, dated October 18, 2006; and Airbus All Operators Telex A340-32A4252, dated October 18, 2006, for related information.
(h) You must use Airbus All Operators Telex A330-32A3208, dated October 18, 2006; or Airbus All Operators Telex A340-32A4252, dated October 18, 2006; as applicable, to do the actions required by this AD, unless the AD specifies otherwise.
(1) The Director of the Federal Register approved the incorporation by reference of this service information under 5 U.S.C. 552(a) and 1 CFR part 51.
(2) For service information identified in this AD, contact Airbus, 1 Rond Point Maurice Bellonte, 31707 Blagnac Cedex, France.
(3) You may review copies at the FAA, Transport Airplane Directorate, 1601 Lind Avenue, SW., Renton, Washington; or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to:
Federal Aviation Administration (FAA), DOT.
Direct final rule; request for comments.
This action amends Title 14 Code of Federal regulations, part 71 (14 CFR 71) by modify Class E airspace at Hugoton Municipal Airport, KS. Standard Instrument Approach Procedures have been developed for Hugoton Municipal Airport, KS. Additional controlled airspace extending upward from the surface and upward from 700 feet above the surface of the earth is needed to contain aircraft executing these approaches. This action increases the area of the existing controlled airspace for Hugoton Municipal Airport, KS.
This direct final rule is effective on 0901 UTC, August 30, 2007. The Director of the Federal Register approves this incorporation by reference action under 1 CFR Part 51, subject to the annual revision of FAA Order 7400.9 and publication of conforming amendments. Comments for inclusion in the Rules Docket must be received on or before June 1, 2007.
Send comments on this proposal to the Docket Management System, U.S. Department of Transportation, Room Plaza 401, 400 Seventh Street, SW., Washington, DC 20590-0001. You must identify the docket number FAA-2007-27838/Airspace Docket No. 07-ACE-6, at the beginning of your comments. You may also submit comments on the Internet at
Grant Nichols, System Support, DOT Regional Headquarters Building, Federal Aviation Administration, 901 Locust, Kansas City, MO 64106; telephone: (816) 329-2522.
This amendment to 14 CFR 71 modifies the Class E airspace area at Hugoton Municipal Airport, KS. The radius of the Class E airspace area extending upward from 700 feet or more above the surface of the earth is expanded from within a 6.5-mile radius to within a 7.2-mile radius of the airport. This modification brings the legal description of the Hugoton Municipal Airport, KS Class E5 airspace area into compliance with FAA Orders 7400.2F and 8260.19C. Class E airspace areas extending upward from 700 feet or more above the surface of the earth are published in Paragraph 6005 of FAA Order 7400.9P, Airspace Designations and Reporting Points, dated September 1, 2006, and effective September 15, 2006, which is incorporated by reference in 14 CFR 71.1. of the same order. The Class E airspace designations listed in this document would be published subsequently in the Order.
The FAA anticipates that this regulation will not result in adverse or negative comment and, therefore, is issuing it as a direct final rule. Previous actions of this nature have not been controversial and have not resulted in adverse comments or objections. Unless a written adverse or negative comment or a written notice of intent to submit an adverse or negative comment is received within the comment period, the regulation will become effective on the date specified above. After the close of the comment period, the FAA will publish a document in the
Interested parties are invited to participate in this rulemaking by submitting such written data, views, or arguments, as they may desire. Comments that provide the factual basis supporting the views and suggestions presented are particularly helpful in developing reasoned regulatory decisions on the proposal. Comments are specifically invited on the overall regulatory, aeronautical, economic, environmental, and energy-related aspects of the proposal. Communications should identify both document numbers and be submitted in
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.
The FAA has determined that this regulation is noncontroversial and unlikely to result in adverse or negative comments. For the reasons discussed in the preamble, I certify that this regulation (1) Is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under Department of Transportation (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.
This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of the airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority since it contains aircraft executing instrument approach procedures to Hugoton Municipal Airport, KS.
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 700 feet above the surface within a 7.2-mile radius of Hugoton Municipal Airport and within 2.6 miles each side of the 199° bearing from the Hugton NDB extending to 7 miles south of the airport.
Federal Aviation Administration (FAA), DOT.
Direct final rule; request for comments.
This action amends Title 14 Code of Federal Regulations, part 71 (14 CFR 71) by modifying Class E airspace at Bolivar Municipal Airport, MO. Standard Instrument Approach Procedures have been developed for Bolivar Municipal Airport, MO. Additional controlled airspace extending upward from the surface and upward from 700 feet above the surface of the earth is needed to contain aircraft executing these approaches. This action increases the area of the existing controlled airspace for Bolivar Municipal Airport, MO.
This direct final rule is effective on 0901 UTC, August 30, 2007. The Director of the Federal Register approves this incorporation by reference action under 1 CFR Part 51, subject to the annual revision of FAA Order 7400.9 and publication of conforming amendments. Comments for inclusion in the Rules Docket must be received on or before June 1, 2007.
Send comments on this proposal to the Docket Management System, U.S. Department of Transportation, Room Plaza 401, Seventh Street, SW., Washington, DC 20509-0001. You must identify the docket number FAA-2007-27837/Airspace Docket No. 07-ACE-5, at the beginning of your comments. You may also submit comments on the Internet at
Grant Nichols, System Support, DOT Regional Headquarters Building, Federal Aviation Administration, 901 Locust, Kansas City, MO 64106; telephone: (816) 329-2522.
This amendment to 14 CFR 71 modifies the Class E airspace area at Bolivar Municipal Airport, MO. The radius of the Class E airspace area extending upward from 700 feet or more above the surface of the earth is expanded from within a 6.3-mile radius to within a 7.2-mile radius of the airport. This modification brings the legal description of the Bolivar Municipal Airport, MO Class E5 airspace area into compliance with FAA Orders 7400.2F and 8260.19C. Class E airspace areas extending upward from 700 feet or more above the surface of the earth are published in Paragraph 6005 of FAA Order 7400.9P, Airspace Designations and Reporting Points, dated September 1, 2006, and effective September 15, 2006, which is incorporated by reference in 14 CFR 71.1. of the same order. The Class E airspace designations listed in this document would be published subsequently in the Order.
The FAA anticipates that this regulation will not result in adverse or negative comment and, therefore, is issuing it as a direct final rule. Previous actions of this nature have not been
Interested parties are invited to participate in this rulemaking by submitting such written data, views, or arguments, as they may desire. Comments that provide the factual basis supporting the views and suggestions presented are particularly helpful in developing reasoned regulatory decisions on the proposal. Comments are specifically invited on the overall regulatory, aeronautical, economic, environmental, and energy-related aspects of the proposal. Communications should identify both docket numbers and be submitted in triplicate to the address listed above. Commenters wishing the FAA to acknowledge receipt of their comments on this notice must submit with those comments a self-addressed, stamped postcard on which the following statement if made: “Comments to Docket No. FAA-2006-27837/Airspace Docket No. 07-ACE-5.” The postcard will be date/time stamped and returned to the commenter.
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.
The FAA has determined that this regulation is noncontroversial and unlikely to result in adverse or negative comments. For the reasons discussed in the preamble, I certify that this regulation (1) Is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under Department of Transportation (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.
This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of the airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority since it contains aircraft executing instrument approach procedures to Bolivar Municipal Airport, MO.
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 700 feet above the surface within a 7.2-mile radius of the Bolivar Municipal Airport.
Federal Aviation Administration (FAA), DOT.
Final rule.
This amendment establishes, amends, suspends, or revokes Standard Instrument Approach Procedures (SIAPs) and/or Weather Takeoff Minimums for operations at certain airports. These regulatory actions are needed because of the adoption of new or revised criteria, or because of changes occurring in the National Airspace System, such as the commissioning of new navigational facilities, addition of new obstacles, or changes in air traffic requirements. These changes are designed to provide safe and efficient use of the navigable airspace and to promote safe flight operations under instrument flight rules at the affected airports.
This rule is effective May 1, 2007. The compliance date for each SIAP and/or Weather Takeoff Minimums is specified in the amendatory provisions.
The incorporation by reference of certain publications listed in the regulations is approved by the Director of the Federal Register as of May 1, 2007.
Availability of matters incorporated by reference in the amendment is as follows:
1. FAA Rules Docket, FAA Headquarters Building, 800 Independence Avenue, SW., Washington, DC 20591;
2. The FAA Regional Office of the region in which the affected airport is located;
3. The National Flight Procedures Office, 6500 South MacArthur Blvd., Oklahoma City, OK 73169 or,
4. The National Archives and Records Administration (NARA). For
1. FAA Public Inquiry Center (APA-200), FAA Headquarters Building, 800 Independence Avenue, SW., Washington, DC 20591; or
2. The FAA Regional Office of the region in which the affected airport is located.
Donald P. Pate, Flight Procedure Standards Branch (AFS-420), Flight Technologies and Programs Division, Flight Standards Service, Federal Aviation Administration, Mike Monroney Aeronautical Center, 6500 South MacArthur Blvd. Oklahoma City, OK. 73169 (Mail Address: P.O. Box 25082 Oklahoma City, OK. 73125) telephone: (405) 954-4164.
This amendment to Title 14 of the Code of Federal Regulations, Part 97 (14 CFR part 97), establishes, amends, suspends, or revokes SIAPs and/or Weather Takeoff Minimums. The complete regulatory description of each SIAP and/or Weather Takeoff Minimums is contained in official FAA form documents which are incorporated by reference in this amendment under 5 U.S.C. 552(a), 1 CFR part 51, and 14 CFR part 97.20. The applicable FAA Forms are identified as FAA Forms 8260-3, 8260-4, 8260-5 and 8260-15A. Materials incorporated by reference are available for examination or purchase as stated above.
The large number of SIAPs and/or Weather Takeoff Minimums, their complex nature, and the need for a special format make their verbatim publication in the
This amendment to 14 CFR part 97 is effective upon publication of each separate SIAP and/or Weather Takeoff Minimums as contained in the transmittal. Some SIAP and/or Weather Takeoff Minimums amendments may have been previously issued by the FAA in a Flight Data Center (FDC) Notice to Airmen (NOTAM) as an emergency action of immediate flight safety relating directly to published aeronautical charts. The circumstances which created the need for some SIAP, and/or Weather Takeoff Minimums amendments may require making them effective in less than 30 days. For the remaining SIAPs and/or Weather Takeoff Minimums, an effective date at least 30 days after publication is provided.
Further, the SIAPs and/or Weather Takeoff Minimums contained in this amendment are based on the criteria contained in the U.S. Standard for Terminal Instrument Procedures (TERPS). In developing these SIAPs and/or Weather Takeoff Minimums, the TERPS criteria were applied to the conditions existing or anticipated at the affected airports. Because of the close and immediate relationship between these SIAPs and/or Weather Takeoff Minimums and safety in air commerce, I find that notice and public procedure before adopting these SIAPs and/or Weather Takeoff Minimums are impracticable and contrary to the public interest and, where applicable, that good cause exists for making some SIAPs and/or Weather Takeoff Minimums effective in less than 30 days.
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. It, therefore—(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. For the same reason, the FAA certifies that this amendment will not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
Air Traffic Control, Airports, Incorporation by reference, and Navigation (Air).
49 U.S.C. 106(g), 40103, 40106, 40113, 40114, 40120, 44502, 44514, 44701, 44719, 44721-44722.
The FAA published an Amendment in Docket No. 30545 Amdt No. 3214 to Part 97 of the Federal Aviation Regulations (Vol 72, FR No. 72, page 18867, dated, April 16, 2007) Under Section 97.15 effective 10 May 2007, which is hereby rescinded:
Internal Revenue Service (IRS), Treasury.
Correction to final and temporary regulations.
This document contains corrections to final and temporary regulations that was published in the
Theresa Abell, (202) 622-7700 or Phoebe Bennett, (202) 622-7770 (not toll-free numbers).
The final and temporary regulations (TD 9322) that are the subject of these corrections are under section 1502 of the Internal Revenue Code.
As published, these final and temporary regulations (TD 9322) contain errors that may prove to be misleading and are in need of clarification.
Accordingly, these final and temporary regulations (TD 9322) that were the subject of FR Doc. E7-6541, are corrected as follows:
1. On page 17805, column 1, in the preamble, under the paragraph heading “
2. On page 17805, column 2, in the preamble, under the paragraph heading “
3. On page 17805, column 2, in the preamble, under the paragraph heading “
Coast Guard, DHS.
Temporary final rule; correction.
The U. S. Coast Guard published a rule in the
This rule is effective from 8 a.m. on May 3, 2007, until 8 p.m. on May 4, 2007.
LCDR Thomas Tarrants, Enforcement Branch Chief, U.S. Coast Guard Sector Hampton Roads, Virginia at (757) 483-8571.
The U.S. Coast Guard published a document in the
In rule FR Doc. CGD05-07-038 published on April 23, 2007, (72 FR 20051) make the following correction. On page 20052, in two places, remove the number § 165.T07-038 and put in place of that number § 165.T05-038.
Office of Personnel Management.
Notice of proposed rulemaking.
The Office of Personnel Management (OPM) proposes to amend its regulations governing Federal adverse actions. The proposed regulations would conform the adverse action rules regarding employee coverage to binding judicial decisions interpreting the underlying statute.
Submit comments on or before July 2, 2007.
Send or deliver written comments to Ana A. Mazzi, Deputy Associate Director for Workforce Relations and Accountability Policy, Office of Personnel Management, 1900 E Street, NW., Room 7H28, Washington, DC 20415; by FAX to 202-606-2613; or by e-mail to
Sharon L. Mayhew by telephone at (202) 606-2930; by FAX at (202) 606-2613; or by e-mail at
Section 7514 of title 5, United States Code (U.S.C.), provides the statutory authority for OPM to prescribe regulations pertaining to adverse actions in the competitive or excepted service. In addition, these regulations are found at title 5, Code of Federal Regulations (CFR), part 752, subpart D, and are the subject of this interim final rule. Corresponding and related regulations pertaining to probationary periods are found at 5 CFR part 315, subpart H, and also are the subject of this proposed rule.
Two decisions of the U.S. Court of Appeals for the Federal Circuit (Federal Circuit or Court),
The pertinent statutory text appears below:
5 U.S.C. Sec. 7511. Definitions; application
(a) For the purpose of this subchapter—
(1) “Employee” means—
(A) An individual in the competitive service—
(i) Who is not serving a probationary or trial period under an initial appointment; or
(ii) Who has completed 1 year of current continuous service under other than a temporary appointment limited to 1 year or less;
(B) A preference eligible in the excepted service who has completed 1 year of current continuous service in the same or similar positions—
(i) In an Executive agency; or
(ii) In the United States Postal Service or Postal Rate Commission; and
(C) An individual in the excepted service (other than a preference eligible)—
(i) Who is not serving a probationary or trial period under an initial appointment pending conversion to the competitive service; or
(ii) Who has completed 2 years of current continuous service in the same or similar positions in an Executive agency under other than a temporary appointment limited to 2 years or less;
An individual who meets this definition of “employee” is entitled to certain procedural and appeal rights when he or she is the subject of an adverse action (
Before the Court issued
Contrary to this interpretation, the Federal Circuit in
The Federal Circuit addressed the question of whether an individual, like Ms. Van Wersch, serving in a probationary or trial period and therefore excluded from the definition of “employee” under 5 U.S.C. 7511(a)(1)(C)(i), could still be considered an employee, with full adverse action rights, if she met only the criteria of 5 U.S.C. 7511(a)(1)(C)(ii). The Government argued that Congress had not intended to extend employee appeal rights to excepted service personnel, such as Ms. Van Wersch, who were serving in probationary or trial positions pending conversion to the competitive service. While recognizing that the Government made a compelling case for its reading of the statute based on the legislative history, the Court rejected the Government's argument, holding that Congress had not used language that effectuated the putative legislative intent and that courts are not authorized to look at Congressional intent when the language of the statute was clear and unambiguous.
The Federal Circuit applied the
The Court held that “[t]he panel is bound by the court's earlier decision in
As yet, Congress has not accepted the Court's invitation to amend these provisions. Therefore, to eliminate potential confusion, OPM proposes to amend the regulations at 5 CFR part 752 to conform to the existing Federal Circuit case law described above.
[0]We therefore propose to make four amendments to the text of paragraphs (c) and (d) of 5 CFR 752.401, to clarify the definition of “employee” for purposes of the adverse action rules. Three amendments are required to conform to the holding in
First, to conform with
Second, we propose to add a new § 752.401(d)(13) to clarify that a competitive service employee who is serving a probationary or trial period does not meet the definition of “employee” unless he or she has completed one year of current continuous service under other than a temporary appointment limited to one year or less.
The
To comply with
We are also proposing to change part 315, Career and Career Conditional Employment, to make the regulations governing probationary periods consistent with the change in the definition of “covered employee.”
OPM is proposing to remove the phrase “in the same or similar positions” from the regulation at the amended paragraph 5 CFR 752.401(c)(2), and also from the definition of “current continuous employment” at 5 CFR 752.402. This change addresses language in the current regulations concerning individuals in the competitive service that requires that “continuous service” be in “the same or similar positions.” That language is not found in the statute. This issue arose in administrative litigation before the MSPB.
OPM invites interested persons to participate in this proposed rulemaking by submitting written comments, data, or views.
Before finalizing these proposed amendments, we will consider all comments received on or before the closing date for comments. We will consider comments filed late if it is possible to do so without incurring expense or delay. We may change these proposed amendments in light of the comments we receive.
The Office of Management and Budget has reviewed this rule in accordance with E.O. 12866.
OPM has determined these amendments will not have a significant economic impact on a substantial number of small entities because they will apply only to Federal agencies and employees.
Government employees.
Administrative practice and procedure, Government employees.
Accordingly, OPM proposes to amend parts 315 and 752 of title 5, Code of Federal Regulations, as follows:
1. The authority for part 315 continues to read:
5 U.S.C. 1302, 3301, and 3302; E.O. 10577, 3 CFR, 1954-1958 Comp., p. 218, unless otherwise noted; and E.O. 13162; secs, 315.601 and 315.609 also issued under 22 U.S.C. 3651 and 3652. Secs. 315.602 and 315.604 also issued under 5 U.S.C. 1104. Sec 315.603 also issued under 5 U.S.C. 8151. Sec 315.605 also issued under E.O. 12034, 3 CFR, 1978 Comp., p. 111. Sec 315.606 also issued under E.O. 11219, 3 CFR, 1964-1965 Comp., p. 303. Sec 315.607 also issued under 22 U.S.C. 2506. Sec 315.608 also issued under E.O. 12721, 3 CFR, 1990 Comp., p. 293. Sec. 315.610 also issued under 5 U.S.C. 3304(d). Sec 315.611 also issued under Section 511, Pub. L. 106-117, 113 Stat. 1575-76. Sec 315.708 also issued under E.O. 13318. Sec. 315.710 also issued under E.O. 12596, 3 CFR, 1987 Comp., p. 229. Subpart I also issued under 5 U.S.C. 3321, E.O. 12107, 3 CFR, 1978 Comp., p. 264.
2. Revise § 315.803 to read as follows:
(a) The agency shall utilize the probationary period as fully as possible to determine the fitness of the employee and shall terminate his services during this period if he fails to demonstrate fully his qualifications for continued employment.
(b) Termination of an individual serving a probationary period must be taken in accordance with subpart D of part 752 of this chapter if the individual has completed one year of current continuous service under other than a temporary appointment limited to 1 year or less and is not otherwise excluded by the provisions of that subpart.
3. Revise § 315.804 (a) to read as follows:
(a) Subject to § 315.803(b), when an agency decides to terminate an employee serving a probationary or trial period because his work performance or conduct during this period fails to demonstrate his fitness or his qualifications for continued employment, it shall terminate his services by notifying him in writing as to why he is being separated and the effective date of the action. The information in the notice as to why the employee is being terminated shall, as a minimum, consist of the agency's conclusions as to the inadequacies of his performance or conduct.
4. Revise § 315.805 introductory text to read as follows:
Subject to § 315.803(b), when an agency proposes to terminate an employee serving a probationary or trial period for reasons based in whole or in part on conditions arising before his appointment, the employee is entitled to the following:
1. The authority for part 752 continues to read:
5 U.S.C. 7504, 7514, and 7543.
2. Revise § 752.401 (c)(1) and (2), (d)(11) and (12), and add (d)(13) to read as follows:
(a) * * *
(b) * * *
(c) * * *
(1) A career or career conditional employee in the competitive service who is not serving a probationary or trial period;
(2) An employee in the competitive service who has completed 1 year of current continuous service under other than a temporary appointment limited to 1 year or less;
(d) * * *
(11) A nonpreference eligible employee serving a probationary or trial period under an initial appointment in the excepted service pending conversion to the competitive service, unless they meet the requirements of paragraph (c)(5) of this section;
(12) An employee whose agency or position has been excluded from the appointing provisions of title 5, United States Code, by separate statutory authority in the absence of any provision to place the employee within the coverage of chapter 75 of title 5, United States Code; and
(13) An employee in the competitive service serving a probationary or trial period, unless they meet the requirements of paragraph (c)(2) of this section.
3. Revise § 752.402 (b) to read as follows:
(a) * * *
Grain Inspection, Packers and Stockyards Administration, USDA.
Advance notice of proposed rulemaking.
We are initiating a review of the United States Standards for Soybeans to determine their effectiveness and responsiveness to current grain industry needs. Numerous changes have occurred in the breeding and production practices of soybeans as well as in the technology used to harvest, process, and test soybeans, and in the marketing practices of soybeans. As a result, soybean producer groups have asked us to initiate a review of the soybean standards. In order to ensure that the standards and subsequent grading practices remain relevant, we invite interested persons to submit comments and supporting information to assist in the evaluation of current standards and grading practices for soybeans and in the development of any recommendations for change.
We will consider comments that we receive by July 2, 2007.
We invite you to submit comments on this advance notice of proposed rulemaking. You may submit comments by any of the following methods:
•
•
•
•
•
•
•
Rebecca Riese at GIPSA, USDA, 1400 Independence Avenue, SW., Washington, DC 20250-3630; Telephone (202) 720-4116; Fax Number (202) 720-7883; e-mail
This rule has been determined to be exempt from the purpose of Executive Order 12866, and therefore has not been reviewed by the Office of Management and Budget (OMB).
We established the U.S. soybean standards on November 20, 1940, under the authority of the United States Grain Standards Act (7 U.S.C. 76). To further facilitate the marketing of U.S. soybeans, we revised the standards in 1994 and 2006. The 2006 revision becomes effective September 1, 2007.
In 1994, we revised the reporting requirements of splits (broken soybeans where more than one fourth of the soybean removed and that are not damaged), reduced the U.S. Sample Grade criteria for stones and glass, established a special grade Purple Mottled or Stained, eliminated the grade limitation on materially weathered soybeans, clarified references to Mixed soybeans, and established a cumulative total for U.S. Sample Grade factors. In 2006, we published a Final Rule (71 FR 52403-52406), to be effective September 1, 2007, that changes the minimum test weight per bushel (TW) from a grade determining factor to an informational factor. Various factors are identified for soybeans and are used to determine the level of the grade of the shipment of soybeans. TW will continue to be measured, but no longer used to determine grade; it will be provided as additional information on the certificate unless the applicant for inspection service for the soybeans indicates that the information is not needed. As an informational factor TW may continue to be of interest and specified in contracts for soybean shipments.
The standards serve as the fundamental starting point to define U.S. soybean quality in the global marketplace. They include definitions, the basic principles governing application of standards, such as the type of sample used for a particular quality analysis, grades and grade requirements, and special grades and special grade requirements, such as for Garlicky soybeans and Purple Mottled or Stained soybeans. Official procedures for how the various grading factors are determined are provided in the Grain Inspection Handbook, Book II, Chapter 10, “Soybeans.” Official procedures may be viewed and printed from the GIPSA Web site at:
GIPSA's grading and inspection services, as provided through a network of federal, state, and private laboratories, determine the quality and condition of soybeans. These determinations are performed in accordance with applicable standards using approved methodologies, and can be applied at any point in the marketing chain. The current testing technology for quality attributes, such as oil and protein content, is rapid and reliable, yielding consistent results. In addition, GIPSA issues certificates describing the quality and condition of the graded soybeans that are accepted as evidence in all Federal courts. U.S. soybean standards, and the affiliated grading and testing services offered by GIPSA, verify that the seller's commodity meets specified requirements, and that customers receive the quality they expect.
Over time, numerous changes have occurred in the breeding and production practices of soybeans as well as in the technology used to harvest, process, and test soybeans, and in the marketing practices of soybeans. In this rapidly evolving market, we need to ensure that the U.S. soybean standards and associated grading procedures remain relevant. Therefore, we are issuing this advance notice of proposed rulemaking to invite comments from all interested persons for input and suggestions for
The soybean standards currently define foreign material (FM) as: “All matter that passes through an 8/64 round-hole sieve and all matter other than soybeans remaining in the sieved sample after sieving according to procedures prescribed in FGIS instructions.”
When separating FM (impurities) from soybeans, inspectors follow a process that entails using a combined mechanical (sieve) and manual separation procedure. Specifically, inspectors first handpick the 1,000 to 1,050-gram soybean sample for coarse foreign material (
It is important to note that when inspectors see soybean pods in the sample, they remove the soybeans from the pods and only the pod is considered as foreign material. Further, soybean hulls which remain on top of the sieve are not considered FM; whereas small broken pieces of soybeans, which pass through the sieve, are considered as FM.
Finally, inspectors calculate the total amount of FM by adding the percentage of coarse FM to the percentage of fine FM. (This procedure may be viewed and printed from the GIPSA Web site at:
The following is a series of questions about the FM definition and procedure:
1. Is the definition of FM, as provided in the soybean standards, still sufficient for current marketing practices?
2. How does our method for separating FM from soybeans compare to the commercial cleaning process? Please provide as much detail as possible as to how FM is determined in the market or for the segment of the market that you represent.
3. In order to provide a better representation of actual market value of soybeans, should we consider developing and adopting a fully-automated process to better reflect commercial cleaning capabilities? Please elaborate on the type of equipment (and sieves, if applicable) necessary for using such a procedure for separating FM from soybeans.
4. Do small broken pieces of soybeans have processing value? Should the procedure be amended so that brokens are not considered as FM?
5. Do processors have a method for removing soybeans from the pod? If not, should the procedure be amended so that pods, with or without soybeans in them, will be considered as FM?
6. In light of changes in the production practices of soybeans brought about by various technological developments, farm programs, and other factors, should the grading limits for FM be amended? What should the new grade limits be? Please provide a rationale for any changes, and if possible, project the quantifiable costs and benefits for the U.S. soybean market if the grade limits were amended.
According to our current inspection procedures, inspectors cross section soybeans and pieces of soybeans that are immature and have a thin, flat, wrinkled, or wafer-like appearance to determine if there is “meat” in the kernel. If there is “meat” in the kernel and the “meat” is not otherwise damaged, the inspector considers the soybean to be sound.
7. Do wafered kernels (wafers) containing minimal amounts of “meat” have processing value? If not, or if the value is appreciably reduced, should the procedure be amended so that wafers, to include soybeans with minimal amounts of meat, are considered damaged for inspection and grading purposes?
In the Official Inspection and Weighing System, we currently offer analyses or determinations for a number of official criteria factors for soybeans.
8. Are there other factors for which we should offer analyses/determinations that would provide better or more complete information to facilitate the marketing and/or processing of soybeans?
9. Since oil and protein content are considered to be the true determinants of value for soybean processing, should analysis of oil and protein content be mandatory, nongrade-determining factors that would be determined and reported on all official certificates for grade?
10. Are there certain aspects about the oil and protein content that would provide more meaningful information? For example, should we offer not only protein content, but also the amino acid profile of the protein?
11. Considering the rapid growth in biodiesel production, would the information exchange between sellers and buyers of soybeans be facilitated if standardized tests existed for attributes, such as fatty acids?
a. Please list the specific attributes.
b. Should we have a role in standardizing tests for the attributes listed? Should we assist only in the standardization of the tests (e.g., develop reference methods or improve existing reference methods) or should we make tests for these attributes available throughout the official system?
GIPSA has been working with life science companies in the pursuit of a standardized, rapid test for the determination of linolenic acid content in soybeans. Acres currently devoted to production of low linolenic acid soybean varieties are lower than previously anticipated. In 2006, these acres totaled approximately 750,000 out of the 72 million total planted soybean acres, less than 1 percent. However, seed distributors project acres devoted to production of low linolenic acid soybean varieties in 2007 to triple.
12. Should GIPSA continue to pursue a standardized, rapid test for the determination of linolenic acid content and, if so, why?
In the determination of the grading factor total damage, inspectors look for a number of types of damage, including badly ground-damaged, badly weathered-damaged, diseased, frost-damaged, germ-damaged, heat-damaged, insect-bored, mold-damaged, sprout-damaged, stinkbug-stung, or otherwise materially damaged.
13. Are these the right types of damage, and are visual reference images/interpretive lines that are currently used to determine the various types of damages reflective of the level of quality desired in the marketplace? (Visual reference images/interpretive lines may be viewed on the GIPSA Web site at:
Inspectors also rely on visual reference images to determine whether
14. In consideration of the fact that the overall appearance of the product is an important consideration for some customers, should we create other general appearance images? What appearance factors are of greatest interest? (Visual reference images/general appearance factors may be viewed on the GIPSA Web site at:
As provided in 9 CFR 810.1603, Basis of determination, “each determination of class, heat-damaged kernels, damaged kernels, splits, and soybeans of other colors is made on the basis of the grain when free from foreign material. Inspectors make other determinations not specifically provided for under the general provisions on the basis of the grain as a whole.” For example, inspectors determine moisture content on the sample as a whole.
15. What basis of determination is used in the marketplace for the various factors? Why does the marketplace use that basis?
16. Would there be any positive or detrimental consequences if we were to determine all factors on the basis of a sample when free from foreign matter?
17. Should we establish a separate standard, for example, U.S. Standards for Food Grade Soybeans or a separate grade level, class, or special grade within the existing soybeans standards for food-grade soybeans? Please provide as much detail as possible as to:
a. Explain why.
b. What would a new standard look like or what would the grade limits be for a new grade level?
We are committed to provide market-relevant soybean standards. We welcome your comments on these issues as well as any comments or suggestions on changes to the soybean standards and grading procedures.
7 U.S.C. 71-87.
Agricultural Marketing Service, USDA.
Referendum order.
This document directs that a continuance referendum be conducted among eligible growers of cranberries in the States of Massachusetts, Rhode Island, Connecticut, New Jersey, Wisconsin, Michigan, Minnesota, Oregon, Washington, and Long Island in the State of New York to determine whether they favor continuance of the marketing order regulating the handling of cranberries grown in the production area.
The referendum will be conducted from May 17 through May 31, 2007. To vote in this referendum, growers must have been engaged in producing cranberries within the production area during the period September 1, 2005, through August 31, 2006.
Copies of the marketing order may be obtained from USDA, Washington, DC Marketing Field Office, 4700 River Road, Unit 155, Riverdale, Maryland 20737, or the Office of the Docket Clerk, Marketing Order Administration Branch, Fruit and Vegetable Programs, Agricultural Marketing Service, U.S. Department of Agriculture, 1400 Independence Avenue, SW., Stop 0237, Washington, DC 20250-0237.
Patricia A. Petrella or Kenneth G. Johnson, Marketing Order Administration Branch, Fruit and Vegetable Programs, AMS, USDA, Unit 155, 4700 River Road, Riverdale, MD 20737; telephone: (301) 734-5243, Fax: (301) 734-5275; or e-mail at:
Pursuant to Marketing Order No. 929 (7 CFR part 929), hereinafter referred to as the “order,” and the applicable provisions of the Agricultural Marketing Agreement Act of 1937, as amended (7 U.S.C. 601-674), hereinafter referred to as the “Act,” it is hereby directed that a referendum be conducted to ascertain whether continuance of the order is favored by growers. The referendum shall be conducted during the period May 17 through May 31, 2007, among eligible cranberry growers in the production area. Only growers that were engaged in the production of cranberries in the States of Massachusetts, Rhode Island, Connecticut, New Jersey, Wisconsin, Michigan, Minnesota, Oregon, Washington, and Long Island in the State of New York during the period of September 1, 2005, through August 31, 2006, may participate in the continuance referendum.
USDA has determined that continuance referenda are an effective means for determining whether growers favor continuation of marketing order programs. The USDA would not consider termination of the order if more than 50 percent of the growers who vote in the referendum and growers of more than 50 percent of the volume of cranberries represented in the referendum favor continuance of their program.
In evaluating the merits of continuance versus termination, the USDA will not only consider the results of the continuance referendum. The USDA will also consider all other relevant information concerning the operation of the order and the relative benefits and disadvantages to growers, processors, and consumers in order to determine whether continued operation of the order would tend to effectuate the declared policy of the Act.
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), the ballot materials used in the referendum herein ordered have been previously approved by the Office of Management and Budget (OMB) under OMB No. 0581-0189, OMB Generic Fruit Crops. It has been estimated that it will take an average of 20 minutes for each of the approximately 1,100 producers of cranberries in the production area to cast a ballot. Participation is voluntary. Ballots postmarked after May 31, 2007, will be marked invalid and not included in the vote tabulation.
Kenneth G. Johnson, Patricia A. Petrella and Dawana Clark of the Washington, DC Marketing Field Office, Fruit and Vegetable Programs, Agricultural Marketing Service, USDA, are hereby designated as the referendum agents of USDA to conduct such referendum. The procedure applicable to the referendum shall be the “Procedure for the Conduct of Referenda in Connection With
Ballots will be mailed to all growers of record and may also be obtained from the referendum agents and from their appointees.
Cranberries, Marketing agreements, Reporting and recordkeeping requirements.
7 U.S.C. 601-674.
Federal Energy Regulatory Commission, DOE.
Withdrawal of notice of proposed rulemaking.
The Federal Energy Regulatory Commission is withdrawing its proposal to amend its regulations to require public utilities to append to their open access transmission tariffs (OATTs) an intermittent generator imbalance service schedule in light of the imbalance-related reforms adopted in Order No. 890, 72 FR 12266 (Mar. 15, 2007).
The notice of proposed rulemaking published on April 14, 2005, at 70 FR 21349, is withdrawn as of May 1, 2007.
1. On April 14, 2005, the Commission issued a Notice of Proposed Rulemaking (NOPR) in this proceeding.
2. In the NOPR, the Commission proposed to clarify and amend imbalance-related provisions in the
3. Since issuance of the NOPR, the Commission has completed its OATT reform rulemaking in Docket Nos. RM05-25-000,
4. As a result of the imbalance-related reforms adopted in Order No. 890, and in particular the requirement that generator imbalance provisions in each transmission provider's OATT take into account an intermittent resources' limited ability to forecast or control generation levels, the Commission concludes that it is no longer necessary to address the NOPR proposal to add to the
5. The Commission therefore withdraws the NOPR and terminates this rulemaking proceeding.
Docket No. RM05-10-000 is hereby terminated.
By the Commission.
Coast Guard, DHS.
Notice of proposed rulemaking.
The Coast Guard proposes establishing a temporary safety zone on the navigable waters of the Lower Colorado River, Laughlin, NV, in support of a Labor Day fireworks display near the AVI Resort and Casino. The safety zone is necessary to provide for the safety of the crew, spectators, participants of the event, participating vessels and other vessels and users of the waterway. Persons and vessels will be prohibited from entering into, transiting through, or anchoring within this safety zone unless authorized by the Captain of the Port, or his designated representative.
Comments and related material must reach the Coast Guard on or before July 31, 2007.
You may mail comments and related material to Commander (SPW), Attn: Waterways Management Division, Coast Guard Sector San Diego, 2710 N. Harbor Drive, San Diego, CA 92101-1028. Marine Events, Prevention Department, maintains the public docket for this rulemaking. Comments and material received from the public, as well as documents indicated in this preamble as being available in the docket, will become part of this docket and will be available for inspection or copying at Coast Guard Sector San Diego between 8 a.m. and 3 p.m., Monday through Friday, except Federal holidays.
Chief Petty Officer Eric Carroll, Waterways Management, U.S. Coast Guard Sector San Diego, CA, at telephone (619) 278-7277.
We encourage you to participate in this rulemaking by submitting comments and related material. If you do so, please include your name and address, identify the docket number for this rulemaking [COTP San Diego 07-225], indicate the specific section of this document to which each comment applies, and give the reason for each comment. Please submit all comments and related material in an unbound format, no larger than 8
We do not now plan to hold a public meeting. But you may submit a request for a meeting by writing to Coast Guard Sector San Diego at the address under
The Coast Guard proposes establishing a temporary safety zone on the navigable waters of the Lower Colorado River, Laughlin, NV, in support of a Labor Day fireworks show in the navigation channel of the Lower Colorado River, Laughlin, NV. The fireworks show is being sponsored by AVI Resort and Casino. The safety zone will be set at a 980-foot radius around the anchored firing barge. This temporary safety zone is necessary to provide for the safety of the show's crew, spectators, participants of the event, participating vessels, and other vessels and users of the waterway.
The event involves one anchored barge, which will be used as a platform for launching of fireworks. The safety zone is required because the barge's planned firing location is in the navigation channel. This safety zone would be enforced from 8 p.m. through 9:30 p.m. on September 2, 2007.
The limits of this temporary safety zone include all areas within 980 feet of the firing location adjacent to the AVI Resort and Casino centered in the navigational channel between Laughlin Bridge and the northwest point of the AVI Resort and Casino Cove in position: 35°00′45″ N, 114°38′16″ W.
U.S. Coast Guard personnel would enforce this safety zone. Other Federal, State, or local agencies may assist the Coast Guard, including the Coast Guard Auxiliary. Vessels or persons violating this rule would be subject to both criminal and civil penalties.
This proposed rule is not a “significant regulatory action” under section 3(f) of Executive Order 12866, Regulatory Planning and Review, and does not require an assessment of potential costs and benefits under section 6(a)(3) of that Order. The Office of Management and Budget has not reviewed it under that Order. It is not “significant” under the regulatory policies and procedures of the Department of Homeland Security (DHS).
We expect the economic impact of this proposed rule to be so minimal that a full Regulatory Evaluation under the regulatory policies and procedures of DHS is unnecessary. Although the safety zone will restrict boating traffic within the navigable waters of the Lower Colorado River, Laughlin, NV, the effect of this regulation will not be significant as the safety zone will encompass only a small portion of the waterway and will be very short in duration. The entities most likely to be affected are pleasure craft engaged in recreational activities and sightseeing. As such, the Coast Guard expects the economic impact of this rule to be minimal.
Under the Regulatory Flexibility Act (5 U.S.C. 601-612), we have considered whether this proposed rule would have a significant economic impact on a substantial number of small entities. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000.
The Coast Guard certifies under 5 U.S.C. 605(b) that this proposed rule would not have a significant economic impact on a substantial number of small entities. This rule will affect the following entities, some of which may be small entities: the owners or operators of vessels intending to transit or anchor in a portion of the Lower Colorado River, Laughlin, NV, from 8 p.m. to 9:30 p.m. on September 2, 2007.
This safety zone will not have a significant economic impact on a substantial number of small entities for the following reasons. The safety zone only encompasses a small portion of the waterway, it is short in duration at a late hour when commercial traffic is low, and the Captain of the Port may authorize entry into the zone, if necessary.
If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this rule would have a significant economic impact on it, please submit a comment (see
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), we want to assist small entities in understanding this proposed rule so that they can better evaluate its effects on them and participate in the rulemaking. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact Chief Petty Officer Eric Carroll, Waterways Management, U.S. Coast Guard Sector San Diego at telephone (619) 278-7277. The Coast Guard will not retaliate against small entities that question or complain about this rule or any policy or action of the Coast Guard.
This proposed rule would call for no new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).
A rule has implications for federalism under Executive Order 13132, Federalism, if it has a substantial direct effect on State or local governments and would either preempt State law or impose a substantial direct cost of compliance on them. We have analyzed this proposed rule under that Order and have determined that it does not have implications for federalism.
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 or more in any one year. Though this proposed rule would not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.
This proposed rule would not effect a taking of private property or otherwise have taking implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.
This proposed rule meets applicable standards in sections 3(a) and 3(b)(2) of Executive Order 12988, Civil Justice Reform, to minimize litigation, eliminate ambiguity, and reduce burden.
We have analyzed this proposed rule under Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and would not create an environmental risk to health or risk to safety that might disproportionately affect children.
This proposed rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it would not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes.
We have analyzed this proposed rule under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use. We have determined that it is not a “significant energy action” under that order because it is not a “significant regulatory action” under Executive Order 12866 and is not likely to have a significant adverse effect on the supply, distribution, or use of energy. The Administrator of the Office of Information and Regulatory Affairs has not designated it as a significant energy action. Therefore, it does not require a Statement of Energy Effects under Executive Order 13211.
The National Technology Transfer and Advancement Act (NTTAA) (15 U.S.C. 272 note) directs agencies to use voluntary consensus standards in their regulatory activities unless the agency provides Congress, through the Office of Management and Budget, with an explanation of why using these standards would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (
This proposed rule does not use technical standards. Therefore, we did not consider the use of voluntary consensus standards.
We have analyzed this proposed rule under Commandant Instruction M16475.lD and Department of Homeland Security Management Directive 5100.1, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321-4370f), and have made a preliminary determination that there are no factors in this case that would limit the use of a categorical exclusion under section 2.B.2 of the Instruction. Therefore, we believe that this rule should be categorically excluded, under figure 2-1, paragraph (34)(g), of the Instruction, from further environmental documentation because we would be establishing a safety zone. A preliminary “Environmental Analysis Check List” and “Categorical Exclusion Determination” are available in the docket where indicated under
Harbors, Marine safety, Navigation (water), Reporting and recordkeeping requirements, Security measures, Waterways.
For the reasons discussed in the preamble, the Coast Guard proposes to amend 33 CFR part 165 as follows:
1. The authority citation for part 165 continues to read as follows:
33 U.S.C. 1226, 1231; 46 U.S.C. Chapter 701; 50 U.S.C. 191, 195; 33 CFR 1.05-1(g), 6.04-1, 6.04-6, and 160.5; Pub. L. 107-295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1.
2. Add § 165.T11-179 to read as follows:
(a)
(b)
(c)
(d)
Coast Guard, DHS.
Notice of proposed rulemaking.
The Coast Guard proposes establishing a temporary safety zone on the navigable waters of the Lower Colorado River, Laughlin, NV, in support of a Independence Day fireworks display near the AVI Resort and Casino. The safety zone is necessary to provide for the safety of the crew, spectators, participants of the event, participating vessels and other vessels and users of the waterway. Persons and vessels will be prohibited from entering into, transiting through, or anchoring within this safety zone unless authorized by the Captain of the Port, or his designated representative.
Comments and related material must reach the Coast Guard on or before May 31, 2007.
You may mail comments and related material to Commander (SPW), Attn: Waterways Management Division, Coast Guard Sector San Diego, 2710 N. Harbor Drive, San Diego, CA 92101-1028. Marine Events, Prevention Department, maintains the public docket for this rulemaking. Comments and material received from the public, as well as documents indicated in this preamble as being available in the docket, will become part of this docket and will be available for inspection or copying at Coast Guard Sector San Diego between 8 a.m. and 3 p.m., Monday through Friday, except Federal holidays.
Chief Petty Officer Eric Carroll, Waterways Management, U.S. Coast Guard Sector San Diego, CA, at telephone (619) 278-7277.
We encourage you to participate in this rulemaking by submitting comments and related material. If you do so, please include your name and address, identify the docket number for this rulemaking [COTP San Diego 07-125], indicate the specific section of this document to which each comment applies, and give the reason for each comment. Please submit all comments and related material in an unbound format, no larger than 8
We do not now plan to hold a public meeting. But you may submit a request for a meeting by writing to Coast Guard Sector San Diego at the address under
The Coast Guard proposes establishing a temporary safety zone on the navigable waters of the Lower Colorado River, Laughlin, NV, in support of an Independence Day fireworks show in the navigation channel of the Lower Colorado River, Laughlin, NV. The fireworks show is being sponsored by AVI Resort and Casino. The safety zone will be set at a 980-foot radius around the anchored firing barge. This temporary safety zone is necessary to provide for the safety of the show's crew, spectators, participants of the event, participating vessels, and other vessels and users of the waterway.
The event involves one anchored barge, which will be used as a platform for launching of fireworks. The safety zone is required because the barge's planned firing location is in the navigation channel. This safety zone would be enforced from 8 p.m. through 9:45 p.m. on July 7, 2007.
The limits of this temporary safety zone include all areas within 980 feet of the firing location adjacent to the AVI Resort and Casino centered in the navigational channel between Laughlin Bridge and the northwest point of the AVI Resort and Casino Cove in position: 35°00′45″ N, 114°38′16″ W.
U.S. Coast Guard personnel would enforce this safety zone. Other Federal, State, or local agencies may assist the Coast Guard, including the Coast Guard Auxiliary. Vessels or persons violating this rule would be subject to both criminal and civil penalties.
This proposed rule is not a “significant regulatory action” under
We expect the economic impact of this proposed rule to be so minimal that a full Regulatory Evaluation under the regulatory policies and procedures of DHS is unnecessary. Although the safety zone will restrict boating traffic within the navigable waters of the Lower Colorado River, Laughlin, NV, the effect of this regulation will not be significant as the safety zone will encompass only a small portion of the waterway and will be very short in duration. The entities most likely to be affected are pleasure craft engaged in recreational activities and sightseeing. As such, the Coast Guard expects the economic impact of this rule to be minimal.
Under the Regulatory Flexibility Act (5 U.S.C. 601-612), we have considered whether this proposed rule would have a significant economic impact on a substantial number of small entities. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000.
The Coast Guard certifies under 5 U.S.C. 605(b) that this proposed rule would not have a significant economic impact on a substantial number of small entities. This rule will affect the following entities, some of which may be small entities: The owners or operators of vessels intending to transit or anchor in a portion of the Lower Colorado River, Laughlin, NV, from 8 p.m. to 9:45 p.m. on July 7, 2007.
This safety zone will not have a significant economic impact on a substantial number of small entities for the following reasons. The safety zone only encompasses a small portion of the waterway, it is short in duration at a late hour when commercial traffic is low, and the Captain of the Port may authorize entry into the zone, if necessary.
If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this rule would have a significant economic impact on it, please submit a comment (see
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), we want to assist small entities in understanding this proposed rule so that they can better evaluate its effects on them and participate in the rulemaking. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact Chief Petty Officer Eric Carroll, Waterways Management, U.S. Coast Guard Sector San Diego at telephone (619) 278-7277. The Coast Guard will not retaliate against small entities that question or complain about this rule or any policy or action of the Coast Guard.
This proposed rule would call for no new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).
A rule has implications for federalism under Executive Order 13132, Federalism, if it has a substantial direct effect on State or local governments and would either preempt State law or impose a substantial direct cost of compliance on them. We have analyzed this proposed rule under that Order and have determined that it does not have implications for federalism.
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 or more in any one year. Though this proposed rule would not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.
This proposed rule would not effect a taking of private property or otherwise have taking implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.
This proposed rule meets applicable standards in sections 3(a) and 3(b)(2) of Executive Order 12988, Civil Justice Reform, to minimize litigation, eliminate ambiguity, and reduce burden.
We have analyzed this proposed rule under Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks. This rule is not an economically significant rule and would not create an environmental risk to health or risk to safety that might disproportionately affect children.
This proposed rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it would not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes.
We have analyzed this proposed rule under Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use. We have determined that it is not a “significant energy action” under that order because it is not a “significant regulatory action” under Executive Order 12866 and is not likely to have a significant adverse effect on the supply, distribution, or use of energy. The Administrator of the Office of Information and Regulatory Affairs has not designated it as a significant energy action. Therefore, it does not require a Statement of Energy Effects under Executive Order 13211.
The National Technology Transfer and Advancement Act (NTTAA) (15 U.S.C. 272 note) directs agencies to use voluntary consensus standards in their regulatory activities unless the agency provides Congress, through the Office of Management and Budget, with an explanation of why using these standards would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (
This proposed rule does not use technical standards. Therefore, we did not consider the use of voluntary consensus standards.
We have analyzed this proposed rule under Commandant Instruction M16475.lD and Department of Homeland Security Management Directive 5100.1, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321-4370f), and have made a preliminary determination that there are no factors in this case that would limit the use of a categorical exclusion under section 2.B.2 of the Instruction. Therefore, we believe that this rule should be categorically excluded, under figure 2-1, paragraph (34)(g), of the Instruction, from further environmental documentation because we would be establishing a safety zone. A preliminary “Environmental Analysis Check List” and a draft “Categorical Exclusion Determination” are available in the docket where indicated under
Harbors, Marine safety, Navigation (water), Reporting and recordkeeping requirements, Security measures, Waterways.
For the reasons discussed in the preamble, the Coast Guard proposes to amend 33 CFR part 165 as follows:
1. The authority citation for part 165 continues to read as follows:
33 U.S.C. 1226, 1231; 46 U.S.C. Chapter 701; 50 U.S.C. 191, 195; 33 CFR 1.05-1(g), 6.04-1, 6.04-6, and 160.5; Pub. L. 107-295, 116 Stat. 2064; Department of Homeland Security Delegation No. 0170.1.
2. Add § 165.T11-178 to read as follows:
(a)
(b)
(c)
(d)
Environmental Protection Agency (EPA).
Proposed rule.
EPA is proposing to approve an assortment of rules, submitted by Ohio on May 16, 2006, setting limits on sulfur dioxide (SO
Comments must be received on or before May 31, 2007.
Submit your comments, identified by Docket ID No. EPA-R05-OAR-2007-0546, by one of the following methods:
1.
2.
3.
4.
5.
John Summerhays, Criteria Pollutant Section, Air Programs Branch (AR-18J), Environmental Protection Agency, Region 5, 77 West Jackson Boulevard, Chicago, Illinois 60604, (312) 886-6067,
This supplementary information section is arranged as follows:
Ohio submitted its original State Implementation Plan on January 30, 1972, which EPA partially approved on May 31, 1972, and fully approved on September 22, 1972. After a court remanded this approval for EPA to solicit public comments on the rulemaking, Ohio withdrew its submittal of rules for SO
On September 12, 1979, Ohio submitted a plan with limits for SO
On April 20, 1982, at 47 FR 16784, EPA approved rules for parts of 3 additional counties and all of another three additional counties. EPA approved rules for an additional county on June 30, 1982, at 47 FR 28377. EPA approved subsequently submitted Ohio SO
As a result of these prior rulemakings, EPA has approved State rules for all sources in 84 of Ohio's 88 counties and for all but one source in an 85th county. Counties for which sources remain subject to the FIP include Franklin County (full county), Stark County (full county), Summit County (full county), and Sandusky County (only for Martin Marietta). Ohio submitted further rules on May 16, 2006, most significantly including State rules to replace these Federal rules.
In 1978, EPA designated numerous areas in Ohio as nonattainment for the SO
As stated in 40 CFR 52.1881(a), “[w]here USEPA has approved the State's sulfur dioxide plan, those regulations supersede the federal sulfur dioxide plan contained in [40 CFR 52.1881(b)] and 40 CFR 52.1882.” On June 29, 1995, at 60 FR 33915, EPA rescinded numerous federally promulgated Ohio SO
Ohio law requires that the State review its regulations every five years. Ohio conducted this review and concluded that amendments were warranted for 4 of its 6 general rules and 40 of its county-specific rules. Since the regulations remain necessary for the State to continue to attain the SO
Ohio currently has no areas designated nonattainment for SO
However, a portion of one county, Summit County, has no designation. As the result of a 1980 remand by the Court of Appeals for the 6th Circuit, in
In 1981, EPA published multiple rulemaking notices that led to EPA taking no action on provisions of Ohio SO
On May 16, 2006, Ohio EPA submitted 4 amended general SO
Ohio submitted revisions to four of its six general SO
Rule 3745-18-06 was revised to add jet engine test stands to a list of source types that are exempt from the emission limits given in Ohio's rules for any day that the equipment burns only natural gas. EPA has approved this exemption as previously worded, on January 28, 2005, at 70 FR 4023 (see also 69 FR 41336, dated July 8, 2004). The first listed source type is fuel burning equipment. Thus, this rule revision may be considered simply a clarification that jet engine test stands shall have the exemption that fuel burning equipment has. In any case, the SO
As noted above, FIP rules remain in 4 counties: Franklin, Sandusky (applicable only to Martin Marietta), Stark, and Summit Counties. Ohio submitted rules for each of these counties to replace the FIP rules.
For Franklin and Summit Counties, Ohio amended its rules to assure that all sources with emission limits in the FIP have the same limits in the State rules. Criteria for EPA's review of these rules are described in guidance issued from the Director of the Air Quality Management Division to the Director of Region 5's Air and Radiation Division on September 28, 1994. This memorandum recommended approving State rules in place of FIP rules if three criteria are met:
1. That the FIP demonstrated the limits were adequately protective at the time of promulgation.
2. There is no evidence now that the FIP and associated emission limits are inadequate to protect the SO
3. The rules do not relax existing emission limits. EPA believes that these criteria are satisfied, i.e., that limits were appropriately demonstrated at the time of FIP promulgation to provide for attainment, that no subsequent evidence suggests otherwise, and that the State's rules provide limits that are fully as stringent as the existing FIP limits. The State rules also establish limits for sources that are not included either in the FIP rules or in the modeling that demonstrated that the FIP limits provide for attainment. Therefore, EPA believes that the rules for Franklin and Summit County may be approved and may supersede the existing FIP rules.
As noted above, EPA disapproved the State's rules for Summit County in 1981, stating that modeling evidence indicated that the limits did not assure attainment. Those rules differed substantially from the FIP limits and relied on a separate modeling analysis. The prior disapproval did not in any way indicate inadequacy of the FIP limits to assure attainment. EPA continues to believe that the FIP limits for Summit County provide for attainment. Thus, since the State rules have been modified to reflect the FIP limits, EPA believes the rules now provide for attainment, and the prior disapproval is moot.
For Stark County, as with Franklin and Summit Counties, the State amended its rules as necessary for sources regulated under the FIP to have limits that match those of the FIP. The Stark County rules also tighten the limits for one source not regulated under the FIP, namely Canton Drop Forge. Modeling was conducted to assess impacts of this source and other nearby sources. This modeling used AERMOD, which is EPA's recommended model for this application. The modeling included emissions from all significant sources in this portion of Stark County. The modeling used 1988 to 1992 meteorological data for Akron, and the modeling considered the potential downwash effects of the buildings of
For Sandusky County, only one source, Martin Marietta, remains subject to FIP rules. The FIP imposes a limit of 15.42 pounds of SO
EPA has previously approved Ohio's rule for other sources in Sandusky County. The amended rule updates the names of three companies and deletes one source from the rule but makes no substantive changes in the limits. EPA believes that the full rule is approvable.
Two additional rules include substantive revisions to applicable limits. The first is for Auglaize County. The applicable attainment demonstration, approved on January 27, 1981 at 46 FR 8481, provides for emissions above the county's generic limit of 2.6 pounds per million BTU for several emission points at the Saint Mary's municipal power plant, but the previously approved rules only authorize emissions above that generic limit for one unit. Ohio amended its rules to replace a limit of 6.5 #/MM Btu just for boiler number 6 with a limit of 5.9 #/MM Btu applicable to both the number 6 and the number 5 boilers. The previously approved attainment demonstration demonstrates that these limits will provide for attainment, so these amendments are approvable.
For Cuyahoga County, Ohio amended its rules to incorporate an additional general emission limit. In the Cuyahoga County rules that EPA approved in January 2005, Ohio had generally amended the rules to match the federally promulgated rules for this county. In particular, Ohio adopted the federally promulgated generic limit for coal-fired boilers with greater than 350 MM Btu per hour heat input. However, the State had failed to adopt the federally promulgated generic limit for coal-fired boilers with heat input between 10 MM Btu and 350 MM Btu per hour. The rule submitted on May 16, 2006 adds this second generic limit that applies to smaller boilers. This limit is part of the plan that has been demonstrated to provide for attainment, and so the addition of this limit is approvable.
As a result of its periodic rule review, Ohio amended numerous rules to update company names, to correct various unit identifications, and to correct typographical errors. In addition to making these types of amendments in the rules discussed above, Ohio made these types of revisions to the rules for 34 additional counties. The counties for which Ohio submitted such rules are Allen, Ashtabula, Athens, Butler, Champaign, Clark, Erie, Fairfield, Geauga, Greene, Hamilton, Hancock, Lake Lawrence, Lorain, Lucas, Marion, Miami, Montgomery, Muskingum, Ottawa, Paulding, Pike, Richland, Ross, Scioto, Seneca, Shelby, Trumbull, Tuscarawas, Van Wert, Washington, Wayne, and Wood Counties.
Ohio amended two rules because a source had been addressed in an incorrect county's rules. Specifically, a facility owned by Archer Daniels Midland (formerly A.E. Staley) is located in Hancock County, not Seneca County, and so Ohio removed this facility's limits from the Seneca County rule (Rule 3745-18-80) and inserted the identical limits in the Hancock County rule (Rule 3745-18-38).
These various revisions do not affect the stringency of the SIP but do enhance the clarity of the applicability of these limits. Therefore, these revised rules are approvable.
EPA published its initial designations on October 5, 1978, at 43 FR 46011. The designation for SO
As discussed above, Ohio has requested approval of emission limits that match the limits of the FIP, i.e. limits which modeling underlying the FIP have demonstrated to provide for attainment. Therefore, no further review of the modeling underlying the State limits of 1979 is necessary, and EPA may proceed to establish a designation for the portion of Summit County that is presently undesignated.
Air quality monitoring data from 2003 to 2006 indicate that SO
Modeling evidence also indicates that the relevant portion of Summit County is attaining the standard. EPA believes there are no companies within the undesignated area significantly violating their SO
Section 107(d)(3)(E) of the Clean Air Act describes several prerequisites for redesignation of areas from nonattainment to attainment. Because the relevant portion of Summit County is not designated nonattainment and in fact has no designation, these provisions of Section 107(d)(3)(E) are not germane here.
EPA is proposing to approve 44 rules for SO
By this action, EPA is proposing that state rules would supersede the last remaining portions of the FIP that was promulgated in 1976
Today's notice provides proposed revisions to the CFR to implement the actions proposed here. EPA is proposing to rescind the entirety of 40 CFR 52.1881(b) (including general provisions and county-specific limits) and of 40 CFR 52.1882 (providing FIP compliance schedules). Since EPA is proposing that Ohio has approvable rules for the entire State, EPA is proposing to rescind the sections of 40 CFR 52.1881(a) that identify counties for which EPA has taken no action or has disapproved the state's plan. EPA is proposing to replace the listing of counties having approved rules with a rule-by-rule listing of approved rules. EPA is proposing that the action concerning the designation of Summit County would establish a simplified, county-wide designation of attainment. Since EPA is proposing to address the court remand that has affected the designations for Summit County, EPA is proposing to rescind the footnotes that identify the effects of the remand. (EPA is also proposing to rescind the footnote that was inadvertently applied to the designation of Trumbull County.)
When submitting comments, remember to:
1. Identify the rulemaking by docket number and other identifying information (subject heading,
2. Follow directions—The EPA may ask you to respond to specific questions or organize comments by referencing a Code of Federal Regulations (CFR) part or section number.
3. Explain why you agree or disagree; suggest alternatives and substitute language for your requested changes.
4. Describe any assumptions and provide any technical information and/or data that you used.
5. If you estimate potential costs or burdens, explain how you arrived at your estimate in sufficient detail to allow for it to be reproduced.
6. Provide specific examples to illustrate your concerns, and suggest alternatives.
7. Explain your views as clearly as possible, avoiding the use of profanity or personal threats.
8. Make sure to submit your comments by the comment period deadline identified.
Under Executive Order 12866 (58 FR 51735, September 30, 1993), this action is not a “significant regulatory action” and therefore is not subject to review by the Office of Management and Budget.
This proposed rule does not impose an information collection burden under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
This proposed action merely proposes to approve state law as meeting Federal requirements and imposes no additional requirements beyond those imposed by state law. Accordingly, the Administrator certifies that this proposed rule will not have a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
Because this rule proposes to approve pre-existing requirements under state law and does not impose any additional enforceable duty beyond that required by state law, it does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4).
This action also does not have Federalism implications because it does 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 (64 FR 43255, August 10, 1999). This action merely proposes to approve a state rule implementing a federal standard, and does not alter the relationship or the distribution of power and responsibilities established in the Clean Air Act.
This proposed rule also does not have tribal implications because it will not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes, as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).
This proposed rule also is not subject to Executive Order 13045 “Protection of Children from Environmental Health Risks and Safety Risks” (62 FR 19885, April 23, 1997), because it is not economically significant.
Because it is not a “significant regulatory action” under Executive Order 12866 or a “significant regulatory action,” this action is also not subject to Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001).
Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), 15 U.S.C. 272, requires Federal agencies to use technical standards that are developed or adopted by voluntary consensus to carry out policy objectives, so long as such standards are not inconsistent with applicable law or otherwise impractical. In reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the Clean Air Act. Absent a prior existing requirement for the state to use voluntary consensus standards, EPA has no authority to disapprove a SIP submission for failure to use such standards, and it would thus be inconsistent with applicable law for EPA to use voluntary consensus standards in place of a program submission that otherwise satisfies the provisions of the Clean Air Act. Therefore, the requirements of section 12(d) of the NTTAA do not apply.
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Sulfur oxides.
Environmental protection, Air pollution control, National parks, Sulfur dioxide, Wilderness areas.
For the reasons stated in the preamble, parts 52 and 81, chapter I, of title 40 of the Code of Federal Regulations are proposed to be amended as follows:
1. The authority citation for part 52 continues to read as follows:
42 U.S.C. 7401
2. Section 52.1870 is amended by adding paragraph (c)(136) to read as follows:
(c) * * *
(136) On May 16, 2006, Ohio submitted numerous regulations for sulfur dioxide. These regulations were submitted to replace the remaining federally promulgated regulations, to make selected revisions to applicable limits, and to update company names and make other similar administrative changes.
(i)
(ii)
3. Section 52.1881 is amended as follows:
a. By revising paragraph (a)(4).
b. By removing and reserving paragraphs (a)(7), (a)(8), and (b).
(a) * * *
(4) Notwithstanding the portions of Ohio's sulfur dioxide rules identified in this section that EPA has either disapproved or taken no action on, EPA has approved a complete plan addressing all counties in the State of Ohio. EPA has approved the following rules, supplemented by any additional approved rules specified in 40 CFR 52.1870:
(i) Rules as effective in Ohio on December 28, 1979: OAC 3745-18-04 (measurement methods)—except for five disapproved paragraphs ((D)(2), (D)(3), (E)(2), (E)(3), and (E)(4)) and three paragraphs approved later ((D)(8), (D)(9), and (E)(7)), OAC 3745-18-05 (ambient monitoring), OAC 3745-18-08 (Allen)—except for one paragraph approved later (Cairo Chemical), OAC 3745-18-09 (Ashland County), OAC 3745-18-13 (Belmont), OAC 3745-18-14 (Brown), OAC 3745-18-16 (Carroll), OAC 3745-18-19 (Clermont)—except for one paragraph approved later (CG&E Beckjord), OAC 3745-18-20 (Clinton), OAC 3745-18-21 (Columbiana), OAC 3745-18-23 (Crawford), OAC 3745-18-25 (Darke), OAC 3745-18-26 (Defiance), OAC 3745-18-27 (Delaware), OAC 3745-18-30 (Fayette), OAC 3745-18-32 (Fulton), OAC 3745-18-36 (Guernsey), OAC 3745-18-39 (Hardin), OAC 3745-18-40 (Harrison), OAC 3745-18-41 (Henry), OAC 3745-18-42 (Highland), OAC 3745-18-43 (Hocking), OAC 3745-18-44 (Holmes), OAC 3745-18-45 (Huron), OAC 3745-18-46 (Jackson), OAC 3745-18-48 (Knox), OAC 3745-18-51 (Licking), OAC 3745-18-52 (Logan), OAC 3745-18-55 (Madison), OAC 3745-18-58 (Medina), OAC 3745-18-59 (Meigs), OAC 3745-18-60 (Mercer), OAC 3745-18-62 (Monroe), OAC 3745-18-64 (Morgan)—except for one paragraph approved later (OP Muskinghum River), OAC 3745-18-65 (Morrow), OAC 3745-18-67 (Noble), OAC 3745-18-70 (Perry), OAC 3745-18-73 (Portage), OAC 3745-18-74 (Preble), OAC 3745-18-75 (Putnam), OAC 3745-18-86 (Union), OAC 3745-18-88 (Vinton), OAC 3745-18-89 (Warren), OAC 3745-18-92 (Williams), and OAC 3745-18-94 (Wyandot);
(ii) Rules as effective in Ohio on October 1, 1982: OAC 3745-18-64 (B) (OP Muskinghum River in Morgan County);
(iii) Rules as effective in Ohio on October 31, 1991: OAC 3745-18-04 (D)(7), (D)(8)(a) to (D)(8)(e), (E)(5),
(iv) Rules as effective in Ohio on July 25, 1996: OAC 3745-18-47 (Jefferson);
(v) Rules as effective in Ohio on March 21, 2006: OAC 3745-18-22 (Coshocton), OAC 3745-18-33 (Gallia), and OAC 3745-18-71 (Pickaway);
(vi) Rules as effective in Ohio on September 1, 2003: OAC 3745-18-56 (Mahoning); and
(vii) Rules as effective in Ohio on January 23, 2006: OAC 3745-18-01 (definitions), OAC 3745-18-02 (air quality standards), OAC 3745-18-03 (compliance dates), OAC 3745-18-06 (general provisions), OAC 3745-18-07 (Adams), OAC 3745-18-10 (Ashtabula), OAC 3745-18-11 (Athens), OAC 3745-18-12 (Auglaize), OAC 3745-18-15 (Butler), OAC 3745-18-17 (Champaign), OAC 3745-18-18 (Clark), OAC 3745-18-24 (Cuyahoga), OAC 3745-18-28 (Erie), OAC 3745-18-29 (Fairfield), OAC 3745-18-31 (Franklin), OAC 3745-18-34 (Geauga), OAC 3745-18-35 (Greene), OAC 3745-18-37 (Hamilton), OAC 3745-18-38 (Hancock), OAC 3745-18-49 (Lake), OAC 3745-18-50 (Lawrence), OAC 3745-18-53 (Lorain), OAC 3745-18-54 (Lucas), OAC 3745-18-57 (Marion), OAC 3745-18-61 (Miami), OAC 3745-18-63 (Montgomery), OAC 3745-18-66 (Muskingum), OAC 3745-18-68 (Ottawa), OAC 3745-18-69 (Paulding), OAC 3745-18-72 (Pike), OAC 3745-18-76 (Richland), OAC 3745-18-77 (Ross), OAC 3745-18-78 (Sandusky), OAC 3745-18-79 (Scioto), OAC 3745-18-80 (Seneca), OAC 3745-18-81 (Shelby), OAC 3745-18-82 (Stark), OAC 3745-18-83 (Summit), OAC 3745-18-84 (Trumbull), OAC 3745-18-85 (Tuscarawas), OAC 3745-18-87 (Van Wert), OAC 3745-18-90 (Washington), OAC 3745-18-91 (Wayne), and OAC 3745-18-93 (Wood).
4. Section 52.1882 is removed and reserved.
5. The authority citation for part 81 continues to read as follows:
42 U.S.C. 7401
6. The table in § 81.336 entitled “Ohio—SO
Agricultural Marketing Service, USDA.
Notice and request for comments.
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), this notice announces the Agricultural Marketing Service's (AMS) intention to request approval from the Office of Management and Budget for an extension of the currently approved information collection of the Lamb Promotion, Research, and Information Program. Once approved, AMS will be requesting that the Office of Management and Budget merge this information collection with the information collection for National Research, Promotion and Consumer Information Programs.
Comments on this notice must be received by July 2, 2007 to be assured of consideration.
The timing and frequency of collecting information are intended to meet the needs of the industry while minimizing the amount of work necessary to fill out the required reports. In addition, the information included on these forms is not available from other industry sources because such information relates specifically to individuals or organizations subject to the provisions of the Act.
We estimate the paperwork and time burden of the above referenced information collection to be as follows:
Comments are invited on: (1) 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) 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; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) ways to minimize the burden of the collection of information for those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology. Comments must be sent to Kenneth R. Payne, Chief, Marketing Programs, Livestock and Seed Program, AMS, USDA, Room 2628-S, STOP 0251, 1400 Independence Avenue, SW., Washington, DC 20250-0251; Fax: (202) 720-1125; or, online at
Agricultural Marketing Service, USDA.
Notice and request for comments.
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), this notice announces the Agricultural Marketing Service's (AMS) intention to request approval from the Office of Management and Budget, for an extension and revision to the currently approved information collection Cotton Classing, Testing, and Standards.
Comments received by July 2, 2007 will be considered.
Interested persons are invited to submit written comments concerning this proposal to Shethir Riva, Chief, Research and Promotion, Cotton Program, Agricultural Marketing Service, USDA, 1400 Independence Ave., SW., Washington, DC 20250-0224. Comments should be submitted in triplicate. Comments may also be submitted electronically through
Shethir Riva, Chief, Research and Promotion, Cotton Program, Agricultural Marketing Service, USDA, 1400 Independence Ave., SW., Room 2639-S, Washington, DC 20250-0224, telephone (202) 720-3193, facsimile (202) 690-1718, or e-mail at
The information collection requirements in this request are essential to carry out the intent of the Acts and to provide the cotton industry the type of information they need to make sound business decisions. The information collected is the minimum required. Information is requested from growers, cooperatives, merchants, manufacturers, and other government agencies.
The information collected is used only by authorized employees of the USDA, AMS. The Cotton Industry is the primary user of the compiled information and AMS and other government agencies are secondary users.
All responses to this notice will be summarized and included in the request for OMB approval. All comments will become a matter of public record.
Agricultural Marketing Service, USDA.
Notice; request for nominations.
The Farm Security and Rural Investment Act of 2002 requires the Secretary of Agriculture to establish a Peanut Standards Board (Board) for the purpose of advising the Secretary on quality and handling standards for domestically produced and imported peanuts. The initial Board was appointed by the Secretary and announced on December 5, 2002. USDA seeks nominations for individuals to be considered for selection as Board members for terms of office ending June 30, 2010. Selected nominees sought by this action would replace those six producer and industry representatives who are currently serving for the term of office that ends June 30, 2007. The Board consists of 18 members representing producers and industry representatives.
Written nominations must be received on or before May 18, 2007.
Nominations should be sent to Dawana J. Clark, Marketing Order Administration Branch, Fruit and Vegetable Programs, AMS, USDA, Unit 155, 4700 River Road, Riverdale, MD 20737: Telephone: (301) 734-5243; Fax: (301) 734-5275; e-mail:
Section 1308 of the Farm Security and Rural Investment Act of 2002 (Farm Bill) requires the Secretary of Agriculture to establish a Peanut Standards Board (Board) for the purpose of advising the
The Farm Bill provides that the Board consist of 18 members, with three producers and three industry representatives from the States specified in each of the following producing regions: (a) Southeast (Alabama, Georgia, and Florida); (b) Southwest (Texas, Oklahoma, and New Mexico); and (c) Virginia/Carolina (Virginia and North Carolina).
For the initial appointments, the Farm Bill required the Secretary to stagger the terms of the members so that: (a) One producer member and peanut industry member from each peanut producing region serves a one-year term; (b) one producer member and peanut industry member from each peanut producing region serves a two-year term; and (c) one producer member and peanut industry member from each peanut producing region serves a three-year term. The term “peanut industry representatives” includes, but is not limited to, representatives of shellers, manufacturers, buying points, marketing associations and marketing cooperatives. The Farm Bill exempted the appointment of the Board from the requirements of the Federal Advisory Committee Act. The initial Board was appointed by the Secretary and announced on December 5, 2002.
USDA invites those individuals, organizations, and groups affiliated with the categories listed above to nominate individuals for membership on the Board. Nominees sought by this action would replace one producer and one industry member from each peanut producing region who served for the term of office that ends June 30, 2007. New members would serve for a 3-year term of office ending June 30, 2010.
Nominees should complete a Peanut Standards Board Background Information form and submit it to Mrs. Clark. Copies of this form may be obtained at the Internet site:
Equal opportunity practices will be followed in all appointments to the Board in accordance with USDA policies. To ensure that the recommendations of the Board have taken into account the needs of the diverse groups within the peanut industry, membership shall include, to the extent practicable, individuals with demonstrated abilities to represent minorities, women, persons with disabilities, and limited resource agriculture producers.
7 U.S.C. 7958.
Animal and Plant Health Inspection Service, USDA.
Extension of approval of an information collection; comment request.
In accordance with the Paperwork Reduction Act of 1995, this notice announces the Animal and Plant Health Inspection Service's intention to request an extension of approval of an information collection associated with regulations for the importation of live poultry, poultry meat, and other poultry products from specified regions.
We will consider all comments that we receive on or before July 2, 2007.
You may submit comments by either of the following methods:
• Federal eRulemaking Portal: Go to
•
For information on an information collection associated with regulations for the importation of live poultry, poultry meat, and other poultry products from specified regions, contact Dr. Peter Merrill, Senior Staff Veterinarian, Technical Trade Services Team, National Center for Import and Export, VS, APHIS, 4700 River Road, Unit 39, Riverdale, MD 20737-1231. For copies of more detailed information on the information collection, contact Mrs. Celeste Sickles, APHIS' Information Collection Coordinator, at (301) 734-7477.
Part 94, § 94.26, allows the importation, subject to certain conditions, of live poultry, poultry meat, and other poultry products from certain regions, including Argentina and the Mexican States of Campeche, Quintana Roo, and Yucatan, that are free of exotic Newcastle disease (END). The conditions for importation require,
We are asking the Office of Management and Budget (OMB) to approve our use of these information collection activities for an additional 3 years.
The purpose of this notice is to solicit comments from the public (as well as affected agencies) concerning our information collection. These comments will help us:
(1) Evaluate 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;
(2) Evaluate the accuracy of our estimate of the burden of the information collection, including the validity of the methodology and assumptions used;
(3) Enhance the quality, utility, and clarity of the information to be collected; and
(4) Minimize the burden of the information collection on those who are to respond, through use, as appropriate, of automated, electronic, mechanical, and other collection technologies, e.g., permitting electronic submission of responses.
All responses to this notice will be summarized and included in the request for OMB approval. All comments will also become a matter of public record.
Commodity Credit Corporation, USDA.
Notice and request for comments.
In accordance with the Paperwork Reduction Act of 1995, this notice announces the Commodity Credit Corporations (CCC) intention to request an extension for a currently approved information collection in support of the CCC Facility Guarantee Program (FGP) based on re-estimates.
Comments on this notice must be received by July 2, 2007.
Contact P. Mark Rowse, Director, Credit Programs Division, Foreign Agricultural Service, U.S. Department of Agriculture, AgStop 1035, Washington, DC 20250-1035, telephone (202) 720-0624 or e-mail at
(1) The applicant, in order to receive a payment guarantee, provides information evidencing that the exported goods and services used to develop improved infrastructure will primarily benefit exports of U.S. agricultural commodities and products; and
(2) The applicant is required to certify that the value of non-U.S. components of goods and services is less than 50 percent of the contract value covered under the payment guarantee.
In addition, each exporter and exporter's assignee (U.S. financial institution) must maintain records on all information submitted to CCC and in connection with sales made under the FGP. The information collection is used by CCC to manage, plan, evaluate and account for government resources. The reports and records are required to ensure the proper and judicious use of public funds.
Copies of this information collection can be obtained from Tamoria Thompson-Hall, the Agency Information Collection Coordinator, at (202) 690-1690 or e-mail at
Comments may be sent to P. Mark Rowse, Director, Credit Programs Division, Office of Trade Programs, FAS, USDA, Stop 1035, Washington, DC 20250, or
All responses to this notice will be summarized and included in the request for OMB approval. All comments will also become a matter of public record.
Farm Service Agency, USDA.
Notice and request for comments.
In accordance with the Paperwork Reduction Act of 1995, the Farm Service Agency (FSA) is seeking comments from all interested individuals and entities on the extension of currently approved information collection that supports the Emergency Loan Program (ELP). The collection of information from loan applicants and commercial lenders is used to determine eligibility, financial feasibility and security positions when the applicant requests emergency loan assistance.
Comments on this notice must be received on or before July 2, 2007 to be assured consideration.
Anne Steppe, Loan Officer, USDA, Farm Service Agency, Loan Making Division, 1400 Independence Avenue, SW., Stop 0522, Washington, DC 20250-0522; Telephone (202) 690-4017; Electronic mail:
Comments will be summarized and included in the request for Office of Management and Budget approval of the information collection. All comments will also become a matter of public record.
Farm Service Agency, USDA.
Notice and request for comments.
In accordance with the Paperwork Reduction Act of 1995, this notice announces the intent of the Farm Service Agency (FSA) to request an extension of the Office of Management and Budget's (OMB) approval of previously approved information collection which supports FSA, Farm Loan Programs (FLP) loan making and servicing applications. This renewal does not involve any revisions to the program regulations.
Comments on this notice must be received on or before July 2, 2007 to be assured of consideration.
Chuck Ropp, Senior Loan Officer, USDA, FSA, Farm Loan Programs, Program Development and Economic Enhancement Division, 1400 Independence Avenue, SW., STOP 0521, Washington, DC 20250-0521; telephone (202) 680-4008; electronic mail:
These comments should be sent to the Desk Officer for Agriculture, Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 and to Chuck Ropp, USDA, FSA, Farm Loan Programs, Program Development and Economic Enhancement Division, 1400 Independence Avenue, SW., STOP 0521, Washington, DC 20250-0521. Copies of the information collection may be obtained from Chuck Ropp at the above address.
Comments will be summarized and included in the request for OMB approval of the information collection. All comments will also become a matter of public record.
Natural Resources Conservation Service, Department of Agriculture.
Notice of a finding of no significant impact.
Pursuant to section 102(2)(c) of the National Environmental Policy Act of 1969; the Council on Environmental Quality Regulations (40 CFR part 1500); and the Natural Resources Conservation Service Regulations (7 CFR part 650); the Natural Resources Conservation Service, U.S. Department of Agriculture, gives notice that an environmental impact statement is not being prepared for the rehabilitation of Floodwater Retarding Structure No. 15 of the Nolan Creek Watershed, Bell County, Texas.
Salvador Salinas, Acting State Conservationist, Natural Resources Conservation Service, 101 South Main, Temple, Texas 76501-7682, Telephone (254) 742-9800.
The environmental assessment of this federally assisted action indicates that the project will not cause significant local, regional, or national impacts on the environment. As a result of these findings, Salvador Salinas, Acting State Conservationist, has determined that the preparation and review of an environmental impact statement is not needed for this project.
The project will rehabilitate Floodwater Retarding Structure No. 15 to maintain the present level of flood control benefits and comply with the current performance and safety standards.
Rehabilitation of the site will require the dam to be modified to meet current performance and safety standards for a high hazard dam. The modification will consist of raising the top of dam 2.7 feet, installation of an additional principal spillway (30″ hooded inlet type), installation of a foundation drain system along the back toe of the embankment, raising the crest elevation of the auxiliary spillway 0.3 feet and widening the auxiliary spillway 20 feet. The auxiliary spillway will be vegetated and the embankment and auxiliary spillway will be fenced for livestock exclusion. All disturbed areas will be planted to adapted native and/or introduced species. The proposed work will not have a significant affect on any prime farmland, endangered or threatened species, wetlands, or cultural resources.
Federal assistance will be provided under authority of the Small Watershed Rehabilitation Amendments of 2000 (Section 313, Pub. L. 106-472). Total project cost is estimated to be $1,043,600, of which $757,700 will be paid from the Small Watershed Rehabilitation funds and $285,900 from local funds.
The notice of a Finding of No Significant Impact (FONSI) has been forwarded to the Environmental Protection Agency and to various Federal, State, and local agencies and interested parties. A limited number of copies of the FONSI are available to fill single copy requests at the above address. Basic data developed during the environmental assessment are on file and may be reviewed by contacting Salvador Salinas, Acting State Conservationist.
No administrative action on implementation of the proposal will be taken until 30 days after the date of this publication in the
Risk Management Agency, USDA.
Notice and request for comments.
In accordance with the Paperwork Reduction Act of 1995, this notice announces the intention of the Risk Management Agency to request approval for the collection of information in support of the agency's mission under section 522(d) of the Federal Crop Insurance Act to develop and implement risk management tools for producers of agricultural commodities through partnership agreements.
Written comments on this notice will be accepted until close of business, July 2, 2007.
Interested persons are invited to submit written comments to Virginia Guzman, United States Department of Agriculture (USDA), Non-Insurance Programs Branch, Federal Crop Insurance Corporation, Risk Management Agency, 6501 Beacon Drive, Mail Stop 813, Kansas City, MO 64133. Written comments may also be submitted electronically to:
Virginia Guzman at the Kansas City, MO address listed above, telephone (816) 926-6343.
The purpose of this notice is to solicit comments from the public concerning the information collection activities. These comments will help us:
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 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, through use, as appropriate, of automated, electronic, mechanical, or other collection technologies, e.g. permitting electronic submission of responses.
All responses to this notice will be summarized and included in the request for OMB approval. All comments will also become a matter of public record.
The Transportation and Related Equipment Technical Advisory Committee will meet on May 2, 2007, 9:30 a.m., in the Herbert C. Hoover Building, Room 6087B, 14th Street between Pennsylvania & Constitution Avenues, NW., Washington, DC. The Committee advises the Office of the Assistant Secretary for Export Administration with respect to technical questions that affect the level of export controls applicable to transportation and related equipment or technology.
1. Welcome and Introductions.
2. Conduct Election of New Chairman.
3. Status Reports by Category Chairman.
4. Regulation Update.
5. Missile Technology Issues for TRANSTAC.
6. Wassenaar Results and Issues for TRANSTAC.
7. Proposals Consideration and Discussion.
8. Follow-up on Open Action Items.
9. Closing Comments.
The meeting will be open to the public and a limited number of seats will be available. Reservation are not accepted. To the extent time permits, members of the public may present oral statements to the Committee. Written statements may be submitted at any time before or after the meeting. However, to facilitate distribution of public presentation materials to Committee members, the Committee suggests that presenters forward the public presentation materials to Yvette Springer at
For more information contact Ms. Springer on (202) 482-2813.
Import Administration, International Trade Administration, Department of Commerce.
Sheila E. Forbes, Office of AD/CVD Operations, Customs Unit, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue, N.W., Washington, D.C. 20230, telephone: (202) 482-4697.
Each year during the anniversary month of the publication of an antidumping or countervailing duty order, finding, or suspension of investigation, an interested party, as defined in section 771(9) of the Tariff Act of 1930, as amended (the Act), may request, in accordance with section 351.213 (2002) of the Department of Commerce (the Department) Regulations, that the Department conduct an administrative review of that antidumping or countervailing duty order, finding, or suspended investigation.
Not later than the last day of May 2007
In accordance with section 351.213(b) of the regulations, an interested party as defined by section 771(9) of the Act may request in writing that the Secretary conduct an administrative review. For both antidumping and countervailing duty reviews, the interested party must specify the individual producers or exporters covered by an antidumping finding or an antidumping or countervailing duty order or suspension agreement for which it is requesting a review, and the requesting party must state why it desires the Secretary to review those particular producers or exporters.
Please note that, for any party the Department was unable to locate in prior segments, the Department will not accept a request for an administrative review of that party absent new information as to the party's location. Moreover, if the interested party who files a request for review is unable to locate the producer or exporter for which it requested the review, the interested party must provide an explanation of the attempts it made to locate the producer or exporter at the same time it files its request for review, in order for the Secretary to determine if the interested party's attempts were reasonable, pursuant to 19 CFR 351.303(f)(3)(ii).
As explained in
Six copies of the request should be submitted to the Assistant Secretary for Import Administration, International Trade Administration, Room 1870, U.S. Department of Commerce, 14th Street & Constitution Avenue, N.W., Washington, D.C. 20230. The Department also asks parties to serve a copy of their requests to the Office of Antidumping/Countervailing Operations, Attention: Sheila Forbes, in room 3065 of the main Commerce Building. Further, in accordance with section 351.303(f)(l)(i) of the regulations, a copy of each request must be served on every party on the Department's service list.
The Department will publish in the
This notice is not required by statute but is published as a service to the international trading community.
Import Administration, International Trade Administration, Department of Commerce.
Notice of Upcoming Sunset Reviews.
Every five years, pursuant to section 751(c) of the Tariff Act of 1930, as amended, the Department of Commerce (“the Department”) and the International Trade Commission automatically initiate and conduct a review to determine whether revocation of a countervailing or antidumping duty order or termination of an investigation suspended under section 704 or 734 would be likely to lead to continuation or recurrence of dumping or a countervailable subsidy (as the case may be) and of material injury.
The following Sunset Review is scheduled for initiation in June 2007 and will appear in that month's Notice of Initiation of Five-Year Sunset Reviews.
The Department's procedures for the conduct of Sunset Reviews are set forth in 19 CFR 351.218. Guidance on methodological or analytical issues relevant to the Department's conduct of Sunset Reviews is set forth in the Department's Policy Bulletin 98.3--Policies Regarding the Conduct of Five-Year (“Sunset”) Reviews of Antidumping and Countervailing Duty Orders; Policy Bulletin, 63 FR 18871 (April 16, 1998) . The Notice of Initiation of Five-Year (“Sunset”) Reviews provides further information regarding what is required of all parties to participate in Sunset Reviews.
Pursuant to 19 CFR 351.103(c), the Department will maintain and make available a service list for these proceedings. To facilitate the timely preparation of the service list(s), it is requested that those seeking recognition as interested parties to a proceeding contact the Department in writing within 15 days of the publication of the Notice of Initition.
Please note that if the Department receives a Notice of Intent to Participate from a member of the domestic industry within 15 days of the date of initiation, the review will continue. Thereafter, any interested party wishing to participate in the Sunset Review must provide substantive comments in response to the notice of initiation no later than 30 days after the date of initiation.
This notice is not required by statute but is published as a service to the international trading community.
Import Administration, International Trade Administration, Department of Commerce.
In accordance with section 751(c) of the Tariff Act of 1930, as amended (“the Act”), the Department of Commerce (“the Department”) is automatically initiating a five-year review (“Sunset Review”) of the antidumping duty order listed below. The International Trade Commission (“the Commission”) is publishing concurrently with this notice its notice of
May 1, 2007.
Juanita Chen, AD/CVD Operations, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street & Constitution Ave., NW, Washington, DC 20230; telephone: (202) 482-1904. For information from the Commission, contact Mary Messer, Office of Investigations, U.S. International Trade Commission at (202) 205-3193.
The Department's procedures for the conduct of Sunset Reviews are set forth in its
In accordance with 19 CFR 351.218(c), we are initiating the Sunset Review of the following antidumping duty order:
As a courtesy, we are making information related to Sunset proceedings, including copies of the Department's regulations regarding Sunset Reviews (19 CFR 351.218) and
Pursuant to 19 CFR 351.103(c), the Department will maintain and make available a service list for these proceedings. To facilitate the timely preparation of the service list(s), it is requested that those seeking recognition as interested parties to a proceeding contact the Department in writing within 10 days of the publication of this notice of initiation.
Because deadlines in Sunset Reviews can be very short, we urge interested parties to apply for access to proprietary information under administrative protective order (“APO”) immediately following publication in the
Domestic interested parties (defined in section 771(9)(C), (D), (E), (F), and (G) of the Act and 19 CFR 351.102(b)) wishing to participate in these Sunset Reviews must respond not later than 15 days after the date of publication in the
If we receive an order-specific notice of intent to participate from a domestic interested party, the Department's regulations provide that
This notice of initiation is being published in accordance with section 751(c) of the Act and 19 CFR 351.218(c).
Import Administration, International Trade Administration, Department of Commerce.
May 1, 2007.
Thomas Martin or Mark Manning at (202) 482-3936 or (202) 482-5253, respectively; AD/CVD Operations, Office 4, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue, NW, Washington, DC 20230.
On July 27, 2006, the Department of Commerce (the Department) initiated an administrative review of the antidumping duty order on chlorinated isocyanurates from Spain, for the period December 20, 2004, to May 31, 2006.
Section 751(a)(3)(A) of the Tariff Act of 1930, as amended (the Act) and 19 CFR 351.213(h)(1) require the Department to issue the preliminary results of an administrative review within 245 days after the last day of the anniversary month of the order for which the administrative review was requested, and the final results of the review within 120 days after the date on which the notice of the preliminary results was published in the
The preliminary results were originally due on March 2, 2007. On February 16, 2007, the Department partially extended the preliminary results of the administrative review, to June 1, 2007.
This notice is issued and published in accordance with sections 751(a)(3)(A) and 777(i)(1) of the Act.
Import Administration, International Trade Administration, Department of Commerce.
On March 21, 2007, the Department of Commerce (the “Department”) published in the
May 1, 2007.
Julia Hancock, AD/CVD Operations, Office 9, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW, Washington, DC 20230; telephone: (202) 482-1394.
On March 21, 2007, the Department published the
On March 19, 2007, QVD and the Catfish Farmers of America and individual U.S. catfish processors (“Petitioners”) filed timely allegations that the Department made various ministerial errors in the
The product covered by this order is frozen fish fillets, including regular, shank, and strip fillets and portions thereof, whether or not breaded or marinated, of the species
The subject merchandise will be hereinafter referred to as frozen “basa” and “tra” fillets, which are the Vietnamese common names for these species of fish. These products are classifiable under tariff article codes 1604.19.4000
A ministerial error is defined in section 751(h) of the Act and further clarified in 19 CFR 351.224(f) as “an error in addition, subtraction, or other arithmetic function, clerical error resulting from inaccurate copying, duplication, or the like, and any other similar type of unintentional error which the Secretary considers ministerial.”
After analyzing all interested parties' comments, we have determined, in accordance with 19 CFR 351.224(e), that ministerial errors existed in the calculations for QVD in the
Therefore, in accordance with section 751(h) of the Act and 19 CFR 351.224(e), we are amending the
The Department shall determine, and U.S. Customs and Border Protection shall assess, antidumping duties on all appropriate entries based on the amended final results. For details on the assessment of antidumping duties on all appropriate entries,
These amended final results are published in accordance with sections 751(h) and 777(i)(1) of the Act.
Import Administration, International Trade Administration, Department of Commerce.
May 1, 2007.
Salim Bhabhrawala at (202) 482-1784, AD/CVD Operations, Office 1, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue, NW, Washington, DC 20230.
On September 29, 2006, the Department of Commerce (the Department) published a notice of initiation of administrative review of the antidumping duty order on granular polytetrafluoroethylene resin from Italy.
Pursuant to section 751(a)(3)(A) of the Tariff Act of 1930, as amended (the Act), the Department shall make a preliminary determination in an administrative review of an antidumping order within 245 days after the last day of the anniversary month of the date of publication of the order. The Act further provides, however, that the Department may extend the 245-day period to 365 days if it determines it is not practicable to complete the review within the foregoing time period. We determine that it is not practicable to complete this administrative review within the time limits mandated by section 751(a)(3)(A) of the Act because this review involves a number of complicated issues (
Accordingly, the Department is extending, by 71 days, the time limit for completion of the preliminary results of this administrative review until no later than July 13, 2007. We intend to issue the final results no later than 120 days after the publication of the preliminary results notice.
This extension is in accordance with section 751(a)(3)(A) of the Act and 19 CFR 351.213(h)(2).
Import Administration, International Trade Administration, Department of Commerce.
May 1, 2007.
The Department of Commerce (the Department) hereby publishes a list of scope rulings completed between January 1, 2007, and March 31, 2007. In conjunction with this list, the Department is also publishing a list of requests for scope rulings and anticircumvention determinations pending as of March 31, 2007. We intend to publish future lists after the close of the next calendar quarter.
Irina Itkin, AD/CVD Operations, Office 2, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue, NW, Washington, DC 20230; telephone: (202) 482-0656.
The Department's regulations provide that the Secretary will publish in the
Interested parties are invited to comment on the completeness of this list of pending scope and anticircumvention inquiries. Any comments should be submitted to the Deputy Assistant Secretary for AD/CVD Operations, Import Administration, International Trade Administration, 14th Street and Constitution Avenue, NW, Room 1870, Washington, DC 20230.
This notice is published in accordance with 19 CFR 351.225(o).
Commodity Futures Trading Commission.
Notice of new system of records.
This notice adds a new system of records to the Commission's systems of records under the Privacy Act of 1974, Public Law 93-579, 5 U.S.C. 552a. The visitor information system contains information provided by visitors to the agency. The visitor provides identification, in the form of a driver's license, passport, or Federal/Military ID. The company affiliation of the visitor will also be requested. This information is scanned and linked to the name and office phone number of the CFTC employee sponsoring the visit, along with information on the location of the visit, time of entry, purpose of the visit, and the number of the badge issued to the visitor. The purpose of the information collection is to enhance the security of CFTC employees and property by verifying the identity of visitors, and to track the location of the visitor so that, in the event of an emergency, the agency can account for all the people in its space. Records in the visitor system will be retained for three months and then purged.
Comments on the establishment of the new system of records must be received no later than May 31, 2007. The new system of records will be effective June 11, 2007 unless the Commission receives comments which would result in a contrary determination.
Comments should be addressed to Eileen Donovan, Acting Secretary, Commodity Futures Trading Commission, Three Lafayette Centre, 1155 21st St., NW., Washington, DC 20581. Comments may be sent via electronic mail to
Tamrah Semega, Office of the Executive Director, Office of Management Operations (202) 418-5155, Commodity
In accordance with the Privacy Act of 1974, 5 U.S.C. 552a, and the Commission's implementing regulations, 17 CFR part 146, the Commission is publishing a description of a new system of records. The new system contains records related to visitors to the Commission.
The new system of records, as required by 5 U.S.C. 552a(r) of the Privacy Act, will be submitted to the Committee on Government Oversight and Reform of the U.S. House of Representatives, the Committee on Governmental Affairs of the U.S. Senate, and the Office of Management and Budget, pursuant to Appendix I to OMB Circular A-130, “Federal Agency Responsibilities for Maintaining Records About Individuals,” dated February 20, 1996 (61FR6435). Accordingly, the Commission is giving notice of the establishment of the following system of records:
Visitor Information System.
The system is located in the Office of the Executive Director, Office of Management Operations, Commodity Futures Trading Commission, Three Lafayette Centre, 1155 21st Street, NW., Washington, DC 20581.
Visitors to the CFTC.
Information from personal identity records, such as driver's license, passport, or Federal/Military ID; the number of the printed badge issued; location, date, and time of entry; company affiliation of visitor; name and phone number of the employee visited; and the purpose of the visit.
The Federal Property and Administrative Services Act of 1949 (63 Stat. 377), as amended; Homeland Security Presidential Directive 12 (HSPD-12), Policy for a Common Identification Standard for Federal Employees and Contractors, August 27, 2004.
The purpose of this information is to verity the identify of visitors in order to protect the employees and property of the Commission, verify that visitors entering the property are authorized to do so, and track the time, date, and location of the visitor so that, in the event of emergency, the agency can account for all the people in its space.
Information in this system may be disclosed in accordance with the General Statement of Routine Uses.
Computer records are stored in a stand-alone database. Paper reports from the system are kept in a locked file.
By date, and by visitor name.
In addition to general building security, access to the visitor database is protected by password. The system, as a stand-alone database, is not accessible through the CFTC network. Reports are kept in a locked file with limited key access.
Records will be retained for three months and then purged.
Tammy Semega, Deputy Director, Office of the Executive Director, Office of Management Operations, Commodity Futures Trading Commission, Three Lafayette Centre, 1155 21st Street, NW., Washington, DC 20581.
Individuals seeking to determine whether this system of records contains information about themselves, or seeking access to records about themselves in the system of records, or contesting the content of records about themselves contained in this system of records should address written inquiry to the FOI Privacy and Sunshine Acts Compliance Staff, Commodity Futures Trading Commission, Three Lafayette Centre, 1155 21st Street, NW., Washington, DC 20581.
The individual on whom the record is maintained.
Department of the Army, DoD.
Notice of intent.
The United States Army Reserve (USAR) will prepare an EIS to analyze the impacts of a real property exchange. This Real Property Exchange Program is conducted under the authority of 10 U.S.C. 18240, as amended. This legislation permits DoD to convey certain real property assets of reserve components to a State, local government, local authority, or private parties in exchange for land and real property improvements, existing and/or to be constructed, including utilities, equipment, and furnishings for the replacement facilities. Approximately 10 acres with two, two-story USAR Center buildings (Holderman and Munemori Halls) and a detached maintenance building will be exchanged for new construction or real property improvements at the USAR facilities located at (1) Bell; (2) Miramar Marine Corps Air Station, located in San Diego; and (3) March USAR Center located in Riverside. The exchange property being offered by the Federal Government for development by the private sector is located at the Southeast corner of Wilshire Boulevard and Federal Avenue in the Southwestern portion of Los Angeles County and is approximately 13 miles west of downtown Los Angeles. The parcel is bounded on all sided by the city of Los Angeles, and is centrally located in the western part of Los Angeles County. It is immediately surrounded by the communities of Westwood, Brentwood, Sawtelle, and West Los Angeles, which are all part of the city of Los Angeles. Additionally, Santa Monica, Beverly Hills, and Pacific Palisades are all within 5 miles of the subject property. The EIS will discuss in detail the 10-acre parcel to be exchanged and all reasonable alternatives including, but not limited to, the (1) No Action Alternative and (2) Army Exchange with Non-Governmental Development alternatives on the exchanged property. New construction or real property improvements that will occur at the three USAR facilities will be covered by separate National Environmental Policy Act (NEPA) documentation.
Patricia Ryan at (562) 795-2356 or by e-mail at
An EIS will be prepared in accordance with NEPA to address any environmental or socioeconomic impacts associated with the real property exchange. The EIS will examine a wide range of resource areas, including, but not limited to, land use, air quality, traffic, noise, biological resources, cultural resources, socioeconomics, utilities, hazardous and toxic substances, and cumulative environmental effects. Air quality and traffic effects are believed at this time to be the areas with greatest potential for impact.
All reasonable alternatives, including a No Action Alternative (as required by NEPA), will be developed and analyzed in the EIS. The range of alternatives will include several redevelopment scenarios. During the scoping process, other alternatives may be developed for consideration. The EIS will analyze each alternative's impact on the natural and cultural environments at the West Los Angeles facility and the surrounding area. Mitigation measures will also be considered in the EIS.
Tribal, federal, state and local agencies, and the public are invited to participate in the scoping process for the preparation of the EIS. The scoping process will help identify additional possible alternatives, potential environmental impacts, and key issues of concern to be analyzed in the EIS. Scoping meetings will be held in convenient locations near the West Los Angeles facility. Notification of the times and locations for the scoping meetings will be published in local newspapers. To ensure scoping comments are fully considered in the draft EIS, comments and suggestions should be received within the 30-day scoping period.
Department of the Army, U.S. Army Corps of Engineers, DOD.
Notice of intent.
In accordance with the National Environmental Policy Act (NEPA), the Baltimore District, U.S. Army Corps of Engineers (USACE), will conduct a review of the 1990
Questions about the proposed DEIS with integrated feasibility report can be addressed to Mr. Kevin Luebke, U.S. Army Corps of Engineers, ATTN: CENAB-PL-P, 10 South Howard Street, P.O. Box 1715, Baltimore, MD 21203-1715, telephone 410-962-6141; e-mail address:
USACE is conducting this review in partnership with the Maryland Department of Natural Resources (DNR). The 1990 study evaluated erosive conditions along the Chesapeake Bay shoreline where publicly owned property and/or infrastructure were threatened. The 1990 study also investigated sources of sediment from shoreline that contribute to shoaling of public navigation channels.
Several efforts have been completed to date in the review. Conditions of the Maryland shoreline have been inventoried by the Virginia Institute of Marine Science and summary data and maps are now available on the worldwide Web at
Study products will comprise components of a shoreline management master plan DNR and MDE are developing for the state of Maryland. The master plan would address issuance of stabilization permits for shoreline property owners, shoreline habitat restoration and conservation, and coastal flood and erosion hazard reduction. The USACE EIS and integrated feasibility report will provide an overview of the master plan and include environmental compliance documentation for specific projects USACE may pursue. Projects to be pursued independently by others would require separate environmental compliance efforts to be undertaken by other agencies and organization.
The study will be conducted in compliance with Sections 401 and 404 of the Clean Water Act, Section 7 of the Endangered Species Act, the Clean Air Act, the U.S. Fish and Wildlife Coordination Act, Section 106 of the National Historic Preservation Act, Prime and Unique Farmlands, the Magnuson-Stevens Fishery Conservation and Management Act, and the National Pollutant Discharge Elimination System Act. All appropriate documentation (
It is expected that public release of the DEIS and integrated feasibility report will occur in Summer 2009.
Office of Fossil Energy, Department of Energy.
Notice of filings.
The owners or operators of twelve baseload electric powerplants have submitted coal capability self-certifications pursuant to section 201 of the Powerplant and Industrial Fuel Use Act of 1978 (FUA) and Department of Energy (DOE) regulations in 10 CFR 501.60, 61.
Copies of self-certification filings are available for public inspection, upon request, in the Office of Electricity Delivery and Energy Reliability, Room 8G-026, Forrestal Building, 1000 Independence Avenue, SW., Washington, DC 20585.
Ellen Russell at (202) 586-9624.
Title II of FUA, as amended (42 U.S.C. 8301
Department of Energy.
Notice of open meeting.
This notice announces a meeting of the Environmental Management Site-Specific Advisory Board (EM SSAB), Hanford. The Federal Advisory Committee Act (Pub. L. No. 92-463, 86 Stat. 770) requires that public notice of this meeting be announced in the
Thursday, June 7, 2007. 9 a.m.-5 p.m. Friday, June 8, 2007. 8:30 a.m.-4 p.m.
Red Lion Hotel Pasco, 2525 North 20th Avenue, Pasco, Washington 99304, Phone: (509) 547-0701, Fax: (509) 544-3908.
Erik Olds, Federal Coordinator, Department of Energy Richland Operations Office, 2440 Stevens Drive, P.O. Box 450, H6-60, Richland, WA 99352; Phone: (509) 372-9130; or E-mail:
Tentative Agenda:
• Discussion of 2009 Budget Advice.
• Office of River Protection Tank Waste Program Path Forward and Logic Diagram.
• River and Plateau Committee Groundwater Flowsheet.
• Worker Compensation Advice.
• Tank Closure and Waste Management Environmental Impact Statement Update.
• Hanford Advisory Board Draft Priorities.
• Demonstration Bulk Vitrification System Update.
Department of Energy.
Notice of open meeting.
This notice announces a meeting of the Environmental Management Site-Specific Advisory Board (EM SSAB), Savannah River Site. The Federal Advisory Committee Act (Pub. L. No. 92-463, 86 Stat. 770) requires that public notice of this meeting be announced in the
Monday, May 21, 2007. 1 p.m.-5 p.m. Tuesday, May 22, 2007. 8:30 a.m.-4 p.m.
Doubletree Hotel, 411 West Bay Street, Savannah, GA 31404.
Gerri Flemming, Office of External Affairs, Department of Energy Savannah River Operations Office, P.O. Box A, Aiken, SC, 29802; Phone: (803) 952-7886.
If needed, time will be allotted after public comments for items added to the agenda and administrative details. A final agenda will be available at the meeting Monday, May 21, 2007.
Take notice that on April 16, 2007, Basin Electric Cooperative filed revised tariff sheets to its non-jurisdictional open-access transmission reciprocity tariff, FERC Electric Tariff, Original Volume No. 1, to comply with paragraph 139 of Order No. 890 and the Commission's April 11, 2007 Order.
Any person desiring to intervene or to protest this filing must file in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211, 385.214). 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 notice of intervention or motion to intervene, as appropriate. Such notices, motions, or protests must be filed on or before the comment date. On or before the comment date, it is not necessary to serve motions to intervene or protests on persons other than the Applicant.
The Commission encourages electronic submission of protests and interventions in lieu of paper using the “eFiling” link at
This filing is accessible on-line at
Centennial Power, Inc. (Centennial Power) filed an application for market-based rate authority, with an accompanying tariff. The proposed market-based rate tariff provides for the sale of energy, capacity and ancillary services at market-based rates. Centennial Power also requested waivers of various Commission regulations. In particular, Centennial
On March 7, 2003, pursuant to delegated authority, the Director, Division of Tariffs and Market Development—West, granted the requests for blanket approval under part 34 (Director's Order). The Director's Order also stated that the Commission would publish a separate notice in the
Notice is hereby given that the deadline for filing protests is May 23, 2007.
Absent a request to be heard in opposition to such blanket approvals by the deadline above, Centennial Power is authorized to issue securities and assume obligations or liabilities as a guarantor, indorser, surety, or otherwise in respect of any security of another person; provided that such issuance or assumption is for some lawful object within the corporate purposes of Centennial Power, compatible with the public interest, and is reasonably necessary or appropriate for such purposes.
The Commission reserves the right to require a further showing that neither public nor private interests will be adversely affected by continued approvals of Centennial Power's issuance of securities or assumptions of liability.
Copies of the full text of the Director's Order are available from the Commission's Public Reference Room, 888 First Street, NE., Washington, DC 20426. The Order may also be viewed on the Commission's Web site at
CMT Fund IX, LLC (CMT) filed an application for market-based rate authority, with an accompanying rate schedule. The proposed market-based rate schedule provides for the sale of energy at market-based rates. CMT also requested waivers of various Commission regulations. In particular, CMT requested that the Commission grant blanket approval under 18 CFR part 34 of all future issuances of securities and assumptions of liability by CMT.
On April 20, 2007, pursuant to delegated authority, the Director, Division of Tariffs and Market Development—West, granted the requests for blanket approval under part 34 (Director's Order). The Director's Order also stated that the Commission would publish a separate notice in the
Notice is hereby given that the deadline for filing protests is May 21, 2007.
Absent a request to be heard in opposition to such blanket approvals by the deadline above, CMT is authorized to issue securities and assume obligations or liabilities as a guarantor, indorser, surety, or otherwise in respect of any security of another person; provided that such issuance or assumption is for some lawful object within the corporate purposes of CMT, compatible with the public interest, and is reasonably necessary or appropriate for such purposes.
The Commission reserves the right to require a further showing that neither public nor private interests will be adversely affected by continued approvals of CMT's issuance of securities or assumptions of liability.
Copies of the full text of the Director's Order are available from the Commission's Public Reference Room, 888 First Street, NE., Washington, DC 20426. The Order may also be viewed on the Commission's Web site at
Take notice that, on April 19, 2007, Gulf South Pipeline Company, LP submitted a compliance filing pursuant to the Commission's order issued March 30, 2007 in Docket No. RP07-179, Gulf South Pipeline Company, LP, 118 FERC ¶ 61,262 (2007).
Gulf South states that copies of the filing were served on parties on the official service list in the above-captioned proceeding.
Any person desiring to protest this filing must file in accordance with Rule 211 of the Commission's Rules of Practice and Procedure (18 CFR 385.211). Protests to this filing 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. Such protests must be filed in accordance with the provisions of § 154.210 of the Commission's regulations (18 CFR 154.210). Anyone filing a protest must serve a copy of that document on all the parties to the proceeding.
The Commission encourages electronic submission of protests in lieu of paper using the “eFiling” link at
This filing is accessible on-line at
Take notice that on April 19, 2007, Northern Natural Gas Company (Northern), tendered for filing in its FERC Gas Tariff, Fifth Revised Volume No. 1, Ninth Revised Sheet No. 146, to become effective May 20, 2007.
Any person desiring to intervene or to protest this filing must file in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). 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 notice of intervention or motion to intervene, as appropriate. Such notices, motions, or protests must be filed in accordance with the provisions of Section 154.210 of the Commission's regulations (18 CFR 154.210). Anyone filing an intervention or protest must serve a copy of that document on the Applicant. Anyone filing an intervention or protest on or before the intervention or protest date need not serve motions to intervene or protests on persons other than the Applicant.
The Commission encourages electronic submission of protests and interventions in lieu of paper using the “eFiling” link at
This filing is accessible on-line at
On April 19, 2007, the Commission issued an order that instituted a proceeding in the above-referenced docket, pursuant to section 206 of the Federal Power Act (FPA), 16 U.S.C. 824e, regarding PJM's allocation of costs for “economic” projects.
The refund effective date in the above-docketed proceedings, established pursuant to section 206(b) of the FPA, will be the date of publication of this notice in the
Project Orange Associates, LLC (Project Orange) filed an application for market-based rate authority, with an accompanying rate schedule. The proposed market-based rate schedule provides for the sale of energy, capacity and ancillary services at market-based rates. Project Orange also requested waivers of various Commission regulations. In particular, Project Orange requested that the Commission grant blanket approval under 18 CFR part 34 of all future issuances of securities and assumptions of liability by Project Orange.
On April 24, 2007, pursuant to delegated authority, the Director, Division of Tariffs and Market Development—West, granted the requests for blanket approval under part 34 (Director's Order). The Director's Order also stated that the Commission would publish a separate notice in the
Notice is hereby given that the deadline for filing protests is May 24, 2007.
Absent a request to be heard in opposition to such blanket approvals by the deadline above, Project Orange is authorized to issue securities and assume obligations or liabilities as a guarantor, indorser, surety, or otherwise in respect of any security of another person; provided that such issuance or assumption is for some lawful object within the corporate purposes of Project Orange, compatible with the public interest, and is reasonably necessary or appropriate for such purposes.
The Commission reserves the right to require a further showing that neither public nor private interests will be adversely affected by continued approvals of Project Orange's issuance of securities or assumptions of liability.
Copies of the full text of the Director's Order are available from the Commission's Public Reference Room, 888 First Street, NE., Washington, DC 20426. The Order may also be viewed on the Commission's Web site at
Rocky Mountain Power, Inc. (Rocky Mountain) filed an application for market-based rate authority, with an accompanying tariff. The proposed market-based rate tariff provides for the sale of capacity and energy at market-based rates. Rocky Mountain also requested waivers of various Commission regulations. In particular, Rocky Mountain requested that the Commission grant blanket approval under 18 CFR part 34 of all future issuances of securities and assumptions of liability by Rocky Mountain.
On September 3, 2004, pursuant to delegated authority, the Director, Division of Tariffs and Market Development—West, granted the requests for blanket approval under part 34 (Director's Order). The Director's Order also stated that the Commission would publish a separate notice in the
Notice is hereby given that the deadline for filing protests is May 23, 2007.
Absent a request to be heard in opposition to such blanket approvals by the deadline above, Rocky Mountain is authorized to issue securities and assume obligations or liabilities as a guarantor, indorser, surety, or otherwise in respect of any security of another person; provided that such issuance or assumption is for some lawful object within the corporate purposes of Rocky Mountain, compatible with the public interest, and is reasonably necessary or appropriate for such purposes.
The Commission reserves the right to require a further showing that neither public nor private interests will be adversely affected by continued approvals of Rocky Mountain's issuance of securities or assumptions of liability.
Copies of the full text of the Director's Order are available from the Commission's Public Reference Room, 888 First Street, NE., Washington, DC 20426. The Order may also be viewed on the Commission's Web site at
Take notice that on April 23, 2007, the Organization of PJM States, Inc., the District of Columbia Public Service Commission; the Indiana Utility Regulatory Commission; the Kentucky Public Service Commission; the Maryland Public Service Commission; the New Jersey Board of Public Utilities; the North Carolina Utilities Commission; the Pennsylvania Public Utility Commission; and the Virginia State Corporation Commission (collectively, Complainants) hereby submit a complaint against PJM Interconnection, L.L.C. (PJM), alleging apparent violations of Attachment M of the PJM Open Access Transmission Tariff with regard to the independence and operation of the PJM Market Monitor and Market Monitoring Unit.
Any person desiring to intervene or to protest this filing must file in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211, 385.214). 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 notice of intervention or motion to intervene, as appropriate. The Respondent's answer and all interventions, or protests must be filed on or before the comment date. The Respondent's answer, motions to intervene, and protests must be served on the Complainants.
The Commission encourages electronic submission of protests and interventions in lieu of paper using the “eFiling” link at
This filing is accessible on-line at
Take notice that the Commission received the following electric corporate filings:
Take notice that the Commission received the following electric rate filings:
Take notice that the Commission received the following electric securities filings:
Take notice that the Commission received the following foreign utility company status filings:
Take notice that the Commission received the following PURPA 210(m)(3) filings:
Any person desiring to intervene or to protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214) on or before 5 p.m. Eastern time on the specified comment date. It is not necessary to separately intervene again in a subdocket related to a compliance filing if you have previously intervened in the same docket. 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. Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant. In reference to filings initiating a new proceeding, interventions or protests submitted on or before the comment deadline need not be served on persons other than the Applicant.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at
Persons unable to file electronically should submit an original and 14 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First St., NE., Washington, DC 20426.
The filings in the above proceedings are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the Web site that enables subscribers to receive e-mail notification when a document is added to a subscribed dockets(s). For assistance with any FERC Online service, please e-mail
Take notice that the following hydroelectric application has been filed with the Commission and is available for public inspection:
a.
b.
c.
d.
e.
f.
g.
h.
i.
All documents (original and eight copies) should be filed with: Secretary, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426.
Comments, protests, and interventions may be filed electronically via the Internet in lieu of paper, see 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's Web site under the “e-Filing” link. The Commission strongly encourages electronic filings. Please include the project number (P-2385-021) on any comments, protests, or motions filed.
The Commission's Rules of Practice and Procedure require all interveners filing a document with the Commission to serve a copy of that document on each person in the official service list for the project. Further, if an intervener files comments or documents with the Commission relating to the merits of an issue that may affect the responsibilities of a particular resource agency, they must also serve a copy of the documents on that resource agency.
j.
k. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site at
l. Individuals desiring to be included on the Commission's mailing list should so indicate by writing to the Secretary of the Commission.
m. Comments, Protests, or Motions to Intervene—Anyone may submit comments, a protest, or a motion to intervene in accordance with the requirements of Rules of Practice and Procedure, 18 CFR 385.210, .211, .214. In determining the appropriate action to take, the Commission will consider all protests or other comments filed, but only those who file a motion to intervene in accordance with the Commission's Rules may become a party to the proceeding. Any comments, protests, or motions to intervene must be received on or before the specified comment date for the particular application.
n. Filing and Service of Responsive Documents—Any filings must bear in all capital letters the title “COMMENTS”, “PROTESTS”, OR “MOTION TO INTERVENE”, as applicable, and the Project Number of the particular application to which the filing refers. Any of the above-named documents must be filed by providing the original and the number of copies provided by the Commission's regulations to: The Secretary, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. A copy of any motion to intervene must also be served upon each representative
o. Agency Comments—Federal, state, and local agencies are invited to file comments on the described application. A copy of the application may be obtained by agencies directly from the Applicant. If an agency does not file comments within the time specified for filling comments, it will be assumed to have no comments. One copy of an agency's comments must also be sent to the Applicant's representatives.
Environmental Protection Agency (EPA).
Notice of adequacy.
In this notice, EPA is notifying the public that we have found that the motor vehicle emissions budgets (MVEBs) for volatile organic compounds (VOC) and oxides of nitrogen (NO
This finding is effective May 16, 2007.
Anthony Maietta, Life Scientist, Criteria Pollutant Section (AR-18J), Air Programs Branch, Air and Radiation Division, United States Environmental Protection Agency, Region 5, 77 West Jackson Boulevard, Chicago, Illinois 60604, (312) 353-8777,
Throughout this document, whenever “we”, “us” or “our” is used, we mean EPA.
Today's notice is simply an announcement of a finding that we have already made. On April 5, 2007, EPA Region 5 sent a letter to the Ohio Environmental Protection Agency stating that the 2009 and 2018 MVEBs for the Columbus and Toledo areas, which were submitted with the 8-hour ozone redesignation request and maintenance plans, are adequate. Receipt of these MVEBs was announced on EPA's transportation conformity website, and no comments were submitted. The finding is available at EPA's conformity Web site:
The adequate 2009 and 2018 MVEBs, in tons per day (tpd), for VOC for Columbus and Toledo are as follows:
The adequate 2009 and 2018 MVEBs, in tons per day (tpd), for NO
Transportation conformity is required by section 176(c) of the Clean Air Act. EPA's conformity rule requires that transportation plans, programs, and projects conform to state air quality implementation plans and establishes the criteria and procedures for determining whether or not they do. Conformity to a State Implementation Plan (SIP) means that transportation activities will not produce new air quality violations, worsen existing violations, or delay timely attainment of the national ambient air quality standards.
The criteria by which we determine whether a SIP's motor vehicle emission budgets are adequate for transportation conformity purposes are outlined in 40 CFR 93.118(e)(4). We have described our process for determining the adequacy of submitted SIP budgets in our July 1, 2004, preamble starting at 69 FR 40038, and we used the information in these resources while making our adequacy determination. Please note that an adequacy review is separate from EPA's completeness review, and it also should not be used to prejudge EPA's ultimate approval of the SIP. Even if we find a budget adequate, the SIP could later be disapproved.
The finding and the response to comments are available at EPA's transportation conformity Web site:
42 U.S.C. 7401-7671 q.
Environmental Protection Agency (EPA).
Notice of meeting.
Pursuant to the Federal Advisory Committee Act, Public Law 92-463, the Environmental Protection Agency, Office of Research and Development (ORD), gives notice of one meeting of the Board of Scientific Counselors (BOSC) Executive Committee.
The meeting will be held on Thursday, May 24, 2007 from 8 a.m. to 5 p.m. and Friday, May 25, 2007 from 8:30 a.m. to 12:45 p.m. All times noted are eastern time. The meeting may adjourn early if all business is finished. Requests for the draft agenda or for making oral presentations at the meeting will be accepted up to 1 business day before the meeting.
The meeting will be held at the Newport Harbor Hotel and Marina, 49 America's Cup Avenue, Newport, Rhode Island 02840. Submit your comments, identified by Docket ID No. EPA-HQ-ORD-2007-0363, by one of the following methods:
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This is not a mailing address. Such deliveries are only accepted during the docket's normal hours of operation, and special arrangements should be made for deliveries of boxed information.
The Designated Federal Officer via mail at: Lorelei Kowalski, Mail Code 8104-R, Office of Science Policy, Office of Research and Development, Environmental Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460; via phone/voice mail at: (202) 564-3408; via fax at: (202) 565-2911; or via e-mail at:
Any member of the public interested in receiving a draft BOSC agenda or making a presentation at the meeting may contact Lorelei Kowalski, the Designated Federal Officer, via any of the contact methods listed in the
Proposed agenda items for the meeting include, but are not limited to: ORD response to recent STAR/GRO report; review/approval of the Human Health Mid-Cycle Draft Report; review/approval of the Safe Pesticides/Safe Products Program Review Draft Report; updates on Mid-Cycle Review Subcommittees for Ecology and Drinking Water; updates on Program Review Subcommittees for Technology for Sustainability, Human Health Risk Assessment, and Homeland Security; updates on Standing Subcommittees for Computational Toxicology, for the National Center for Environmental Research (NCER) and for the National Exposure Research Lab (NERL); an ORD briefing on the National Coastal Condition Report III; and future issues and plans. There will also be a site visit to ORD's Narragansett Lab. The meeting is open to the public.
Federal Deposit Insurance Corporation (FDIC).
Notice and request for comment.
The FDIC, 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 continuing information collections, as required by the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 35). Currently, the FDIC is soliciting comments concerning the following collections of information: Certified Statement for Deposit Insurance Assessment (3064-0057); Student Educational Employment Program (3064-0147); and Complex Structured Finance Transactions (3064-0148).
Comments must be submitted on or before July 2, 2007.
Interested parties are invited to submit written comments by any of the following methods. All comments should refer to the name of the collection:
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A copy of the comments may also be submitted to the OMB Desk Officer for the FDIC, Office of Information and
Steve Hanft (address above).
2.
3.
Comments are invited on: (a) Whether these collections of information are necessary for the proper performance of the FDIC's functions, including whether the information has practical utility; (b) the accuracy of the estimates of the burden of the information collections, including the validity of the methodology and assumptions used; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (d) ways to minimize the burden of the information collections 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 the information.
At the end of the comment period, the comments and recommendations received will be analyzed to determine the extent to which the collections should be modified prior to submission to OMB for review and approval. Comments submitted in response to this notice also will be summarized or included in the FDIC's requests to OMB for renewal of these collections. All comments will become a matter of public record.
Federal Mediation and Conciliation Service.
Notice of OMB Review of Information Collection Forms R-22, R-19, R-43 and F-7 Submitted for Reinstatement and Solicitation of Public Comment.
This notice announces that four information collection requests contained among the Federal Mediation and Conciliation Service (FMCS) agency forms have come up for renewal. Pursuant to the Paperwork Reduction Act of 1995, FMCS has submitted to OMB requests for review of these four FMCS forms: Arbitrator's Report and Fee Statement (Agency Form R-19), Arbitrator's Personal Data Questionnaire (Agency Form R-22), Request for Arbitration Services (Agency Form R-43) and Notice to Mediation Agencies (Agency Form F-7). These requests seek reinstatement of Forms R-19, R-22, and F-7, which expired January 31, 2006, and Form R-43, which expired February 28, 2006, with new expiration dates of three years from the date of OMB approval. FMCS also is soliciting comments on specific aspects of the collections as described below.
Comments must be submitted on or before May 31, 2007.
Submit written comments by mail to the Office of Information and Regulatory Affairs, Human Resources and Housing Branch, Office of Management and Budget, New Executive Office Building, Room 10235, Washington, DC 20503.
Copies of each of the agency forms and the Paperwork Reduction Act Submission to OMB are available from the FMCS Office of Arbitration Services by calling, faxing or writing Vella M. Traynham, Director of Arbitration Services, FMCS, 2100 K Street, NW., Washington, DC 20427. Telephone (202) 606-5111; Fax (202) 606-3749. Please ask for the form by title and agency form number.
FMCS is seeking comments on the following Information Collection Requests (ICRs).
FMCS solicits comments to:
(i) 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.
(ii) Enhance the accuracy of the agency's estimates of the burden of the proposed collection of information.
(iii) Enhance the quality, utility, and clarity of the information to be collected.
(iv) Minimize the burden of the collection of information on those who are to respond, including the use of appropriate automated, electronic collection technologies or other forms of information technology.
This notice corrects a notice (FR Doc. E7-7874) published on pages 20549 and 20550 of the issue for Wedneday, April 25, 2007.
Under the Federal Reserve Bank of San Francisco heading, the entry for Frank W. Yuen, Nassau, Bahamas, is revised to read as follows:
Comments on this application must be received by May 10, 2007.
Board of Governors of the Federal Reserve System, April 25, 2007.
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 Center website at
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 May 25, 2007.
Board of Governors of the Federal Reserve System, April 25, 2007.
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 Center website at
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 May 25, 2007.
Board of Governors of the Federal Reserve System, April 26, 2007.
Federal Trade Commission.
Notice requesting information and comment.
On December 20, 2006, President Bush signed the Postal Accountability and Enhancement Act (“PAEA” or the “Act”) into law. Congress intended the PAEA to increase competition and efficiency in the provision of mail service. The Act requires the Federal Trade Commission (the “Commission or “FTC”) to prepare and submit to the President, Congress, and the Postal Regulatory Commission (“PRC”) a comprehensive report by December 20, 2007, identifying Federal and State laws that apply differently to the United States Postal Service (“USPS”) with respect to the competitive category of mail and to private companies providing similar products. To help prepare this report, the Commission is requesting public comment on several issues.
Public comments must be received on or before July 2, 2007.
Comments should refer to “USPS Study, Project No. P071200” to facilitate the organization of comments. A comment filed in paper form should include this reference both in the text and on the envelope, and the original and two copies should be delivered to the following address: Federal Trade Commission/Office of the Secretary, Room 135-H (Annex F), 600 Pennsylvania Avenue, NW., Washington, DC 20580.
Because paper mail in the Washington area and at the FTC is subject to delay, please consider submitting your comment in electronic form, as prescribed below. Comments containing any material for which confidential treatment is requested, however, must be filed in paper (rather than electronic) form, and the first page of the document must be clearly labeled “Confidential,” and must comply with FTC Rule 4.9(c).
Comments filed in electronic form (except comments containing any confidential material) should be submitted to the FTC by clicking on the following Web link:
The FTC Act and other laws the Commission administers permit the collection of public comments to consider and use in this proceeding as appropriate. All timely and responsive public comments, whether filed in paper or electronic form, will be considered by the Commission and will be available to the public on the FTC Web site, to the extent practicable, at
Requests for additional information should be addressed to James Cooper, Federal Trade Commission, Office of Policy Planning, 600 Pennsylvania Avenue, NW., Washington, DC 20580.
On December 20, 2006, President Bush signed into law the PAEA, which is intended to increase competition and efficiency in the provision of mail service.
With respect to market-dominant products, the Act requires the PRC to establish “a modern system for regulating rates and classes”
The Act further prohibits the USPS, and other Federal agencies acting in concert with it or on its behalf, from engaging in conduct—with respect to any product not covered by the statutory postal monopoly provision—that
The PAEA directs the Commission to prepare and submit to the President, Congress, and the PRC, a comprehensive report “identifying Federal and State laws that apply differently to the [USPS] with respect to the competitive category of mail * * * and to private companies providing similar products.”
Accordingly, to assist with preparing this report, the Commission seeks relevant information concerning the questions that follow. These questions are designed to assist members of the public in focusing their comments, but should not be construed as a limitation on the issues on which public comment may be submitted. To facilitate the consideration of comments, responses to these questions should cite the numbers and subsection of the questions being addressed. All comments submitted should include any relevant data, statistics, or any other evidence upon which the comments are based.
With regard to the following questions “competitive products” refers to (1) priority mail; (2) expedited mail; (3) bulk parcel post; (4) bulk international mail; and (5) mailgrams.
1. With respect to competitive products, please identify specific Federal laws, State laws, and local laws, regulations, ordinances, etc. (collectively, “legal requirements”) with which private competitors must comply, but with which the USPS is not required to comply. Please identify the specific source of the USPS exemption from each such legal requirement. Please provide estimates of both actual expenses, and administrative costs associated with compliance, that such legal requirements impose on private competitors.
2. Please discuss any benefits the USPS derives, in providing competitive services, from its legal monopolies over letter delivery and mailboxes. Specifically, discuss any economies of scope (i.e., cost advantages or other efficiencies that arise due to the provision of multiple products) that exist between the supply of market-dominant products and the supply of competitive products. In what ways, if any, do private suppliers of competitive products interconnect with the USPS system? Do any federal or state laws prevent greater interconnection with the USPS system? If so, please cite these laws and explain the ways in which they prevent greater interconnection.
3. Please identify any additional legal requirements that confer benefits upon the USPS that are not available to its private competitors.
4. With respect to competitive products, please identify specific legal requirements with which the USPS must comply, but with which private competitors are not required to comply, or any other legal constraints on the USPS' operations that affect its costs. Please provide estimates of both actual expenses, and administrative costs associated with compliance, that such legal requirements and constraints impose on the USPS. Can any of these requirements or constraints be addressed apart from changes that would apply to the entire USPS? If so, please identify any requirements or constraints that might be removed only to the extent that they apply to competitive products. What laws would need to be changed to remove these requirements or constraints?
5. Please provide an estimate of how the requirements identified in responses to Question 4 affect the costs that the USPS incurs to provide competitive products, and the prices that the USPS charges for competitive products.
6. Please comment on the costs, benefits, and feasibility of requiring the USPS to account for the cost of complying with the legal requirements identified in responses to Question 1 in the cost of competitive products and in setting prices for competitive products. How should these costs be calculated and allocated between competitive and market-dominant products? Should the USPS be required actually to pay these costs or merely account for them when setting prices? If the USPS actually pays the costs associated with legal requirements, should it be required actually to comply with these legal requirements with respect to competitive products (e.g., pay local property taxes on buildings and vehicles to local governments)? Alternatively, should the USPS be required to pay the costs associated with these legal requirements to the U.S. Treasury or the U.S. Postal Fund?
7. Please describe how the USPS not being required to pay a return on the capital that the federal government contributed toward its competitive operations affects the USPS' costs and prices of competitive products. Should the USPS be required actually to pay a return on the capital that the federal government contributed toward its competitive operations or merely account for such a cost when setting prices for competitive products? How should this return be calculated? How would this cost be allocated between competitive and market-dominant products? Should the USPS be required to pay this return to the U.S. Treasury or to pay this return to the Postal Service Fund?
8. Please describe how the USPS' ability to borrow from the U.S. Treasury at preferential rates as compared with private sector companies affects the USPS' costs and prices of competitive products. How should these borrowing costs be calculated and allocated between competitive and market-dominant products? Should the USPS be required to borrow at commercial rates or should there be another mechanism to equalize this cost differential? If so, how should it be calculated and should it be paid to the U.S. Treasury or the Postal Service Fund?
9. Please discuss the costs, benefits, and feasibility of requiring the USPS explicitly to pay state and local taxes on its competitive operations. How should these costs be calculated and allocated between competitive and market-dominant products? For private sector competitors, please describe and provide the costs associated with filing and paying state and local income,
10. Please discuss the costs, benefits, and feasibility associated with requiring the USPS to establish a separate private entity to provide competitive products. What, if any, scope economies between its market-dominant products and its competitive products would be lost under this scenario? Please cite any relevant examples involving foreign countries in which a state-owned postal service established a separate private entity to provide competitive products.
11. Please discuss any other possible ways of ending the differences in legal requirements between the USPS and its private competitors with respect to the competitive category of mail, including the costs, benefits, and feasibility associated with these other possible approaches.
By direction of the Commission.
General Services Administration and National Nuclear Security Administration, Department of Energy.
Notice of Intent.
The General Services Administration (GSA), as the lead agency, and the National Nuclear Security Administration (NNSA), as a cooperating agency, intend to prepare an Environmental Assessment (EA) to evaluate the potential environmental impacts associated with the following project: Transformation of Facilities and Infrastructure for the Non-Nuclear Production Activities Conducted at the NNSA Kansas City Plant.
The proposed action is for GSA to procure the construction of new facilities to house NNSA's non-nuclear component procurement and manufacturing operations. The new facilities would be located approximately 8 miles south of the existing plant on a currently undeveloped site at the northwest corner of Missouri Highway 150 and Botts Road in Kansas City, Missouri. GSA would lease the facilities to NNSA, which would relocate its non-nuclear operations from the existing Kansas City Plant in the Bannister Federal Complex in Kansas City, Missouri, to the new facilities and conduct future operations in the new facilities. The relocation would involve moving approximately two-thirds of the existing capital and process equipment to the new facilities. Disposition activities of the existing NNSA facilities at the Kansas City Plant are not part of the current proposed action, and will be addressed in appropriate future environmental analyses. The Kansas City Plant is collocated on the Bannister Federal Complex with GSA and disposition activities will require coordination between both agencies.
The proposed facilities would cover more than 1 million square feet and provide over 2,000 surface parking spaces. The current facilities are approximately 3 million square feet. The proposed facilities would meet current and future production requirements for NNSA in a modern, cost effective, and flexible manner through reductions in the current facility footprint while significantly reducing operational, maintenance, security, and energy costs.
The EA also will evaluate the potential environmental impacts associated with alternatives to the proposed action, including:
• No Action,
• Renovate the existing GSA office and warehouse space at the Bannister Federal Complex, relocate NNSA’s non-nuclear operations to the renovated facilities, and conduct future operations in the renovated facilities.
• Renovate the existing GSA office space, demolish existing GSA warehouse space, and construct and operate a new manufacturing facility on the GSA portion of the Bannister Federal Complex.
• Demolish existing GSA office and warehouse space. Construct and operate new office and manufacturing facilities on GSA’s portion of the Bannister Federal Complex.
Concurrent with the preparation of the Environmental Assessment, GSA and NNSA will determine the applicability of floodplain management and wetland protection requirements (10 CFR Part 1022) and will publish a notice of proposed floodplain and/or wetland action as appropriate.
The public scoping meeting is scheduled as follows:
Wednesday, May 23rd, 2007
6:30 p.m. - 9:30 p.m.
Plaza Auditorium
Bannister Federal Complex
1500 East Bannister Road
Kansas City, MO 64131
Enter the Bannister Federal Complex by using Entrance 2, also marked Lydia Entrance, off Bannister Road. Enter the building through GSA Lobby 16. Please bring government-issued photo identification for entry into the building. Oral and written comments will be accepted at the public scoping meeting. In addition, GSA and NNSA will consider all written comments postmarked by May 30, 2007. For further information or to submit written comments please contact:
Carlos Salazar
GSA Regional NEPA Coordinator
1500 East Bannister Road, Room 2191 (6PTA)
Kansas City, MO 64131
(816) 823-2305
NNSA’s non-nuclear operations include the procurement and manufacture of electrical, electronic, electromechanical, plastic, and mechanical components for the nuclear weapons program. Hazardous wastes are generated through general industrial processes and include acidic and
GSA and NNSA believe that the relocation of the non-nuclear production mission to another location outside of the Kansas City Metropolitan Area is not a reasonable alternative and do not intend to analyze it as an alternative in the present EA.
DOE completed a Nuclear Weapons Complex Reconfiguration (Complex-21) Study in January 1991, which identified significant cost savings that could be achieved by downsizing the nuclear weapons complex. On January 27, 1992, the Department issued an NOI (57 FR 3046) to prepare an environmental assessment (DOE/EA-0792) for the consolidation of non-nuclear production activities within the nuclear weapons complex. On September 14, 1993, DOE published a Finding of No Significant Impact (FONSI) regarding its proposal (58 FR 48043) to terminate non-nuclear production missions at the Mound Plant in Ohio, the Pinellas Plant in Florida, and the Rocky Flats Plant in Colorado, and consolidate the electrical and mechanical manufacturing functions at the Kansas City Plant.
DOE issued an NOI on June 6, 1995 (60 FR 31291), a final Stockpile Stewardship and Management PEIS on November 19, 1996 (61 FR 58871), and a ROD on December 26, 1996 (61 FR 68014) announcing its decision to transform the weapons production complex by further downsizing of the nuclear weapons complex. This decision included reducing non-nuclear component fabrication capacity at the Kansas City Plant. In these documents DOE evaluated alternatives for consolidation of non-nuclear manufacturing, storage and surveillance functions of the Nuclear Weapons Complex to the Kansas City Plant and reducing the capacity for non-nuclear component fabrication.
The proposed action would continue the consolidation and downsizing of non-nuclear activities at the Kansas City Plant begun in the early 1990s. The alternatives are constructed around the mission need to maintain the Kansas City Plant while downsizing for cost efficiency. Keeping these activities in the Kansas City area is consistent with NNSA’s broader proposed transformation of the U.S. nuclear weapons complex and is based on the previous NEPA analyses and decisions described above, and on an economic analysis that will be included in the Environmental Assessment. GSA and NNSA invite and will consider comments on this issue during the scoping process.
Separately, NNSA is preparing a Supplement to the Stockpile Stewardship and Management Programmatic Environmental Impact Statement—Complex 2030 (DOE/EIS-0236-S4) that evaluates alternatives for the continued transformation of the nuclear weapons complex. As explained in the NOI for that Supplemental PEIS (71 FR 61731; October 19, 2006), “NNSA believes that it is appropriate to separate the analyses of the transformation of non-nuclear production from the Supplemental PEIS because decisions regarding non-nuclear activities would neither significantly affect nor be affected by decisions regarding the transformation of nuclear production activities.”
Department of Health and Human Services, Office of the Secretary.
Notice.
The Department of Health and Human Services (HHS) seeks nominations of public and private sector organizations to receive the 2007 Innovation in Prevention Awards. This activity seeks to advance President George W. Bush's HealthierUS goal of helping Americans live longer, better, and healthier lives. The statutory authority for this health promotion activity is Section 1703 [42 U.S.C. 300u-2] from Title XVII of the Public Health Service Act. The Innovation in Prevention Awards Initiative will identify and celebrate outstanding organizations that have implemented innovative and creative chronic disease prevention and health promotion programs. To be nominated, a program must address at least one of the following risk categories:
(1) Obesity;
(2) Physical activity; and
(3) Nutrition.
The Department intends that these awards will provide an opportunity to increase public awareness of creative approaches to develop and expand innovative health programs and encourage duplication of successful strategies.
Awards will be given in the following categories:
• Faith-Based and/or Community Initiatives.
• Health Care Delivery.
• Healthy Workplace.
○ Large Employer > 500 employees.
○ Small Employer < 500 employees.
• Non-Profit.
• Public Sector.
• Schools (K-12).
The following criteria will be taken into consideration upon review:
• Creativity/Innovation.
• Leadership.
• Sustainability.
• Replicability.
• Effectiveness (results/outcomes).
• Receipt of other awards or recognition at the national, state, or local level.
Nominations must be received by 5 p.m. EDT on June 29, 2007.
The Department of Health and Human Services is the U.S. government's principal agency for promoting and protecting the health of all Americans. The HHS manages many programs, covering a broad spectrum of health promotion and disease prevention services and activities. Leaders in the business community, State and local government officials, tribes and tribal entities, and charitable, faith-based, and community organizations have expressed an interest in working with the Department to promote healthy choices and behaviors. The Secretary welcomes this interest. With this notice, the Secretary outlines opportunities to identify and celebrate outstanding organizations that have implemented innovative and creative chronic disease prevention and health promotion programs.
Department of Health and Human Services, Office of the Secretary, Office of Public Health and Science, Office on Women's Health.
Notice.
Applications must be received no later than 5 p.m. Eastern Standard Time on July 2, 2007. The application due date requirement in this announcement supersedes the instruction in the OPHS-1 form.
Pre-site visits (if needed): July 23-27, 2007.
Award date: September 1, 2007.
To receive consideration applications must be received by the Office of Grants Management, Office of Public Health and Science (OPHS), Department of Health and Human Services (DHHS) c/o WilDon Solutions, Office of Grants Management Operations Center, 1515 Wilson Blvd., Third Floor, Suite 310, Arlington, VA 22209, Attention Office on Women's Health, Intergenerational.
The Office on Women's Health (OWH) in the Department of Health and Human Services (DHHS) is the Department's focal point for women's health issues, and works to address disparities in research, health care services, and education that negatively effect the health of women. The OWH coordinates women's health efforts within DHHS to eliminate disparities in health status and supports culturally sensitive educational programs that encourage women to take personal responsibility for their own health and wellness. To that end, OWH has established public/private partnerships to address critical women's health issues nationwide. These partnerships are with non-profit community-based, faith-based, and women's service organizations (CBOs, FBOs, WSOs) innovating intergenerational approaches for HIV/AIDS prevention education targeting women disproportionately impacted by HIV/AIDS across the lifespan. African American and Latino women constituted 25 percent of the U.S. female population in 2002, but 81.5 percent of the reported female AIDS cases (65 percent were among African Americans and 16.5 percent were among Hispanics). (1) The number of Asian/Pacific Islanders and American Indian/Alaskan Native women living with AIDS continues to rise, with an approximately 10 percent increase each year over the past 5 years. (2) Women disproportionately impacted by HIV/AIDS are vulnerable for the disease because they lack accurate information about the virus; have low to no condom negotiation skills; are faced with low socioeconomic circumstances; suffer from sexual abuse; struggle with violence and other traumas, and lack information and skills to share sexual health information with other female members in the family. To this end, the Intergenerational Approaches to HIV/AIDS Prevention Education with Women Across the Lifespan Pilot Program intends to: (1) Develop a cross-generational HIV/AIDS prevention education program to establish effective and/or increase communication about sexual health between African American, Native American/American Indian, Hispanic/Latino, and Asian/Pacific Islander women at risk for or living with HIV/AIDS with other female family and/or kinship network members 12+ years old; (2) provide opportunities for African American, Native American/American Indian, Hispanic/Latino, and Asian/Pacific Islander women and other female members of the family 12+ years old to know their serostatus; and 3) address the age-, gender-, cultural-, spiritual-, and language-specific needs of African American, Native American/American Indian, Hispanic/Latino, and Asian/Pacific Islander women and other female members of the family 12+ years old regarding their sexual health issues, particularly HIV/AIDS prevention so they may decrease their risks for disease.
This program builds on Minority AIDS Initiative- and Office on Women's Health-funded Women and HIV/AIDS Programs (
(1) The OWH is the lead for this program and will be responsible for project officer duties.
(2) The following DHHS agencies and offices have agreed to establish a collaborative partnership:
• Office on Women's Health (OWH), OPHS.
• Substance Abuse Mental Health Services Administration (SAMHSA).
• Office of HIV/AIDS Policy (OHAP), OPHS.
• Indian Health Service (IHS).
• Administration on Aging (AOA).
• Office of Population Affairs (OPA).
• Administration for Children and Families (ACF).
• Center for Faith-Based Community Initiatives (CFBCI).
Together these agencies agree to recruit technical review panelists to evaluate grant proposals; make presentations during the orientation meetings; provide advice and materials during the program year; provide advice during quarterly project monitoring teleconferences; and serve as site evaluation team members and/or assist in development of site evaluation form.
This program is authorized by 42 U.S.C. 300u-2(a).
The purpose of the Intergenerational Approaches to HIV/AIDS Prevention Education with Women Across the Lifespan Pilot Program is to develop cross-generational HIV/AIDS prevention education approaches specific to women at risk for or living with HIV/AIDS and other female members of the family 12+ years old, particularly African American, Native American/American Indian, Hispanic/Latino, and Asian/Pacific Islander women from the Diaspora who are grandmothers, mothers, daughters, granddaughters, and aunts. The goals of the program are:
• To teach cross-generations of women and other female members of the family 12+ years old how to develop healthy communication patterns built on caring, trusting familial relationships; and
• Equip women to share accurate information about their sexual health issues with other female members of the family 12+ years old by incorporating gender-focused, age-specific, culturally competent, and linguistically-appropriate HIV/AIDS prevention information.
The objectives of the program are for African American, Native American/American Indian, Hispanic/Latino, and Asian/Pacific Islander women and other
• Know their serostatus;
• Increase their knowledge of HIV/AIDS prevention;
• Gain competencies in cross-generational communications about health in general and sexual health specifically; and
• Connect with a primary healthcare physician (and navigate other systems of care).
In order to achieve the objectives of the program, the grantee shall:
A. During months 1-5 (start-up phase):
1. Attend the OWH Grantee Orientation Meeting. It will be conducted by OWH and DHHS Collaborating Partners (OHAP, IHS, AOA, OPA, ACF, and CFBCI).
2. Clinical Staff and Specialized Training.
a. Licensed female behavioral health therapist (such as Social Worker, Psychologist, Counselor) with expertise in counseling women and other female members of the family 12+ years old most vulnerable for acquiring HIV/AIDS,
b. Request local health department to conduct in-service training on how to establish a review process for conducting a local program evaluation to measure whether goals and objectives are met.
3. Complete program development, including but not limited to the following activities:
a. Complete development of training modules, assessment tools, and protocols necessary to present an intergenerational approach for HIV/AIDS prevention education to reach African American, Native American/American Indian, Hispanic/Latino, or Asian/Pacific Islander women at risk for or living with HIV/AIDS and other female members of the family 12+ years old that reflects: (Note: Grantee must reach only
• The cultural, spiritual, and/or ritual factors that bridge traditional and American mores and values for women at risk for or living with HIV/AIDS, especially African American; Native American/American Indian, Hispanic/Latino, and Asian/Pacific Islander; and,
• Evidence-based (domestic only) HIV/AIDS prevention education curricula designed to reach women at risk for or living with HIV/AIDS and other female members of the family 12+ years old.
b. With adapted tools from local health department, develop the local program evaluation to measure whether the program goals and objectives are met.
4 Recruit a Team of Consumers to give feedback on what works best during all phases of program development and implementation.
5. Recruit community stakeholders with the following roles:
a. Provide HIV testing opportunities for focus group participants (and consumer advisory team)
b. Provide age-specific referral services via scheduled weekly appointments for women at risk for or living with HIV/AIDS and other female members of the family 12+ years old to receive counseling services from a licensed female behavioral health therapist with expertise in counseling women and other female members of the family 12+ years old most vulnerable for acquiring HIV/AIDS, e.g. counseling to address fear, stigma, abuse, and other areas of need that prevent participants from practicing healthy behaviors.
Therapist legally required to uphold “duty to warn” participants in instances presenting imminent harm or danger, such as statutory rape, intimate partner violence, suicide, etc.
6. Recruit women at risk for or living with HIV/AIDS to participate in focus groups to:
• Identify gender-focused concerns of women most vulnerable for acquiring HIV/AIDS to be included in curriculum;
• Identify age- and culturally-specific barriers to effective cross-generational communication for each women and other female members of the family 12+ years old disproportionately impacted by HIV/AIDS, for instance, African American, Native American/American Indian, Hispanic/Latino, and Asian/Pacific Islander women from the Diaspora;
• Adult minority women participants to develop strategies for recruiting other female members of the family 12+ years old;
• Participate in small group piloting of the training;
• Provide entry to untapped venues to recruit additional participants;
• Recruit age-appropriate peer support group leaders;
• Recruit peers to get tested for HIV; and
• Recruit peers to participate in program.
7. Submit:
a. Four abstracts for workshop and/or poster presentations at one national HIV/AIDS conference targeting public health professionals;
b. Four abstracts for one community conference attracting an audience of consumers.
8. Require all program staff, consultants, and volunteers to attend OWH site evaluation visit.
9. Identify twenty funding opportunities and submit four applications.
10. Before start-up phase ends, recruit African American, Native American/American Indian, Hispanic/Latino, and Asian/Pacific Islander women at risk for or living with HIV/AIDS in places where they naturally gather both as a family and individually, including but not limited to:
• Churches and other places of worship
• Alumni associations of academic institutions for higher learning
• Women's professional organizations/social organizations
• PTA meetings
• Commercial fitness centers
• Beauty centers
• English as a Second Language (ESL) courses
• Conferences
• Sporting events
• Supermarkets
11. Submit OWH initial progress report.
B. During months 6-8 (pilot-test phase 1):
1. Pilot-test program and make program adaptations.
a. Professional counseling services to be offered to participants by a licensed female behavioral health therapist (such as Social Worker, Psychologist, Counselor) with expertise in counseling women and other female members of the family 12+ years old most vulnerable for acquiring HIV/AIDS,
b. Offer peer group support to program participants.
c. Review and measure success of meeting goals and objectives to-date.
2. Convene scheduled meetings for the:
a. Team of Consumers
b. Community stakeholders
3. Require program participants, Team of Consumers, and community
4. Receive confirmation for (2) conference presentations.
5. Submit four applications to federal and non-federal funding sources.
6. Submit OWH mid-year progress report.
C. During months 9-12 (pilot phase 2)
1. Conduct program with adaptations finalized from pilot phase 1:
a. Professional counseling services to be offered to participants by a licensed female behavioral health therapist (such as Social Worker, Psychologist, Counselor) with expertise in counseling women and other female members of the family 12+ years old most vulnerable for acquiring HIV/AIDS,
b. Offer peer group support to program participants.
2. Convene final meetings for the:
a. Team of Consumers
b. Community stakeholders.
3. Review the success of meeting program goals and objectives.
4. Conduct one presentation (workshops, panels, posters) on the program at a national HIV/AIDS prevention conference targeting public health professionals.
5. Conduct one presentation (workshops, panels, posters) on the program at one community conference targeting consumers.
6. Submit four applications to federal and non-federal funding sources.
7. Submit OWH final progress report.
8. Submit OWH annual report.
Under this announcement, the Office on Women's Health (OWH) anticipates making four cooperative agreement awards. Approximately $1,200,000 is available to make four awards of up to $300,000 each. It is expected that the award will cover costs for the period of September 1, 2007 through August 31, 2008. Funding estimates may change.
The Federal Government (Project Officer) will:
A. Conduct an orientation meeting for the grantees (with other federal partners) within the first 8 weeks of the funding period.
B. Conduct at least one site evaluation visit (with DHHS Collaborative Partners) that may include observation of program during pilot or implementation phase.
C. Conduct quarterly project monitoring teleconferences (with DHHS Collaborative Partners).
D. Review all quarterly, final, and annual progress reports.
E. Review timeline and implementation plan.
Eligible entities may include: non profit community-based organizations, faith-based organizations, national organizations, colleges and universities, clinics and hospitals, research institutions, State and local government agencies, tribal government agencies and tribal/urban Indian organizations.
Cost sharing and matching funds is not a requirement of this grant.
1.
2.
• Describe the applicant's record of success in providing HIV/AIDS prevention education, support services, and/or other services (
• Describe the applicant's current HIV/AIDS prevention education, support services, and/or other services for the women at risk for or living with HIV/AIDS served by the agency.
• Give details on the barriers to cross-generational communication between grandmothers, mothers, daughters, aunts, and other female members of the family 12+ years old citing the impact of age, culture, traditions, and spirituality, as well as any trends or shifts in these areas.
• Clearly define the women at risk for or living with HIV/AIDS to be reached by giving demographic and HIV/AIDS data covering the applicant's local service area and State (must cite all data from credible sources only).
• Describe the applicant's work utilizing Teams of Consumers for feedback, in such cases where consumer feedback assisted in the design of new programs or making program adaptations that better meet the needs of those to be served.
• Describe in detail any focus groups convened by the agency to reach women at risk for or living with HIV/AIDS, including demographic information, focus group leadership, number of participants, number of sessions, topics for each session, participant age range, and outcomes of the focus groups.
• Describe the applicant's knowledge and/or experience with evidence-based HIV/AIDS prevention education curricula for women at risk for or living with HIV/AIDS in America. Cite your sources.
• Provide a timeline for start-up, two piloting phases, and the proposed intergenerational approach for HIV/AIDS prevention education with a description of the demographics for women at risk for or living with HIV/AIDS and other female members of the family 12+ years old to be reached.
• Provide a draft Plan of Action that links the applicant's timeline with delineated tasks to be accomplished over the three phases of the program.
• Give a detailed description of the participation of applicant in existing community collaborative efforts. Include information on the purpose for collaboration; goals and objectives; names and complete contact information for partners; roles of each partner; timeline; challenges; corrective actions; and achievements.
• Describe the applicant's competency or needs to build skills in reviewing whether program goals and objectives are met during all phases of the funding period.
• Describe the process for determining whether program goals and objectives are met during all phases of the funding period.
The Project Summary and Project Narrative must not exceed a total of 25 double-spaced pages. The appendices
A. Provide a preliminary assessment of the HIV/AIDS prevention and support service needs for women at risk for or living with HIV/AIDS to be reached in this program. The assessment must be an age-specific demographic and service need profile for African American, Native American/American Indian, Hispanic/Latino, or Asian/Pacific Islander women disproportionately impacted by HIV/AIDS and other female members of the family 12+ years old in your local service area and State (cite data from credible sources only).
B. Describe issues or challenges that impact African American, Native American/American Indian, Hispanic/Latino, or Asian/Pacific Islander women at risk for or living with HIV/AIDS to be able to have effective cross-generational communication about: (1) Their own sexual health issues; and (2) the health of female family or kinship network members 12+ years old about:
• Understanding a woman's body and how to care for it over the lifespan;
• Knowledge of ways to enhance health;
• Building and/or maintaining healthy relationships that include an understanding of health threats;
• Awareness of a primary healthcare system and how to access it;
• Skills to express feelings and concerns about one's sexual health issues to other female family or kinship network members 12+ years old;
• Awareness and ability to insure physical safety when threatened by sexual, physical, or emotional violence.
A. State goals for achieving the intended purpose of the proposed Intergenerational Approaches to HIV/AIDS Prevention Education with Women Across the Lifespan Pilot Program: to develop a cross-generational HIV/AIDS prevention education approach specific to women at risk for or living with HIV/AIDS and other female members of the family 12+ years old, particularly African American women, Native American/American Indian, Hispanic/Latino, and Asian/Pacific Islander women from the Diaspora who are grandmothers, mothers, daughters, granddaughters, and aunts.
B. State quantifiable objectives for the number of African American, Native American/American Indian, Hispanic/Latino, or Asian/Pacific Islander women at risk for or living with HIV/AIDS and other female members of the family 12+ years old to be reached for the proposed program.
C. Give a detailed Plan of Action and timeline covering:
• Start-up phase activities;
• First pilot phase activities; and
• Second pilot phase activities.
A. Key project staff, volunteer, and student interns; their resumes; and a staffing chart for budgeted staff.
B. To-be-hired staff and their qualifications, including but not limited to a contractual services of a licensed female behavioral health therapist with expertise in counseling African American, Native American/American Indian, Hispanic/Latino, and Asian/Pacific Islander women at risk for or living with HIV/AIDS and other female members of the family 12+ years old.
C. Staff, consultant/sub-contractor, volunteer, and student intern responsibilities.
D. Management oversight of staff roles and job performance.
E. Address maintenance of confidentiality, ethics in performance, and any mandatory in-service staff training.
A. Indicators that reflect goals/objectives are being met.
B. Indicators of any trends.
C. Indicators of any unanticipated outcomes.
A. Required Forms (Assurance of Compliance Form, etc.).
B. Key Staff Resumes.
C. Charts/Tables (target population demographics, gaps in services, etc.).
D. Other attachments.
3.
The OPHS provides multiple mechanisms for the submission of applications, as described in the following sections. Applicants will receive notification via mail from the OPHS Office of Grants Management confirming the receipt of applications submitted using any of these mechanisms. Applications submitted to the OPHS Office of Grants Management after the deadlines described below will not be accepted for review. Applications which do not conform to the requirements of the grant announcement will not be accepted for review and will be returned to the applicant.
While applications are accepted in hard copy, the use of the electronic application submission capabilities provided by the Grants.gov and GrantSolutions.gov systems is encouraged. Applications may only be submitted electronically via the electronic submission mechanisms specified below. Any applications submitted via any other means of electronic communication, including facsimile or electronic mail, will not be accepted for review.
In order to apply for new funding opportunities which are open to the
Electronic grant application submissions must be submitted no later than 5 p.m. Eastern Time on the deadline date specified in the
Applications will not be considered valid until all electronic application components, hardcopy original signatures, and mail-in items are received by the Office of Grants Management according to the deadlines specified above. Application submissions that do not adhere to the due date requirements will be considered late and will be deemed ineligible.
Applicants are encouraged to initiate electronic applications early in the application development process, and to submit early on the due date or before. This will aid in addressing any problems with submissions prior to the application deadline.
The Grants.gov Web site Portal provides organizations with the ability to submit applications for OPHS grant opportunities. Organizations must successfully complete the necessary registration processes in order to submit an application. Information about this system is available on the Grants.gov Web site,
In addition to electronically submitted materials, applicants may be required to submit hard copy signatures for certain Program related forms, or original materials as required by the announcement. It is imperative that the applicant review both the grant announcement, as well as the application guidance provided within the Grants.gov application package, to determine such requirements. Any required hard copy materials, or documents that require a signature, must be submitted separately via mail to the OPHS Office of Grants Management, c/o WilDon Solutions, and if required, must contain the original signature of an individual authorized to act for the applicant agency and the obligations imposed by the terms and conditions of the grant award. When submitting the required forms, do not send the entire application. Complete hard copy applications submitted after the electronic submission will not be considered for review.
Electronic applications submitted via the Grants.gov Web site Portal must contain all completed online forms required by the application kit, the Program Narrative, Budget Narrative and any appendices or exhibits. All required mail-in items must be received by the due date requirements specified above. Mail-In items may only include publications, resumes, or organizational documentation. When submitting the required forms, do not send the entire application. Complete hard copy applications submitted after the electronic submission will not be considered for review.
Upon completion of a successful electronic application submission via the Grants.gov Web site Portal, the applicant will be provided with a confirmation page from Grants.gov indicating the date and time (Eastern Time) of the electronic application submission, as well as the Grants.gov Receipt Number. It is critical that the applicant print and retain this confirmation for their records, as well as a copy of the entire application package.
All applications submitted via the Grants.gov Web site Portal will be validated by Grants.gov. Any applications deemed “Invalid” by the Grants.gov Web site Portal will not be transferred to the GrantSolutions system, and OPHS has no responsibility for any application that is not validated and transferred to OPHS from the Grants.gov Web site Portal. Grants.gov will notify the applicant regarding the application validation status. Once the application is successfully validated by the Grants.gov Web site Portal, applicants should immediately mail all required hard copy materials to the OPHS Office of Grants Management, c/o WilDon Solutions, to be received by the deadlines specified above. It is critical that the applicant clearly identify the organization name and Grants.gov Application Receipt Number on all hard copy materials.
Once the application is validated by Grants.gov, it will be electronically transferred to the GrantSolutions system for processing. Upon receipt of both the electronic application from the Grants.gov Web site Portal, and the required hardcopy mail-in items, applicants will receive notification via mail from the OPHS Office of Grants Management confirming the receipt of the application submitted using the Grants.gov Web site Portal.
Applicants should contact Grants.gov regarding any questions or concerns regarding the electronic application process conducted through the Grants.gov Web site Portal.
OPHS is a managing partner of the GrantSolutions.gov system. GrantSolutions is a full life-cycle grants management system managed by the Administration for Children and Families, DHHS, and is designated by the Office of Management and Budget (OMB) as one of the three Government-wide grants management systems under the Grants Management Line of Business initiative (GMLoB). OPHS uses GrantSolutions for the electronic processing of all grant applications, as well as the electronic management of its entire Grant portfolio.
When submitting applications via the GrantSolutions system, applicants are required to submit a hard copy of the application face page (Standard Form 424) with the original signature of an individual authorized to act for the applicant agency and assume the obligations imposed by the terms and conditions of the grant award. If required, applicants will also need to submit a hard copy of the Standard Form LLL and/or certain Program related forms (e.g., Program Certifications) with the original signature of an individual authorized to act for the applicant agency. When submitting the required forms, do not send the entire application. Complete hard copy applications submitted after the electronic submission will not be considered for review.
Electronic applications submitted via the GrantSolutions system must contain all completed online forms required by the application kit, the Program Narrative, Budget Narrative and any appendices or exhibits. The applicant may identify specific mail-in items to be sent to the Office of Grants Management separate from the electronic submission; however these mail-in items must be entered on the GrantSolutions Application Checklist at the time of electronic submission, and must be received by the due date requirements specified above. Mail-In items may only include publications, resumes, or
Upon completion of a successful electronic application submission, the GrantSolutions system will provide the applicant with a confirmation page indicating the date and time (Eastern Time) of the electronic application submission. This confirmation page will also provide a listing of all items that constitute the final application submission including all electronic application components, required hardcopy original signatures, and mail-in items, as well as the mailing address of the OPHS Office of Grants Management where all required hard copy materials must be submitted.
As items are received by the OPHS Office of Grants Management, the electronic application status will be updated to reflect the receipt of mail-in items. It is recommended that the applicant monitor the status of their application in the GrantSolutions system to ensure that all signatures and mail-in items are received.
Applicants who submit applications in hard copy (via mail or hand-delivered) are required to submit an original and two copies of the application. The original application must be signed by an individual authorized to act for the applicant agency or organization and to assume for the organization the obligations imposed by the terms and conditions of the grant award.
Mailed or hand-delivered applications will be considered as meeting the deadline if they are received by the WilDon Solutions, Office of Grants Management Operations Center, 1515 Wilson Boulevard, Third Floor Suite 310, Arlington, VA 22209, on or before 5 p.m. Eastern Time on the deadline date specified in the
4.
Community-based, non-governmental applicants are required to submit, no later than the Federal due date for receipt of the application, the following information to the head of the appropriate state and local health agencies in the area(s) to be impacted: (a) A copy of the face page of the application (SF 424), (b) a summary of the project (PHSIS), not to exceed one page, which provides: (1) A description of the population to be served, (2) a summary of the services to be provided, and (3) a description of the coordination planned with the appropriate state or local health agencies. Copies of the letters forwarding the PHSIS to these authorities must be contained in the application materials submitted to the OWH.
This program is also subject to the requirements of Executive Order 12372 that allows States the option of setting up a system for reviewing applications from within their States for assistance under certain Federal programs. The application kit to be made available under this notice will contain a listing of States that have chosen to set up a review system and will include a State Single Point of Contact (SPOC) in the State for review. Applicants (other than federally recognized Indian tribes) should contact their SPOCs as early as possible to alert them to the prospective applications and receive any necessary instructions on the State process. For proposed projects serving more than one State, the applicant is advised to contact the SPOC in each affected State. A complete list of SPOCs may be found at the following Web site:
5.
6.
Be sure to click on the link that reads, “DUNS Number Only” at the right hand, bottom corner of the screen to access the free registration page. Please note that registration via the Web site may take up to 30 business days to complete.
This section must discuss:
1. Applicant's experience providing HIV/AIDS prevention education, support services, and/or other services (
2. Applicant's description of the HIV/AIDS prevention and support service needs for the women at risk for or living with HIV/AIDS and other female members of the family 12+ years old to be reached in this program; must include a detailed assessment with age-specific demographic and service need profile for minority females (African American, Native American/American Indian, Hispanic/Latino, and Asian/Pacific Islander) in the applicant's local service area.
3. Applicant's full description of the issues or challenges that impact women at risk for or living with HIV/AIDS specific to one of the racial/ethnic minority groups to be reached (African American, Native American/American Indian, Hispanic/Latino, or Asian/Pacific Islander) relative to effective cross-generational communication
• Understanding a woman's body and how to care for it over the lifespan.
• Knowledge of ways to enhance health.
• Building and/or maintaining healthy relationships that includes an understanding of health threats.
• Awareness of primary healthcare system and how to access it.
• Gaining skills to express feelings and concerns about one's sexual health issues to other female family or kinship network members 12+ years old.
• Increasing awareness and ability to secure a safe place to live first when threatened by sexual, physical, or emotional violence.
This section must discuss:
1. Evidence provided of applicant's success in providing HIV/AIDS prevention education, support services, and/or other services (
2. Applicant's goals, objectives, plan of action and timeline that fully describes how proposed intergenerational approach to HIV/AIDS prevention education for women at risk for or living with HIV/AIDS who are African American, Native American/American Indian, Hispanic/Latino, or Asian/Pacific Islander addresses the barriers to cross-generational communication between grandmothers, mothers, daughters, granddaughters, and aunts and/or other adult female kinship members 12+ years old with the impact of age, culture, traditions, and spirituality, as well as any trends or shifts in these areas.
3. Evidence of applicant's work in establishing and/or convening African American, Native American/American Indian, Hispanic/Latino, or Asian/Pacific Islander consumers for feedback on HIV/AIDS prevention, support, care, and/or treatment programs.
4. Evidence of applicant's work in identifying and/or working with community stakeholders, specifically for HIV/AIDS prevention, support, care, and/or treatment.
The applicant's proposal should contain:
1. Applicant's proposed staff and/or requirements for new staff adequately described in resumes (see Appendix); must include contractual services of a licensed female behavioral health therapist with expertise in counseling African American, Native American/American Indian, Hispanic/Latino, or Asian/Pacific Islander women at risk for or living with HIV/AID and other female members of the family 12+ years old.
2. Proposed staff level of effort;
3. Detailed position descriptions (appears in Appendix); and
4. Addresses maintenance of confidentiality, ethics in performance, and any mandatory in-service staff training.
The applicant's proposal contains:
1. Clear statement of program goal(s);
2. Quantifiable objectives;
3. Clear indicators to analyze trends; and
4. Clear indicators to recognize unanticipated outcomes.
1.
2.
The DHHS Appropriations Act requires that, when issuing statements, press releases, requests for proposals, bid solicitations, and other documents describing projects or programs funded in whole or in part with Federal money, all grantees shall clearly state the percentage and dollar amount of the total costs of the program or project which will be financed with Federal money and the percentage and dollar amount of the total costs of the project or program that will be financed by non-governmental sources.
3.
An original and one copy of the four report(s) must be submitted as follows:
1. Initial Progress Report due date (provided at OWH orientation meeting).
2. Mid-Year Progress Report due date (provided at OWH orientation meeting).
3. Final Progress Report due date (provided at OWH orientation meeting).
A Financial Status Report (FSR) SF-269 is due 90 days after the close of each 12-month budget period.
For application kits, submission of applications, and information on the budget and business aspects of the application, please contact: WilDon Solutions, Office of Grants Management Operations Center, 1515 Wilson Blvd., Third Floor, Suite 310, Arlington, VA 22209 at 1-888-203-2061, e-mail
4. Questions regarding programmatic information and/or requests for technical assistance in the preparation of the grant application should be directed in writing to:
Joanna Short, M.Div., Public Health Advisor, Office on Women's Health, OPHS, DHHS, Hubert H. Humphrey Building, Room 733E, 200 Independence Avenue, SW.,
The applicant must comply with the DHHS Protection of Human Subjects regulations (which require obtaining Institutional Review Board approval), set out as 45 CFR Part 46, if applicable. General information about Human Subjects regulations can be obtained through the Office of Human Research Protections (OHRP) at
Emphasis will be placed on aligning OWH activities and programs with Healthy People 2010: Goal 2 to eliminate health disparities. More information on the Healthy People 2010 objectives may be found on the Healthy People 2010 Web site:
(1) Centers for Disease Control and Prevention. HIV/AIDS Surveillance Report. 2002; 14/Addendum: 5. Table A3.
(2) Centers for Disease Control and Prevention. HIV/AIDS Surveillance Report 2002, Vol. 14.
National Institute of Environmental Health Sciences (NIEHS), National Institutes of Health (NIH).
Meeting announcement and request for comment.
Pursuant to section 10(a) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of a meeting of SACATM on June 12, 2007, at the Marriott Bethesda North Hotel and Conference Center, 5701 Marinelli Road, Bethesda, Maryland. The meeting is scheduled from 8:30 a.m. to adjournment (~5 p.m.) and is open to the public with attendance limited only the space available. SACATM advises the Interagency Coordinating Committee on the Validation of Alternative Methods (ICCVAM), the NTP Interagency Center for the Evaluation of Alternative Toxicological Methods (NICEATM), and the Director of the NIEHS and NTP regarding statutorily mandated duties of ICCVAM and activities of NICEATM.
The SACATM meeting will be held on June 12, 2007. All individuals who plan to attend are encouraged to register online at the NTP Web site (
The SACATM meeting will be held at the Marriott Bethesda North Hotel & Conference Center, 5701 Marinelli Road, Bethesda, Maryland 20852 [hotel: (301) 822-9200]. Public comments and other correspondence should be directed to Dr. Mary S. Wolfe (NIEHS, P.O. Box 12233, MD A3-01, Research Triangle Park, NC 27709; telephone: 919-541-7539 or e-mail:
A preliminary agenda is provided below. Additional background materials will be posted on the NTP Web site (
Public input is invited and time is set-aside at the meeting for presentation of oral comments. Each organization is allowed one time slot per public comment period. At least 7 minutes will be allotted for each speaker, and if time permits, may be extended up to 10 minutes at the discretion of the chair. Registration for oral comments will also be available on-site, although time allowed for presentation by on-site registrants may be less than for pre-registered speakers and will be determined by the number of persons who register at the meeting.
Persons registering to make oral comments are asked to do so through the online registration form (
SACATM was established in response to the ICCVAM Authorization Act [42 U.S.C. 285
National Institute of Environmental Health Sciences (NIEHS), National Institutes of Health (NIH).
Meeting announcement and request for comments.
The NIEHS and NICEATM request public comments that can be considered by NICEATM, the Interagency Coordinating Committee on the Validation of Alternative Methods (ICCVAM), and relevant program offices on the draft NICEATM-ICCVAM 5-Year Plan. The draft plan addresses: (a) Research, development, translation, and validation of new and revised non-animal and other alternatives assays for integration of relevant and reliable methods into federal agency testing programs and (b) identification of areas of high priority for new and revised non-animal and alternative assays for the replacement, reduction, and refinement (less pain and distress) of animal tests. The draft plan will be available on or before May 7, 2007, at the NICEATM-ICCVAM 5-Year Plan Web site (
The draft NICEATM-ICCVAM 5-Year Plan will be available by May 7, 2007. Registration to attend the meeting and written comments on the draft NICEATM-ICCVAM 5-Year Plan should be received by June 7, 2007. The Town Meeting will be held June 11, 2007.
The Town Meeting will be held at the William H. Natcher Conference Center, Room E, NIH, 9000 Rockville Pike, Bethesda, Maryland. Persons needing special assistance, such as sign language interpretation or other reasonable accommodation in order to attend, should contact 919-541-2475 voice, 919-541-4644 TTY (text telephone), through the Federal TTY Relay System at 800-877-8339, or send e-mail to
Other correspondence should be directed to Dr. William S. Stokes, NICEATM Director (NIH/NIEHS, P.O. Box 12233, MD EC-17, Research Triangle Park, NC 27709; telephone: 919-541-2384, fax: 919-541-0947 or e-mail:
Congress established ICCVAM to promote development, validation, and regulatory acceptance of new or revised alternative toxicological test methods that protect human and animal health and the environment while reducing, refining, or replacing animal tests and ensuring human safety and product effectiveness (42 U.S.C. 285
The Town Meeting will be held on June 11, 2007, at the William H. Natcher Conference Center, National Institutes of Health, Bethesda, Maryland. Persons planning to attend are asked to register by June 7, 2007 by completing the online registration at the NICEATM-ICCVAM Web site (
The NIEHS and NICEATM invite public comments on the draft NICEATM-ICCVAM 5-Year Plan. Written comments should be submitted preferably electronically at the NICEATM-ICCVAM 5-Year Plan Web site (
Persons registering to make oral comments at the Town Meeting are asked to contact NICEATM (see
ICCVAM is an interagency committee composed of representatives from 15 federal regulatory and research agencies that use, generate, or disseminate toxicological information. ICCVAM conducts technical evaluations of new, revised, and alternative methods with regulatory applicability and promotes scientific validation and regulatory acceptance of toxicological test methods that more accurately assess safety and hazards of chemicals and products and that refine, reduce, and replace animal use. The ICCVAM Authorization Act of 2000 (42 U.S.C. 285
National Institute of Environmental Health Sciences (NIEHS); National Institutes of Health.
Announcement of postponed meeting and extension of public comment period.
The second meeting of the expert panel on bisphenol A originally scheduled for May 21-23, 2007 [
Written comments on the interim draft expert panel report should be received by June 20, 2007.
Comments on the interim draft report should be sent to Dr. Michael D. Shelby, CERHR Director, NIEHS, P.O. Box 12233, MD EC-32, Research Triangle Park, NC 27709 (mail), (919) 316-4511 (fax), or
Dr. Michael D. Shelby, CERHR Director, 919-541-3455,
The Program Peer Review Subcommittee (PPRS) of the Board of Scientific Counselors (BSC), National Center for Environmental Health/Agency for Toxic Substances and Disease Registry (NCEH/ATSDR): Meeting.
In accordance with section 10(a)(2) of the Federal Advisory Committee Act (Pub. L. 92-463), NCEH/ATSDR, CDC, announces the following meeting of the aforementioned subcommittee:
The Director, Management Analysis and Services Office, has been delegated the authority to sign
National Institutes of Health, Public Health Service, HHS.
Notice.
The inventions listed below are owned by an agency of the U.S. Government and are available for licensing in the U.S. in accordance with 35 U.S.C. 207 to achieve expeditious commercialization of results of federally-funded research and development. Foreign patent applications are filed on selected inventions to extend market coverage for companies and may also be available for licensing.
Licensing information and copies of the U.S. patent applications listed below may be obtained by writing to the indicated licensing contact at the Office of Technology Transfer, National Institutes of Health, 6011 Executive Boulevard, Suite 325, Rockville, Maryland 20852-3804; telephone: 301/496-7057; fax: 301/402-0220. A signed Confidential Disclosure Agreement will be required to receive copies of the patent applications.
1. A new bioinformatics software tool that can easily identify dimorphisms and can help create a searchable database and graphical interface containing sites of dimorphisms and information regarding functional effects of dimorphisms.
2. Low cost, high-throughput PCR based methods to identify dimorphic repetitive elements from any eukaryotic genome including individual tissue specimens.
3. Methods to determine functional consequences of dimorphisms (indels).
1. Bioinformatics software tools are ready for use.
2. High-throughput PCR methods have been validated.
3. Annotated mouse genes whose expression is altered by dimorphic indels have been identified.
1. Manuscripts relating to this invention are under preparation and will be available once accepted for publication.
2. RE Mills
Nanoparticles constructed from transmembrane domains of certain receptors and transporters have biological activity of their own and inhibit metastasis or drug resistance thus sensitizing tumors to therapy. Hydrophobic drugs can be easily entrapped inside the nanoparticles, which not only solve the problem of drug insolubility under physiological conditions, but also generate a form of a drug that concentrates in tumors due to enhanced permeability and retention (EPR) effects.
1. Self-assembling nano-particles as an alternative to liposomes, inorganic, dendrimeric or polymeric nanoparticles.
2. Nanoparticles have biological activity of their own and can inhibit metastasis (CXCR4 receptor antagonists) or drug resistance (inhibitors of ABCG2 transporter and p-glycoprotein) thus sensitizing tumors to therapy.
1. The nanoparticles are superior in stability, uniformity, ease and reproducibility of preparation compared to conventional liposomes, are much more uniform and less toxic than inorganic, polymeric or dendrimeric nanoparticles.
2. The nanoparticles are much smaller than a liposome thus providing better tumor penetration.
3. Synthetic nanoparticles can be easily coated with receptor ligands and loaded with hydrophobic drugs for more specific tumor targeting.
1. The technology is currently in the pre-clinical stage of development.
2. Proof of concept results show that inhibition of Sipa-1 reduces metastasis in mouse models.
3. Laboratory data shows single nucleotide polymorphisms (SNPs) within the Sipa-1 gene linked to metastatic disease.
1. PCT Publication No. WO 2006084027, published October 8, 2006.
2. YG Park
3. NP Crawford
Notice hereby given of a change in the meeting of the Subcommittee G—Education, June 26, 2007, 8 a.m. to June 27, 2007, 5 p.m., Gaithersburg Marriott Washingtonian Center, 204 Boardwalk Place, Gaithersburg, MD 20878 which was published in the
The meeting has been rescheduled to a one day meeting that will occur on June 26, 2007. The meeting is closed to the public.
Pursuant to section 10(a) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of a meeting of the Sleep Disorders Research Advisory Board.
The meeting will be open to the public, with attendance limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the Contact Person listed below in advance of the meeting.
Any interested person may file written comments with the committee by forwarding the statement to the Contact Person listed on this notice. The statement should include the name, address, telephone number and when applicable, the business or professional affiliation of the interested person.
Information is also available on the Institute's/Center's home page:
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property as such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of a meeting of the National Advisory Council for Nursing Research.
The meeting will be open to the public as indicated below, with attendance limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the Contact Person listed below in advance of the meeting.
The meeting will be closed to the public in accordance with the
Any interested person may file written comments with the committee by forwarding the statement to the Contact Person listed on this notice. The statement should include the name, address, telephone number and when applicable, the business or professional affiliation of the interested person.
In the interest of security, NIH has instituted stringent procedures for entrance onto the NIH campus. All visitor vehicles, including taxicabs, hotel, and airport shuttles will be inspected before being allowed on campus. Visitors will be asked to show one form of identifcation (for example, a government-issued photo ID, driver's license, or passport) and to state the purchase of their visit.
Information is also available on the Institute's/Center's home page
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of meetings of the National Advisory Neurological Disorders and Stroke Council.
The meetings will be open to the public as indicated below, with attendance limited to space available.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
In the interest of security, NIH has instituted stringent procedures for entrance onto the NIH campus. All visitor vehicles, including taxicabs, hotel, and airport shuttles will be inspected before being allowed on campus. Visitors will be asked to show one form of identification (for example, a government-issued photo ID, driver's license, or passport) and to state the purpose of their visit.
Information is also available on the Institute's/Center's home page:
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the following meetings.
The meeting will be closed to the public in accordance with the provisions set forth in section 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
Notice is hereby given of a change in the meeting of the National Institute on Drug Abuse Special Emphasis Panel, April 18, 2007, 9 a.m. to April 19, 2007, 5 p.m., Courtyard by Marriott Rockville, 2500 Research Boulevard, Rockville, MD 20850 which was published in the
The date and location of the meeting was changed to May 9-10, 2007, Hilton Washington, DC/Rockville Executive Meeting Center, 1750 Rockville Pike, Rockville, MD 20852. The meeting is closed to the public.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Notice is hereby given of a change in the meeting of the Neurobiology of Learning and Memory Study Section, May 31, 2007, 8 a.m. to June 1, 2007, 5 p.m., George Washington University Inn, 824 New Hampshire Ave., NW., Washington, DC 20037 which was published in the
The meeting will be held one day only May 31, 2007, 8:30 a.m. to 5 p.m. The meeting location remains the same. The meeting is closed to the public.
Notice is hereby given of a change in the meeting of the Center for Scientific Review Special Emphasis Panel, May 22, 2007, 12:30 p.m. to May 22, 2007, 1:30 p.m. National Institutes of Health, 6701 Rockledge Drive, Bethesda, MD 20892 which was published in the
The meeting will be held May 23, 2007. The meeting time and location remain the same. The meeting is closed to the public.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
Bureau of Land Management, Interior.
Notice of competitive coal lease sale.
Notice is hereby given that certain coal resources in the Pit 14 Coal Tract described below in Sweetwater County, Wyoming, will be offered for competitive lease by sealed bid in accordance with the provisions of the Mineral Leasing Act of 1920, as amended (30 U.S.C. 181
The lease sale will be held at 10 a.m., on Tuesday, June 5, 2007. Sealed bids must be submitted on or before 4 p.m., on Monday, June 4, 2007.
The lease sale will be held in the First Floor Conference Room (Room 107), of the Bureau of Land Management (BLM) Wyoming State Office, 5353 Yellowstone Road, P.O. Box 1828, Cheyenne, WY 82003. Sealed bids must be submitted to the Cashier, BLM Wyoming State Office, at the address given above.
Mavis Love, Land Law Examiner, or Robert Janssen, Coal Coordinator, at 307-775-6258, and 307-775-6206, respectively.
This coal lease sale is being held in response to a lease by application (LBA) filed by Black Butte Coal Company, Point of Rocks, Wyoming. The coal resources to be offered consist of all reserves recoverable by surface mining methods in the following-described lands located in Sweetwater County, 28 miles southeast of Rock Springs, Wyoming, approximately 14 miles south of Interstate 80, about 3 miles east of Black Butte Creek, and just southwest of the permit boundary of the existing Black Butte surface mine:
Containing 1,399.48 acres more or less.
All of the acreage applied for has been determined to be suitable for surface mining. There are no existing surface facilities or structures that will be impacted by the proposed pit. There are no producing oil and/or gas wells on the tract. All of the surface and mineral estate on the LBA tract is controlled by the BLM.
The tract contains surface mineable coal reserves within the Upper Cretaceous Almond Formation. In the LBA area, the coal cropline extends roughly southwest to northeast along the northwestern edge of the proposed pit.
Mining is expected to begin along this cropline. The coal seams dip more rapidly than the ground surface toward the southeast and an economic cutoff of about 200 feet of overburden is projected for the final mine cut.
Numerous coal seams occur in the immediate area, but only four are considered to be mineable within the proposed pit. These are identified, in descending order, as the AG, AF, AFL, and AE seams. The AG is the uppermost seam and is the most consistent over the LBA, generally ranging from 4-6 feet thick. The interburden between the AG and AF seams ranges from about 5-40 feet thick on the LBA. The AF seam ranges from 2-12 feet thick on the LBA and is joined with the AE seam near the cropline in Section 4. The AFL seam is a localized split that is largely confined to Section 34. The parting between the AF and AFL seams ranges from 0-20 feet thick and the AFL seam itself ranges from 2-3 feet thick on the LBA. The interburden between the AF and AE seams ranges from 0-45 feet thick on the LBA. The AE seam varies from 2-8 feet thick on the LBA. The composite mineable coal thickness ranges from 10-20 feet thick over the LBA.
The LBA tract contains an estimated 11,218,740 tons of mineable coal in the four seams described above that could be recovered by surface mining methods. This mineable reserve is based on a minimum 20 foot overburden thickness to avoid any coal oxidation areas, a minimum coal thickness of 2 feet, and a maximum stripping ratio of 14.6:1 (bank cubic yards per ton of coal). Other coal seams and splits are found in the LBA area, but these have not been included in this reserve estimate due to thickness, depth, poor quality, limited areal extent, or any combination of factors.
Potential bidders must establish their own practicable criteria for mining, including their estimate of recoverable reserves based on multiple seams and thin seam mining.
The Pit 14 LBA coal is ranked as subbituminous B. The overall average quality is approximately 9965 BTU/lb with about 7.57% ash and 0.54% sulfur. These quality averages are generally higher than those for the coal reserves currently being mined at the adjacent surface mine.
The tract will be leased to the qualified bidder of the highest cash amount provided that the high bid meets or exceeds the BLM's estimate of the fair market value of the tract. The minimum bid for the tract is $100 per acre or fraction thereof. The bids should be sent by certified mail, return receipt requested, or be hand delivered. The Cashier will issue a receipt for each hand-delivered bid. Bids received after 4 p.m., on Monday, June 4, 2007, will not be considered. The minimum bid is not intended to represent fair market value. The fair market value of the tract will be determined by the Authorized Officer after the sale. The lease issued as a result of this offering will provide for payment of an annual rental of $3.00 per acre, or fraction thereof, and of a
Bidding instructions for the tract offered and the terms and conditions of the proposed coal lease are available from the BLM Wyoming State Office at the addresses above. Case file documents, WYW160394, are available for inspection at the BLM Wyoming State Office.
United States International Trade Commission.
Institution of a five-year review concerning the antidumping duty order on certain folding metal tables and chairs from China.
The Commission hereby gives notice that it has instituted a review pursuant to section 751(c) of the Tariff Act of 1930 (19 U.S.C. 1675(c)) (the Act) to determine whether revocation of the antidumping duty order on certain folding metal tables and chairs from China would be likely to lead to continuation or recurrence of material injury. Pursuant to section 751(c)(2) of the Act, interested parties are requested to respond to this notice by submitting the information specified below to the Commission;
Mary Messer (202-205-3193), 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 (
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Former Commission employees who are seeking to appear in Commission five-year reviews are reminded that they are required, pursuant to 19 CFR 201.15, to seek Commission approval if the matter in which they are seeking to appear was pending in any manner or form during their Commission employment. The Commission's designated agency ethics official has advised that a five-year review is the “same particular matter” as the underlying original investigation for purposes of 19 CFR 201.15 and 18 U.S.C. 207, the post employment statute for Federal employees. Former employees may seek informal advice
(1) The name and address of your firm or entity (including World Wide Web address if available) and name, telephone number, fax number, and E-mail address of the certifying official.
(2) A statement indicating whether your firm/entity is a U.S. producer of the Domestic Like Product, a U.S. union or worker group, a U.S. importer of the Subject Merchandise, a foreign producer or exporter of the Subject Merchandise, a U.S. or foreign trade or business association, or another interested party (including an explanation). If you are a union/worker group or trade/business association, identify the firms in which your workers are employed or which are members of your association.
(3) A statement indicating whether your firm/entity is willing to participate in this review by providing information requested by the Commission.
(4) A statement of the likely effects of the revocation of the antidumping duty order on the Domestic Industry in general and/or your firm/entity specifically. In your response, please discuss the various factors specified in section 752(a) of the Act (19 U.S.C. 1675a(a)) including the likely volume of subject imports, likely price effects of subject imports, and likely impact of imports of Subject Merchandise on the Domestic Industry.
(5) A list of all known and currently operating U.S. producers of the Domestic Like Product. Identify any known related parties and the nature of the relationship as defined in section 771(4)(B) of the Act (19 U.S.C. 1677(4)(B)).
(6) A list of all known and currently operating U.S. importers of the Subject Merchandise and producers of the Subject Merchandise in the Subject Country that currently export or have exported Subject Merchandise to the United States or other countries since the Order Date.
(7) If you are a U.S. producer of the Domestic Like Product, provide the following information on your firm's operations on that product during calendar year 2006 (report quantity data in units and value data in U.S. dollars, f.o.b. plant). If you are a union/worker group or trade/business association, provide the information, on an aggregate basis, for the firms in which your workers are employed/which are members of your association.
(a) Production (quantity) and, if known, an estimate of the percentage of total U.S. production of the Domestic Like Product accounted for by your firm's(s') production;
(b) The quantity and value of U.S. commercial shipments of the Domestic Like Product produced in your U.S. plant(s); and
(c) The quantity and value of U.S. internal consumption/company transfers of the Domestic Like Product produced in your U.S. plant(s).
(8) If you are a U.S. importer or a trade/business association of U.S. importers of the Subject Merchandise from the Subject Country, provide the following information on your firm's(s') operations on that product during calendar year 2006 (report quantity data in units and value data in U.S. dollars). If you are a trade/business association, provide the information, on an aggregate basis, for the firms which are members of your association.
(a) The quantity and value (landed, duty-paid but not including antidumping or countervailing duties) of U.S. imports and, if known, an estimate of the percentage of total U.S. imports of Subject Merchandise from the Subject Country accounted for by your firm's(s') imports;
(b) The quantity and value (f.o.b. U.S. port, including antidumping and/or countervailing duties) of U.S. commercial shipments of Subject Merchandise imported from the Subject Country; and
(c) The quantity and value (f.o.b. U.S. port, including antidumping and/or countervailing duties) of U.S. internal consumption/company transfers of Subject Merchandise imported from the Subject Country.
(9) If you are a producer, an exporter, or a trade/business association of producers or exporters of the Subject Merchandise in the Subject Country, provide the following information on your firm's(s') operations on that product during calendar year 2006 (report quantity data in units and value data in thousands of U.S. dollars, landed and duty-paid at the U.S. port but not including antidumping or countervailing duties). If you are a trade/business association, provide the information, on an aggregate basis, for the firms which are members of your association.
(a) Production (quantity) and, if known, an estimate of the percentage of total production of Subject Merchandise in the Subject Country accounted for by your firm's(s') production; and
(b) The quantity and value of your firm's(s') exports to the United States of Subject Merchandise and, if known, an estimate of the percentage of total exports to the United States of Subject Merchandise from the Subject Country accounted for by your firm's(s') exports.
(10) Identify significant changes, if any, in the supply and demand conditions or business cycle for the Domestic Like Product that have occurred in the United States or in the market for the Subject Merchandise in the Subject Country since the Order Date, and significant changes, if any, that are likely to occur within a reasonably foreseeable time. Supply conditions to consider include technology; production methods; development efforts; ability to increase production (including the shift of production facilities used for other products and the use, cost, or availability of major inputs into production); and factors related to the ability to shift supply among different national markets (including barriers to importation in foreign markets or changes in market demand abroad). Demand conditions to consider include end uses and applications; the existence and availability of substitute products; and the level of competition among the Domestic Like Product produced in the United States, Subject Merchandise produced in the Subject Country, and such merchandise from other countries.
(11) (Optional) A statement of whether you agree with the above definitions of the Domestic Like Product and Domestic Industry; if you disagree with either or both of these definitions, please explain why and provide alternative definitions.
This review is being conducted under authority of title VII of the Tariff Act of 1930; this notice is published pursuant to section 207.61 of the Commission's rules.
By order of the Commission.
Pursuant to the provisions of the Privacy Act of 1974 (5 U.S.C. 552a), the Department of Justice (DOJ) is removing the published notice of a Privacy Act system of records entitled “Master Index File of Names, DAG-005,” last published in the
The “Master Index File of Names” was a system for tracking individuals covered by the following systems of records: Appointed Assistant U.S. Attorneys Personnel System; Assistant U.S. Attorney Applicant Records; Presidential Appointee Candidate Records System; Presidential Appointee Records System; Special Candidates for Presidential Appointments Records System; and U.S. Judges Records System. The “Master Index File of Names” consisted of paper file cards containing individually identifiable information such as: date of birth; date of entry on duty in Federal Service; date of termination of Federal Service; and disposition of the records folder.
The file cards designated as “Master Index File of Names, DAG-005” were destroyed in accordance with National Archives and Records Administration (NARA) guidelines. The underlying records from which the information on these cards was extracted are all covered by other systems of records notices.
Therefore, the notice of “DAG-005, Master Index File of Names” is removed from the Department's listing of Privacy Act systems of records notices, effective on the date of publication of this notice in the
60-day notice of information collection under review: letter application to obtain authorization for the assembly of a non-sporting rifle or non-sporting shotgun for the purpose of testing or evaluation.
The Department of Justice (DOJ), Bureau of Alcohol, Tobacco, Firearms and Explosives (ATF), will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995. The proposed information collection is published to obtain comments from the public and affected agencies. Comments are encouraged and will be accepted for “sixty days” until July 2, 2007. This process is conducted in accordance with 5 CFR 1320.10.
If you have comments especially on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please contact Larry White, Firearms and Explosives Services Division, Room 7400, 650 Massachusetts Avenue, NW., Washington, DC 20226
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
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60-day notice of information collection under review:
Application for Federal Firearms License (Collector of Curios and Relics).
The Department of Justice (DOJ), Bureau of Alcohol, Tobacco, Firearms and Explosives (ATF), will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995. The proposed information collection is published to obtain comments from the public and affected agencies. Comments are encouraged and will be accepted for “sixty days” until July 2, 2007. This process is conducted in accordance with 5 CFR 1320.10.
If you have comments especially on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please contact Patricia Power, Chief, Federal Firearms Licensing Center, 2600 Century Parkway, NE., Suite 110, Atlanta, GA 30345.
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
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60-day notice of information collection under review: Records of acquisition and disposition, collectors of firearms.
The Department of Justice (DOJ), Bureau of Alcohol, Tobacco, Firearms and Explosives (ATF), will be
If you have comments especially on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please contact Thomas McDermott, Firearms Programs Division, Room 7400, 650 Massachusetts Avenue, NW., Washington, DC 20226.
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
(1)
(2)
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(4)
(5)
(6)
On April 21, 2004, the Deputy Assistant Administrator, Office of Diversion Control, Drug Enforcement Administration, issued an Order to Show Cause to Samuel S. Jackson, D.D.S. (Respondent) of Nashville, Tennessee. The Show Cause Order proposed to deny Respondent's pending application for a certificate of registration as a practitioner on three grounds: (1) That Respondent had materially falsified his application,
The Show Cause Order alleged that Respondent had entered into a conspiracy with a drug trafficker, who was then wanted on federal charges, and a confidential informant, whom Respondent also believed to be a fugitive, to help them avoid apprehension. Show Cause Order at 2. More specifically, the Show Cause order alleged that Respondent had agreed to perform cosmetic dental work on these individuals and to arrange for plastic surgery on them for the purpose of altering their appearance so that they could evade arrest.
The Show Cause Order alleged that Respondent subsequently pled guilty in the United States District Court for the Middle District of Tennessee on one count of conspiracy, a crime under 18 U.S.C. 371, and was sentenced to a term of imprisonment for 30 months.
The Show Cause Order alleged that on October 20, 2003, Respondent applied for a new DEA registration.
Respondent, through his counsel, timely requested a hearing. The case was assigned to Administrative Law Judge (ALJ) Gail Randall, who conducted a hearing in Nashville on May 3 and 4, 2005. At the hearing, both parties called witnesses to testify and introduced documentary evidence. Following the hearing, the Government submitted a brief containing its proposed findings of fact, conclusions of law, and argument.
On May 26, 2006, the ALJ issued her recommended findings of fact, conclusions of law, and decision. In that decision, the ALJ concluded that Respondent did not intentionally falsify his application. ALJ at 28. The ALJ further found that while Respondent “was less than completely candid and forthcoming” in his testimony regarding
The Government filed exceptions to the ALJ's recommended decision. Specifically, the Government contended that Respondent had not credibly testified “as to the essential elements of [his] felony conviction,” and that he had given falsified answers on his application. Gov. Exceptions at 11-12. The Government further maintained that granting Respondent's application would not be consistent with DEA precedents which require that an applicant (or registrant) truthfully testify and accept full responsibility for his misconduct. Respondent did not file exceptions.
Having considered the record as a whole, I hereby issue this decision and final order. I adopt the ALJ's findings of fact except as expressly noted herein. I hold that the Government has not proved by substantial evidence that Respondent materially falsified his application. I further hold that the Government has not proved by substantial evidence that Respondent has failed to accept responsibility for his criminal conduct. I thus conclude that Respondent's registration would not be inconsistent with the public interest and order that his application be granted.
Respondent is a 1997 graduate of the Meharry Medical College School of Dentistry. Tr. 148. Respondent currently holds a license from the State of Tennessee to practice dentistry. Resp. Exh. 1. Respondent previously held a DEA Certificate of Registration as a practitioner. On October 1, 2002, my predecessor ordered that Respondent's DEA registration be revoked (effective November 22, 2002) on the ground that Respondent had entered into an agreed order with the Tennessee Department of Health which resulted in the revocation of his state license and therefore was not entitled to maintain a DEA registration.
As explained below, the impetus for these actions was Respondent's entering into a conspiracy under which Respondent agreed to help Paul Woods, an indicted drug trafficker who was then at large, as well as a confidential informant (CI) whom Respondent also believed was wanted by the authorities, to avoid apprehension. According to the record, in 1997 a Nashville-based DEA task force began an investigation into the criminal activities of Woods and his organization. Tr. 73. The investigation established that Woods and his organization were involved in the distribution of multi-kilo amounts of cocaine in the Nashville area.
Woods was charged in July 1999, in the initial wave of indictments.
To gain the confidence of Woods, the authorities portrayed the informant as a fugitive.
At the time of the investigation, Respondent was dating a woman whose niece was Woods' live-in girlfriend and the mother of one of Woods' children.
Respondent agreed to perform cosmetic dental work on both Woods and the informant to alter their appearance and to help them avoid detection.
The ALJ further found that Respondent was aware that Woods and the informant were drug traffickers at the time he agreed to assist them.
As for the media coverage of the events, the Lead Task Force Officer testified that the Task Force's inability to arrest Woods following his indictment “was covered on the three local stations as well as in * * * the paper.” Tr. 134. That was the extent of the evidence; the Government did not produce any evidence to show how many days the story was covered by TV stations and the paper. Moreover, the
Nor does Respondent's participation in the December 15, 1999 phone conversation provide substantial evidence that he knew Woods and the informant were drug dealers. At the hearing, the Lead Task Force Officer testified as to his interpretation of the street slang used in the December 15, 1999 conversation between Respondent, Woods and the informant. Specifically, the Task Force Officer testified that Woods' comments that the informant was “like cool as [expletive
The Government did not prove, however, that Respondent interpreted the language as a reference to drug dealing as opposed to other forms of criminal activity. Indeed, it bears noting that the Government introduced only this single phone call to support the contention and even the Task Force Officer apparently did not draw the inference that Respondent knew that Woods and the informant were drug dealers.
Finally, the substantial evidence test requires that the Agency “ ‘tak[e] into account contradictory evidence or evidence from which conflicting inferences could be drawn.’ ”
On January 13, 2000, Woods was arrested by U.S. Marshals. Gov. Exh. 4 at 7. Thereafter, on January 17, 2000, the informant called Respondent to determine whether he was still willing to assist the informant in evading capture. Tr. 86. Respondent agreed to do so.
On January 18, 2000, the informant called Respondent and told him that “he needed to get his money together.”
Later that day, Respondent arrived at the parking lot and entered the informant's car.
That evening, Respondent agreed to an interview. The interview was conducted by an Assistant United States Attorney and several law officers. Gov. Exh. 6. During the interview, Respondent fully discussed the circumstances surrounding his involvement with Woods. During the interview, Respondent described Woods as a “big time hoodlum” and that he was in trouble.
At the hearing, the lead Task Force Officer testified that Respondent “was totally truthful” with the interviewers and that the information he provided was consistent with other information obtained in the investigation. Tr. 141. Respondent also agreed to cooperate with the investigation by making phone calls to another suspect and wearing a wire.
The United States Attorney subsequently charged Respondent with one count of conspiring to violate 18 U.S.C. 3, the “accessory after the fact” statute. Gov. Exh. 4;
On July 20, 2001, Respondent pled guilty and was sentenced to a term of thirty months imprisonment and a term of three years of supervised release. Gov. Exh. 3. Respondent received sentence reduction points for his cooperation with law enforcement officials and for accepting responsibility for his conduct. Tr. 137. Respondent
Following his release from prison, Respondent applied for reinstatement of his state dental license.
After the Tennessee Board's decision, Respondent contacted the DEA office in Atlanta, Georgia, to determine the status of his registration.
Thereafter, on October 3, 2003, Respondent re-applied for a DEA registration. Gov. Exh. 5, at 2. On the application, Respondent was asked whether he had “ever been convicted of a crime in connection with controlled substances under state or federal law?”
The application also requires that an applicant give an explanation for a “yes” answer to these questions. In this block, Respondent wrote:
I voluntarily surrendered my license to practice dentistry in the State of Tennessee as a result of my conviction for accessory after the fact. I also voluntarily surrendered my DEA # to prescribe medications. The board of * * * Tennessee voted unanimously to reinstate my license to practice dentistry in the State of Tennessee on 9/19/03.
Respondent testified regarding his criminal conduct. When asked by his counsel whether he had committed a crime, Respondent answered: “Absolutely.” Tr. 150. Respondent further testified that he “agreed to help arrange for him [Woods] to avoid apprehension, and as much as I want to blame other people for that, I can't. The onus is firmly and squarely on my shoulders, and I take full responsibility for that.”
Respondent also testified that his conduct in agreeing to help Woods “was the absolute worst thing—the only thing I could have done worse was actually murder someone. * * * [I]t's just a terrible, terrible thing.”
Respondent further testified that at the time he committed the act, he was aware that Woods was a criminal, a “hoodlum,” and a “hustler.”
During its cross-examination, the Government asked Respondent about his motive. Specifically, the Government asked Respondent whether “making a lot of money off of this was” his motive.
When pressed by the Government as to whether he was to receive any money out of this, Respondent testified that his California contact was “going to do something nice for” him.
Respondent also testified regarding his application. Specifically, Respondent testified that he believed that he had voluntarily surrendered his DEA registration because “at no time did we put up any resistance to the process.”
The ALJ specifically found that “Respondent credibly testified that at the time he completed his application, he believed he had voluntarily surrendered his previous * * * registration and that he was responding truthfully.” ALJ Dec. at 15 (FOF 64). I adopt this finding.
Regarding the application's criminal history question, Respondent testified that he answered “no” because he did not think that he had committed a drug-related felony.
The ALJ specifically credited Respondent's testimony on both issues.
I further note that there is no evidence that Respondent has ever illegally used
Section 303(f) of the Controlled Substances Act provides that an application for a practitioner's registration may be denied upon a determination “that the issuance of such registration would be inconsistent with the public interest.” 21 U.S.C. 823(f). In making the public interest determination, the CSA requires the consideration of the following factors:
(1) The recommendation of the appropriate State licensing board or professional disciplinary authority.
(2) The applicant's experience in dispensing * * * controlled substances.
(3) The applicant's conviction record under Federal or State laws relating to the manufacture, distribution, or dispensing of controlled substances.
(4) Compliance with applicable State, Federal, or local laws relating to controlled substances.
(5) Such other conduct which may threaten the public health and safety.
“These factors are * * * considered in the disjunctive.”
Furthermore, DEA precedent establishes that the various grounds for revocation or suspension of an existing registration that Congress enumerated in section 304(a), 21 U.S.C. 824(a), are also properly considered in deciding whether to grant or deny an application under section 303.
For reasons explained below, I conclude that the Government has not proved that Respondent materially falsified his application. Furthermore, while I am deeply troubled by Respondent's criminal conduct, I am satisfied that he has accepted responsibility for it and reject the Government's assertion to the contrary.
The Government maintains that Respondent materially falsified his application in two respects. First, by answering “no” to the application's question as to whether Respondent had “ever been convicted of a crime in connection with controlled substances,” and second, by stating that he had “voluntarily surrendered” his DEA number. Gov. Exceptions at 7-9. As explained above, the ALJ found that Respondent did not intentionally falsify his application in either instance.
DEA precedents make clear that culpability short of intentional falsification is actionable in these proceedings.
As an initial matter, I conclude that the liability question is not limited to a conviction in which one is directly involved in drug dealing. The “in connection with * * * controlled substances” language is broad in its scope; its intent is to provide the Agency with the information necessary to determine whether an applicant/registrant has committed a felony that may preclude his registration under the CSA.
The text of section 404(a)(2) makes plain that it is not limited to a felony which directly involves drug dealing. As the provision states, a registration may be revoked based on a “convict[ion] of a felony under this subchapter [the CSA] or subchapter II of this chapter [the Controlled Substances Import and Export Act]
Respondent was thus required to provide a “yes” answer to the liability question. This conclusion does not, however, close the inquiry because it must also be determined whether Respondent's answer was material.
“The most common formulation” of the concept of materiality is that “a concealment or misrepresentation is material if it ‘has a natural tendency to influence, or was capable of influencing, the decision of' the decisionmaking body to which it was addressed.”
Taken in isolation, Respondent's answer is material because this Agency “relies upon such answers to determine whether an investigation is needed prior to granting the application.”
This, however, is not such a case. Here, Respondent disclosed his criminal “conviction for accessory after the fact” on the application and this description is an accurate representation of the crime he was charged with and pled guilty to.
The Government also alleges that Respondent materially falsified his application by stating that “I also voluntarily surrendered my DEA # to prescribe medications.”
The Government argues, however, that Respondent's statement was a material falsification because Respondent's DEA “number actually was revoked pursuant to a final order.” Gov. Exceptions at 9. The Government further points to the ALJ's finding that “ ‘Respondent's mere failure to request a hearing or to contest the revocation proceedings is insufficient for a finding of a voluntary surrender of his DEA’ ” registration.
It is true that Respondent's registration was revoked pursuant to a final order and was not voluntarily surrendered. But neither the CSA nor DEA's regulations define the respective terms and no agency precedent explains that there are consequential differences between them.
Most significantly, even if the statement would—if viewed in isolation—be capable of influencing the decision by inducing a more favorable view of Respondent's application—the fact remains that the statement immediately followed Respondent's factually accurate representation that he had surrendered his state license “as a result of [his] conviction for accessory after the fact.” Gov. Ex. 5, at 2. In short, viewed in context, Respondent's statements clearly placed agency personnel on notice that his application should not be summarily approved, but rather, subjected to an investigation. I thus hold that even though Respondent's statement was false, it was not capable of influencing the decision and is thus not material. I therefore conclude that the Government's allegations that Respondent materially falsified his application are without merit and turn to the public interest factors.
As explained above, in Section 303(f), Congress directed that I consider five factors in determining whether granting Respondent's registration would be “inconsistent with the public interest.” 21 U.S.C. 823(f). While I consider Respondent's criminal conduct to be outrageous, having considered all of the factors and our precedents, I conclude that he is entitled to be registered.
As the ALJ found, following his release from prison, the Tennessee Board of Dentistry reinstated Respondent's license without conditions. While this factor is not dispositive, see
Significantly, there is no evidence in the record that Respondent ever used his previous DEA registration to illegally dispense a controlled substance. Furthermore, there is no evidence in the record that Respondent ever used his registration to divert controlled substances for personal use. Relatedly, Respondent has never been convicted of a crime directly involving the distribution or dispensing of controlled substances. Thus, both factors support the granting of Respondent's application.
As explained above, Respondent committed a federal criminal offense in violation of 18 U.S.C. 3 and 371, when he entered into a conspiracy with Woods and an informant in which he agreed to assist them in altering their appearance and thereby help them avoid apprehension. Furthermore, even after Woods was apprehended, Respondent agreed to assist the informant. These are truly outrageous acts of criminality.
Proceedings under sections 303 and 304 of the CSA are, however, non-punitive.
As egregious as his conduct is, Respondent committed his crimes more than seven years ago. In the interim, Respondent has served his sentence and there is no evidence that he has violated the terms of his period of supervised release. Respondent pled guilty to the offense, was found by the federal district court to have accepted responsibility, and cooperated with the Task Force in its investigation.
Moreover, in this proceeding, Respondent stated that he had “absolutely” committed a crime, that he could not “blame other people for” his decision to help Woods avoid capture, and that he took “full responsibility for that.” Tr. 150. Of note, Respondent also testified that his conduct “was the absolute worst thing—the only thing I could have done worse was actually murder someone.”
The Government nonetheless contends that Respondent has not sufficiently accepted responsibility. In the Government's view, Respondent “has not been candid about the facts surrounding his conviction,” Gov. Exceptions at 6, because he has maintained in this proceeding that he did not know that Woods and the informant were drug traffickers. The Government also maintains that Respondent was not candid about his motive.
The Government's first contention is disposed of by my finding that the Government's evidence only creates a suspicion that Respondent knew that Woods and the informant were engaged in drug trafficking. Having failed to adduce substantial evidence proving this as a fact, the Government is precluded from arguing that Respondent
The Government further argues that Respondent lacked candor because he “asserted at the hearing that he had no pecuniary motive.”
While I find Respondent's testimony on this point disturbing, the record does not contain sufficient evidence to support a finding that Respondent lacked candor and has not accepted responsibility for his criminal conduct. I thus conclude that factors four and five do not support a finding that Respondent's registration would be inconsistent with the public interest. And having considered all of the factors, I further conclude that Respondent is entitled to be registered.
Pursuant to the authority vested in me by 21 U.S.C. 823(f) and 28 CFR 0.100(b) and 0.104, I order that the application of Samuel S. Jackson, D.D.S., for a DEA Certificate of Registration as a practitioner be, and it hereby is, granted. This order is effective immediately.
The Department of Labor (DOL) has submitted the following public information collection request (ICR) to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995 (Pub. L. 104-13, 44 U.S.C. Chapter 35). A copy of this ICR, with applicable supporting documentation, may be obtained at
Comments should be sent to the Office of Information and Regulatory Affairs, Attn: OMB Desk Officer for U.S. Department of Labor/Employment and Training Administration (ETA), Office of Management and Budget, Room 10235, Washington, DC 20503, 202-395-7316 (this is not a toll free number), within 30 days from the date of this publication in the
The OMB is particularly interested in comments which:
• 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;
• Evaluate 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;
• Enhance the quality, utility and clarity of the information to be collected; and
• Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
Employment and Training Administration (ETA), Labor.
Notice; amendment.
The Employment and Training Administration published a document in the
Linda Forman, Grants Management Specialist, Telephone (202) 693-3416.
In the
The solicitation is amended to read: The agency expects to award approximately 50 grants. The grant amount for each “grassroots” organization will be up to $60,000.
National Science Foundation.
Notice.
Under the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3501 et seq.), and as part of its continuing effort to reduce paperwork and respondent burden, the National Science Foundation (NSF) is inviting the general public and other Federal agencies to comment on this proposed information collection.
Written comments on this notice must be received by June 29, 2007 to be assured of consideration. Comments received after that date will be considered to the extent practicable.
Written comments regarding the information collection and requests for copies of the proposed information collection request should be addressed to Suzanne Plimpton, Reports Clearance Officer, National Science Foundation, 4201 Wilson Boulevard, Room 295, Arlington, VA 22230, or by e-mail to
Suzanne Plimpton on (703) 292-7556 or send e-mail to
Notice is hereby given that pursuant to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
The title for the collection of information is “Form N-3 (17 CFR 239.17a and 274.11b) under the Securities Act of 1933 and under the Investment Company Act of 1940, Registration Statement of Separate Accounts Organized as Management Investment Companies.” Form N-3 is the form used by insurance company separate accounts organized as management investment companies that offer variable annuity contracts to register as investment companies under the Investment Company Act of 1940 (15 U.S.C. 80a-1
The Commission estimates that there are 2 initial registration statements and 30 post-effective amendments to initial registration statements filed on Form N-3 annually and that the average number of portfolios referenced in each initial filing and post-effective amendment is 2. The Commission further estimates that the hour burden for preparing and filing a post-effective amendment on Form N-3 is 154.7 hours per portfolio. The total annual hour burden for preparing and filing post-effective amendments is 9,282 hours (30 post-effective amendments × 2 portfolios × 154.7 hours per portfolio). The estimated annual hour burden for preparing and filing initial registration statements is 3,690.8 hours (2 initial registration statements × 2 portfolios × 922.7 hours per portfolio). The total annual hour burden for Form N-3, therefore, is estimated to be 12,972.8 hours (9,282 hours + 3,690.8 hours).
The information collection requirements imposed by Form N-3 are mandatory. Responses to the collection of information will not be kept confidential. 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 control number
General comments regarding the above information should be directed to the following persons: (i) Desk Officer for the Securities and Exchange Commission, Office of Information and Regulatory Affairs, Office of Management and Budget, Room 10102, New Executive Office Building, Washington, DC 20503 or e-mail to:
Securities and Exchange Commission (“SEC” or the “Commission”).
Notice of Application for exemption pursuant to Section 6(c) of the Investment Company Act of 1940, as amended (the “1940 Act”), for an exemption from the provisions of Sections 9(a), 13(a), 15(a), and 15(b) of the 1940 Act and Rules 6e-2(b)(15) and 6e-3(T)(b)(15) thereunder.
XTF Advisors Trust (the “Trust”) and XTF Advisors LLC, (the “Investment Advisor”), (collectively the “Applicants”).
Applicants request an order pursuant to Section 6(c) of the 1940 Act exempting certain life insurance companies and their separate accounts that currently invest or may hereafter invest in the Insurance Funds (defined below) from the provisions of Sections 9(a), 13(a), 15(a), and 15(b) of the 1940 Act and Rules 6e-2(b)(15) and 6e-3(T)(b)(15) thereunder, to the extent necessary to permit shares of the Trust and shares of any future investment companies that are designed to fund insurance products and for which the Investment Advisor or any of its affiliates may serve as investment manager, investment adviser, subadviser, administrator, principal underwriter or sponsor (each, an “Insurance Fund” and collectively, the “Insurance Funds”) to be sold to and held by: (a) Separate accounts funding variable annuity contracts and variable life insurance policies (collectively “Variable Contracts”) issued by both affiliated life insurance companies and unaffiliated life insurance companies; (b) trustees of qualified group pension and group retirement plans outside of the separate account context (“Qualified Plans”); (c) separate accounts that are not registered as investment companies under the 1940 Act pursuant to exemptions from registration under Section 3(c) of the 1940 Act; (d) any Advisor to an Insurance Fund for the purpose of providing seed capital to an Insurance Fund; and (e) any other account of a Participating Insurance Company permitted to hold shares of an Insurance Fund (“General Accounts”).
The Application was filed on October 17, 2006, and amended on April 17, 2007.
If no hearing is ordered, the requested exemption will be granted. Any interested person may request a hearing on this Application, or ask to be notified if a hearing is ordered. Any requests must be received by the Commission by 5:30 p.m. on May 21, 2007. Request a hearing in writing, giving the nature of your interest, the reason for the request, and the issues you contest. Serve the Applicants with the request, either personally or by mail, and also send it to the Secretary of the Commission, along with proof of service by affidavit, or in the case of any attorney-at-law by certificate. Request notification of the date of a hearing by writing to the Secretary of the Commission.
The Commission: Secretary, Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-1090; Applicants: c/o JoAnn Strasser, Esq., Thompson Hine LLP, 312 Walnut St., Suite 1400, Cincinnati Ohio 45202.
Robert S. Lamont, Jr., Senior Counsel, or Joyce M. Pickholz, Branch Chief, Office of Insurance Products, Division of Investment Management, at (202) 551-6795.
The following is a summary of the Application; the complete Application is available for a fee from the Commission's Public Reference Branch, 100 F Street, NE., Room 1580, Washington, DC 20549-1090 (telephone (202) 551-8090).
1. Each Insurance Fund is registered under the 1940 Act as an open-end management investment company. The Trust was organized under Delaware law on October 10, 2006 and is registered under the 1940 Act as a management investment company (File Nos. 811-21971/333-138261).
2. The Investment Advisor was organized in 2002, under the laws of the State of Delaware, and registered with the Commission under the Investment Advisors Act of 1940, as amended, in 2005. The sole member of the Investment Advisor is XTF L.P., a Delaware limited partnership.
3. Applicants represent that the Trust intends to, and other Insurance Funds may in the future, offer Shares to separate accounts of affiliated and unaffiliated insurance companies in order to fund various types of insurance products. These separate accounts are, or will be, registered as investment companies under the 1940 Act or will be exempt from such registration under Section 3(c) of the 1940 Act (individually a “Separate Account” and collectively the “Separate Accounts”). Insurance companies whose Separate Account(s) may now or in the future own Shares are referred to herein as “Participating Insurance Companies.”
4. Applicants represent that the Participating Insurance Companies have established, or will establish, their own Separate Accounts and design their own Variable Contracts. Each Participating Insurance Company has, or will have, the legal obligation to satisfy all applicable requirements under both State and Federal law. Each Participating Insurance Company may rely on Rule 6e-2 or Rule 6e-3(T) under the 1940 Act, although in connection with the establishment and maintenance of Separate Accounts funding variable life insurance policies some Participating Insurance Companies may rely on individual exemptive orders as well.
5. Applicants state that each Participating Insurance Company on behalf of its Separate Accounts has entered, or will enter, into a participation agreement with each Insurance Fund in which it invests which will govern participation by the Participating Insurance Company in such Insurance Fund (a “Participation Agreement”). The role of the Insurance Fund under this arrangement, insofar as Federal securities laws are applicable, will consist of offering Shares to the Separate Accounts and fulfilling any conditions that the Commission may impose upon granting the order requested herein.
6. Applicants propose that the Insurance Funds also be permitted to offer and/or sell Shares to Qualified Plans administered by a Trustee. Section 817(h) of the Internal Revenue Code of 1986, as amended (the “Code”), imposes certain diversification standards on the underlying assets of Separate Accounts funding Variable Contracts. In particular, the Code provides that Variable Contracts shall not be treated as an annuity contract or life insurance policy for any period (and any subsequent period) for which the underlying assets are not, in accordance with regulations prescribed by the Treasury Department, adequately diversified. On March 2, 1989, the Treasury Department issued Treasury Regulations (Treas. Reg. Section 1.817-
7. Qualified Plans may choose the Shares offered as the sole investment under the Qualified Plan or as one of several investments. Qualified Plan participants may or may not be given an investment choice depending on the terms of the Qualified Plan itself. Exercise of voting rights by participants in any such Qualified Plans, as opposed to the trustees of such Qualified Plans, cannot be mandated by the Applicants. Each Qualified Plan must be administered in accordance with the terms of the Qualified Plan and as determined by its trustee or trustees. To the extent permitted under applicable law, an Advisor may act as investment adviser or trustee to Qualified Plans that purchase Shares.
8. Applicants propose that the Insurance Funds also be permitted to offer and/or sell Shares to an Advisor. The Treasury Regulations permit such sales as long as the return on Shares held by the Advisor or its affiliates is computed in the same manner as for Shares held by the Separate Accounts, and the Advisor does not intend to sell the Shares to the public. The Treasury Regulations impose an additional restriction on sales to an Advisor, who may hold Shares only in connection with the creation of an Insurance Fund. Applicants anticipate that sales will be made to an Advisor for the purpose of providing necessary capital required by Section 14(a) of the 1940 Act. Any Shares purchased by an Advisor will automatically be redeemed if and when the Advisor's investment advisory agreement terminates.
9. Applicants propose that the Insurance Funds also be permitted to offer and/or sell Shares to General Accounts. The Treasury Regulations permit sales to General Accounts as long as the return on Shares held by General Accounts is computed in the same manner as for Shares held by a Separate Account, and the General Accounts do not intend to sell the Shares to the Public. Applicants anticipate that sales may be made to General Accounts for purposes of creation of the Insurance Funds.
1. In connection with the funding of scheduled premium variable life insurance policies issued through a Separate Account registered as a unit investment trust (“UIT”) under the 1940 Act, Rule 6e-2(b)(15) provides partial exemptions from Sections 9(a), 13(a), 15(a), and 15(b) of the 1940 Act. Section 9(a)(2) of the 1940 Act makes it unlawful for any company to serve as an investment adviser or principal underwriter of any UIT, if an affiliated person of that company is subject to disqualification enumerated in Section 9(a)(1) or (2) of the 1940 Act. Sections 13(a), 15(a) and 15(b) of the 1940 Act have been deemed by the Commission to require “pass-through” voting with respect to an underlying investment company's shares. Rule 6e-2(b)(15) provides these exemptions apply only where all of the assets of the UIT are shares of management investment companies “which offer their shares exclusively to variable life insurance separate accounts of the life insurer or of any affiliated life insurance company.” Therefore, the relief granted by Rule 6e-2(b)(15) is not available with respect to a scheduled premium life insurance Separate Account that owns shares of an underlying fund that also offers its shares to a variable annuity Separate Account or a flexible premium variable life insurance Separate Account of the same company or any other affiliated company. The use of a common management investment company as the underlying investment vehicle for both variable annuity and variable life insurance Separate Accounts of the same life insurance company or of any affiliated life insurance company is referred to herein as “mixed funding.”
2. The relief granted by Rule 6e-2(b)(15) also is not available with respect to a scheduled premium variable life insurance Separate Account that owns shares of an underlying fund that also offers its shares to Separate Accounts funding Variable Contracts issued by one or more unaffiliated life insurance companies. The use of a common management investment company as the underlying investment vehicle for Separate Accounts funding Variable Contracts issued by one or more unaffiliated life insurance companies is referred to herein as “shared funding.”
3. Moreover, because the relief under Rule 6e-2(b)(15) is available only where shares are offered exclusively to variable life insurance Separate Accounts of a life insurer or any affiliated life insurance company, additional exemptive relief is necessary if the Shares are also to be sold to Qualified Plans, an Advisor and General Accounts (collectively, “Eligible Purchasers”). Applicants note that if the Shares were sold only to Separate Accounts funding variable annuity contracts and/or Eligible Purchasers, exemptive relief under Rule 6e-2(b)(15) would not be necessary. The relief provided for under this section does not relate to Eligible Purchasers or to a registered investment company's ability to sell its shares to Eligible Purchasers. The use of a common management investment company as the underlying investment vehicle for Separate Accounts funding Variable Contracts issued by affiliated and unaffiliated insurance companies, and for Eligible Purchasers, is referred to herein as “extended mixed and shared funding.”
4. In connection with flexible premium variable life insurance contracts issued through a Separate Account registered under the 1940 Act as a UIT, Rule 6e-3(T)(b)(15) provides partial exemptions from Sections 9(a), 13(a), 15(a) and 15(b) of the 1940 Act. The exemptions granted by Rule 6e-3(T)(b)(15) are available only where all the assets of the Separate Account consist of the shares of one or more registered management investment companies that offer to sell their shares “exclusively to separate accounts of the life insurer, or of any affiliated life insurance companies, offering either scheduled contracts or flexible contracts, or both; or which also offer their shares to variable annuity separate accounts of the life insurer or of an affiliated life insurance company or which offer their shares to any such life insurance company in consideration solely for advances made by the life insurer in connection with the operation
5. Moreover, because the relief under Rule 6e-3(T)(b)(15) is available only where Shares are offered exclusively to Separate Accounts funding Variable Contracts issued by a life insurer or any affiliated life insurance company, additional exemptive relief is necessary if the Shares are also to be sold to Eligible Purchasers. Applicants note that if the Shares were sold only to Separate Accounts funding variable annuity contracts and/or Eligible Purchasers, exemptive relief under Rule 6e-3(T)(b)(15) would not be necessary. The relief provided for under this section does not relate to Eligible Purchasers or to a registered investment company's ability to sell its shares to Eligible Purchasers.
6. Applicants maintain that there is no policy reason for the sale of the Shares to Eligible Purchasers to result in a prohibition against, or otherwise limit a Participating Insurance Company from relying on the relief provided by Rules 6e-2(b)(15) and 6e-3(T)(b)(15). However, because the relief under Rules 6e-2(b)(15) and 6e-3(T)(b)(15) is available only when shares are offered exclusively to certain Separate Accounts, additional exemptive relief may be necessary if the Shares are also to be sold to Eligible Purchasers. Applicants therefore request relief in order to have the Participating Insurance Companies enjoy the benefits of the relief granted in Rules 6e-2(b)(15) and 6e-3(T)(b)(15) even where Eligible Purchasers are investing in the relevant Insurance Fund. Applicants note that if the Shares were to be sold only to Eligible Purchasers, and/or Separate Accounts funding variable annuity contracts, exemptive relief under Rule 6e-2(b)(15) and Rule 6e-3(T)(b)(15) would be unnecessary. The relief provided for under Rules 6e-2(b)(15) and 6e-3(T)(b)(15) does not relate to Eligible Purchasers, or to a registered investment company's ability to sell its shares to Eligible Purchasers.
7. Consistent with the Commission's authority under Section 6(c) of the 1940 Act to grant exemptive orders to a class or classes of persons and transactions, this Application requests relief for the class consisting of Participating Insurance Companies and their Separate Accounts (and to the extent necessary, investment advisers, principal underwriters and depositors of such Separate Accounts).
8. In effect, the partial relief granted in Rules 6e-2(b)(15) and 6e-3(T)(b)(15) under the 1940 Act from the requirements of Section 9 of the 1940 Act limits the amount of monitoring necessary to ensure compliance with Section 9 to that which is appropriate in light of the policy and purposes of Section 9. Those rules recognize that it is not necessary for the protection of investors or the purposes fairly intended by the policy and provisions of the 1940 Act to apply the provisions of Section 9(a) to individuals in a large insurance complex, most of whom will have no involvement in matters pertaining to investment companies in that organization. Applicants assert that it is also unnecessary to apply Section 9(a) of the 1940 Act to the many individuals in various unaffiliated insurance companies (or affiliated companies of Participating Insurance Companies) that may utilize the Insurance Fund as investment vehicles for Variable Contracts. Applicants argue that there is no regulatory purpose in extending the monitoring requirements to embrace a full application of Section 9(a)'s eligibility restrictions because of mixed funding or shared funding and sales to Qualified Plans, an Advisor or General Accounts. Applicants represent that the Participating Insurance Companies and Qualified Plans are not expected to play any role in the management of the Insurance Funds. Applicants argue that those individuals who participate in the management of the Insurance Funds will remain the same regardless of which Separate Accounts or Qualified Plans invest in the Insurance Funds. Applying the monitoring requirements of Section 9(a) of the 1940 Act because of investment by Separate Accounts of Participating Insurance Companies or Qualified Plans would be unjustified and would not serve any regulatory purpose and could reduce the net rates of return realized by contract owners and Qualified Plan holders due to increased monitoring costs.
9. Rules 6e-2(b)(15)(iii) and 6e-3(T)(b)(15)(iii) under the 1940 Act provide exemptions from pass-through voting requirements with respect to several significant matters, assuming the limitations on mixed and shared funding are observed. Rules 6e-2(b)(15)(iii)(A) and 6e-3(T)(b)(15)(iii)(A) provide that the insurance company may disregard the voting instructions of its contract owners with respect to the investments of an underlying fund, or any contract between such a fund and its investment adviser, when required to do so by an insurance regulatory authority (subject to the provisions of Rules 6e-2(b)(5)(i), 6e-2(b)(7)(ii)(A), 6e-3(T)(b)(5)(i) and 6e-3(T)(b)(7)(ii)(A) under the 1940 Act). Rules 6e-2(b)(15)(iii)(B) and 6e-3(T)(b)(15)(iii)(A)(2) provide that an insurance company may disregard the voting instructions of its contract owners if the contract owners initiate any change in an underlying fund's investment policies, principal underwriter or any investment adviser (provided that disregarding such voting instructions is reasonable and subject to the other provisions of Rules 6e-2(b)(5)(ii), 6e-2(b)(7)(ii)(B), 6e-2(b)(7)(ii)(C), 6e-3(T)(b)(5)(ii), 6e-3(T)(b)(7)(ii)(B), and 6e-3(T)(b)(7)(ii)(C) under the 1940 Act).
10. Rule 6e-2 under the 1940 Act recognizes that a variable insurance contract, as an insurance contract, has important elements unique to insurance contracts and is subject to extensive State regulation. In adopting Rule 6e-2(b)(15)(iii), the Commission expressly recognized that State insurance regulators have authority, pursuant to State insurance laws or regulations, to disapprove or require changes in investment policies, investment advisers, or principal underwriters. The Commission also expressly recognized that State insurance regulators have authority to require an insurer to draw from its general account to cover costs imposed upon the insurer by a change approved by contract owners over the insurer's objection. The Commission, therefore, deemed such exemptions necessary “to assure the solvency of the life insurer and performance of its contractual obligations by enabling an insurance regulatory authority or the life insurer to act when certain proposals reasonably could be expected to increase the risks undertaken by the life insurer.” In this respect, flexible premium variable life insurance contracts are identical to scheduled premium variable life insurance contracts. Therefore, the corresponding provisions of Rule 6e-3(T) under the 1940 Act undoubtedly were adopted in recognition of the same factors.
11. Applicants also assert that the sale of Shares to Qualified Plans, an Advisor and General Accounts will not have any impact on the relief requested herein. With respect to Qualified Plans, which are not registered as investment companies under the 1940 Act, shares of a portfolio of an investment company sold to a Qualified Plan must be held by the trustee(s) of the Qualified Plan pursuant to Section 403(a) of the Employee Retirement Income Security Act (“ERISA”). Applicants note that (1) Section 403(a) of ERISA endows Qualified Plan trustees with the exclusive authority and responsibility for voting proxies provided neither of two enumerated exceptions to that
12. Applicants argue that an Advisor and General Accounts are similar in that they are not subject to any pass-through voting requirements. Applicants therefore, conclude that unlike the case with insurance company Separate Accounts, the issue of resolution of material irreconcilable conflicts with respect to voting is not present with Eligible Purchasers.
13. Applicants represent that where a Qualified Plan does not provide participants with the right to give voting instructions, the trustee or named fiduciary has responsibility to vote the shares held by the Qualified Plan. Accordingly, Applicants argue that even if an Advisor or an affiliate of an Advisor were to serve in the capacity of trustee or named fiduciary with voting responsibilities, an Advisor or its affiliates would have a fiduciary duty to vote relevant Shares in the best interest of the Qualified Plan participants.
14. Further, Applicants assert that even if a Qualified Plan were to hold a controlling interest in an Insurance Fund, Applicants do not believe that such control would disadvantage other investors in such Insurance Fund to any greater extent than is the case when any institutional shareholder holds a majority of the voting securities of any open-end management investment company. In this regard, Applicants submit that investment in an Insurance Fund by a Qualified Plan will not create any of the voting complications occasioned by mixed funding or shared funding. Unlike mixed funding or shared funding, Qualified Plan investor voting rights cannot be frustrated by veto rights of insurers or State regulators.
15. Where a Qualified Plan provides participants with the right to give voting instructions, Applicants see no reason to believe that participants in Qualified Plans generally or those in a particular Qualified Plan, either as a single group or in combination with participants in other Qualified Plans, would vote in a manner that would disadvantage Variable Contract holders. Applicants assert that the purchase of Shares by Qualified Plans that provide voting rights does not present any complications not otherwise occasioned by mixed or shared funding.
16. Applicants do not believe that the sale of the Shares to Qualified Plans will increase the potential for material irreconcilable conflicts of interest between or among different types of investors. In particular, Applicants see very little potential for such conflicts beyond those that would otherwise exist between Variable Contract owners.
17. Applicants assert that permitting an Insurance Fund to sell its shares to an Advisor or to the General Account of a Participating Insurance Company will enhance management of each Insurance Fund without raising significant concerns regarding material irreconcilable conflicts. Unlike the circumstances of many investment companies that serve as underlying investment media for variable insurance products, an Insurance Fund may be deemed to lack an insurance company “promoter” for purposes of Rule 14a-2 under the 1940 Act. Accordingly, any Insurance Funds that are established as new registrants may be subject to the requirements of Section 14(a) of the 1940 Act, which generally requires that an investment company have a net worth of $100,000 upon making a public offering of its shares. Insurance Funds also will require more limited amounts of initial capital in connection with the creation of any new series of Shares and the voting of initial Shares of such series on matters requiring the approval of Shareholders. A potential source of the requisite initial capital is an Insurance Fund's investment adviser or a Participating Insurance Company. Either of these parties may have an interest in making the requisite capital investment and in participating with an Insurance Fund in its organization. However, provision of seed capital or the purchase of shares in connection with the management of an Insurance Fund by its investment adviser or by a Participating Insurance Company may be deemed to violate the exclusivity requirement of Rule 6e-2(b)(15) and/or Rule 6e-3(T)(b)(15).
18. Given the conditions of Treas. Reg. Section 1.817-5(f)(3) and the harmony of interest between an Insurance Fund, on the one hand, and an Advisor or a Participating Insurance Company, on the other, Applicants assert that little incentive for overreaching exists. Applicants further assert that such investment should not implicate the concerns discussed above regarding the creation of material irreconcilable conflicts. Instead, Applicants argue that permitting investments by an Advisor, or by General Accounts, will permit the orderly and efficient creation of an Insurance Fund, and reduce the expense and uncertainty of using outside parties at the early stages of the Insurance Fund's operations.
Applicants consent to the following conditions with respect to each Insurance Fund:
1. A majority of the Board of each Insurance Fund will consist of persons who are not “interested persons” of the Insurance Fund, as defined by Section 2(a)(19) of the 1940 Act, and the rules thereunder, and as modified by any applicable orders of the Commission, except that if this condition is not met by reason of death, disqualification or bona fide resignation of any trustee or trustees, then the operation of this condition will be suspended: (a) For a period of 90 days if the vacancy or vacancies may be filled by the Board; (b) for a period of 150 days if a vote of shareholders is required to fill the vacancy or vacancies; or (c) for such longer period as the Commission may prescribe by order upon application.
2. The Board of each Insurance Fund will monitor the Insurance Fund for the existence of any material irreconcilable conflict between the interests of the contract owners of all Separate Accounts and participants of all Qualified Plans investing in the Insurance Fund, and determine what action, if any should be taken in response to such conflicts. A material irreconcilable conflict may arise for a variety of reasons, including: (a) An action by any State insurance regulatory authority; (b) a change in applicable Federal or State insurance, tax, or securities laws or regulations, or a public ruling, private letter ruling, no-action or interpretive letter, or any similar action by insurance, tax or securities regulatory authorities; (c) an administrative or judicial decision in any relevant proceeding; (d) the manner in which the investments of the Insurance Fund are being managed; (e) a difference in voting instructions given by variable annuity contract owners, variable life insurance contract owners, and trustees of the Qualified Plans; (f) a decision by a Participating Insurance Company to disregard the voting instructions of contract owners; or (g) if applicable, a decision by a Qualified Plan to disregard the voting instructions of Qualified Plan participants.
3. Participating Insurance Companies (on their own behalf, as well as by virtue of any investment of General Account assets in an Insurance Fund), an Advisor, and any Trustee on behalf of any Qualified Plan that executes a Participation Agreement upon becoming an owner of 10 percent or more of the
4. If it is determined by a majority of the Board of an Insurance Fund, or a majority of the disinterested directors/trustees of such Board, that a material irreconcilable conflict exists, then the relevant Participant will, at its expense and to the extent reasonably practicable (as determined by a majority of the disinterested directors/trustees), take whatever steps are necessary to remedy or eliminate the material irreconcilable conflict, up to and including: (a) Withdrawing the assets allocable to some or all of their Separate Accounts from the relevant Insurance Fund and reinvesting such assets in a different investment vehicle including another Insurance Fund, submitting the question as to whether such segregation should be implemented to a vote of all affected contract or policy owners and, as appropriate, segregating the assets of any appropriate group (
5. The determination by the Board of each Insurance Fund of the existence of a material irreconcilable conflict and its implications will be made known in writing promptly to all Participants.
6. As to Variable Contracts issued by Separate Accounts registered under the 1940 Act, Participating Insurance Companies will provide pass-through voting privileges to all Variable Contract owners as required by the 1940 Act as interpreted by the Commission. However, as to Variable Contracts issued by unregistered Separate Accounts, pass-through voting privileges will be extended to contract owners to the extent granted by the issuing insurance company. Accordingly, such Participants, where applicable, will vote the Shares held in their Separate Accounts in a manner consistent with voting instructions timely received from Variable Contract owners. Participating Insurance Companies will be responsible for assuring that each Separate Account investing in the relevant Insurance Fund calculates voting privileges in a manner consistent with other Participants. The obligation to calculate voting privileges as provided in this Application will be a contractual obligation of all Participating Insurance Companies under their Participation Agreement with the relevant Insurance Fund. Each Participating Insurance Company will vote Shares for which it has not received timely voting instructions, as well as Shares held in its General Account or otherwise attributed to it, in the same proportion as it votes those Shares for which it has received voting instructions. Each Qualified Plan will vote as required by applicable law and governing Qualified Plan documents.
7. As long as the 1940 Act requires pass-through voting privileges to be provided to Variable Contract owners, an Advisor, who has provided seed capital for the Insurance Fund, and any General Account will vote their respective Shares in the same proportion as all variable contract owners having voting rights with respect to that Insurance Fund; provided, however, that an Advisor or any General Account shall vote its Shares in such other manner as may be required by the Commission or its staff.
8. Each Insurance Fund will comply with all provisions of the 1940 Act requiring voting by shareholders, which, for these purposes, shall be the persons having a voting interest in the Shares, and, in particular, the Insurance Fund will either provide for annual meetings (except to the extent that the
9. An Insurance Fund will make its Shares available to the Separate Accounts and Qualified Plans at or about the time it accepts any seed capital from an Advisor or General Account of a Participating Insurance Company.
10. Each Insurance Fund has notified, or will notify, all Participants that Separate Account prospectus disclosure or Qualified Plan prospectuses or other Qualified Plan disclosure documents regarding potential risks of mixed and shared funding may be appropriate. Each Insurance Fund will disclose in its prospectus that: (a) Shares of the Insurance Fund may be offered to Separate Accounts funding both variable annuity contracts and variable life insurance policies and, if applicable, to Qualified Plans; (b) due to differences in tax treatment and other considerations, the interests of various contract owners participating in the Insurance Fund and the interests of Qualified Plans investing in the Insurance Fund, if applicable, may conflict; and (c) the Insurance Fund's Board will monitor events in order to identify the existence of any material irreconcilable conflicts and to determine what action, if any, should be taken in response to any such conflict.
11. If and to the extent that Rule 6e-2 and Rule 6e-3(T) under the 1940 Act are amended, or proposed Rule 6e-3 under the 1940 Act is adopted, to provide exemptive relief from any provision of the 1940 Act, or the rules promulgated thereunder, with respect to mixed or shared funding, on terms and conditions materially different from any exemptions granted in the order requested in this Application, then each Insurance Fund and/or Participating Insurance Companies, as appropriate, shall take such steps as may be necessary to comply with Rules 6e-2 or 6e-3(T), or Rule 6e-3, as such rules are applicable.
12. Each Participant, at least annually, will submit to the Board of each Insurance Fund such reports, materials or data as the Board reasonably may request so that the directors/trustees of the Board may fully carry out the obligations imposed upon the Board by the conditions contained in this Application. Such reports, materials and data will be submitted more frequently if deemed appropriate by the Board of an Insurance Fund. The obligations of the Participants to provide these reports, materials and data to the Board, when it so reasonably requests, will be a contractual obligation of all Participants under their Participation Agreement with the relevant Insurance Fund.
13. All reports of potential or existing conflicts received by the Board of each Insurance Fund, and all Board action with regard to determining the existence of a conflict, notifying Participants of a conflict and determining whether any proposed action adequately remedies a conflict, will be properly recorded in the minutes of the Board or other appropriate records, and such minutes or other records shall be made available to the Commission upon request.
14. Each Insurance Fund will not accept a purchase order from a Qualified Plan if such purchase would make the Qualified Plan an owner of 10 percent or more of the assets of the Insurance Fund unless the Trustee for such Qualified Plan executes an agreement with the Insurance Fund governing participation in the Insurance Fund that includes the conditions set forth herein to the extent applicable. A Trustee for a Qualified Plan will execute an application containing an acknowledgement of this condition at the time of its initial purchase of Shares.
Applicants submit that, for the reasons summarized above and to the extent necessary or appropriate to provide for the transactions described herein, the requested exemptions from Sections 9(a), 13(a), 15(a), and 15(b) of the 1940 Act and Rules 6e-2(b)(15) and 6e-3(T)(b)(15) thereunder, in accordance with the standards of Section 6(c) of the 1940 Act, are in the public interest and consistent with the protection of investors and the purposes fairly intended by the policy and provisions of the 1940 Act.
For the Commission, by the Division of Investment Management, pursuant to delegated authority.
Notice is hereby given, pursuant to the provisions of the Government in the Sunshine Act, Public Law 94-409, that the Securities and Exchange Commission will hold the following meeting during the week of April 30, 2007:
A Closed Meeting will be held on Thursday, May 3, 2007 at 2 p.m.
Commissioners, Counsel to the Commissioners, the Secretary to the Commission, and recording secretaries will attend the Closed Meeting. Certain staff members who have an interest in the matters may also be present.
The General Counsel of the Commission, or his designee, has certified that, in his opinion, one or more of the exemptions set forth in 5 U.S.C. 552b(c)(3), (4), (5), (7), (8), (9)(B), and (10) and 17 CFR 200.402(a)(3), (4), (5), (7), (8), 9(ii) and (10), permit consideration of the scheduled matters at the Closed Meeting.
Commissioner Casey, as duty officer, voted to consider the items listed for the closed meeting in closed session.
The subject matter of the Closed Meeting scheduled for Thursday, May 3, 2007 will be:
Formal orders of investigations;
Institution and settlement of injunctive actions;
Institution and settlement of administrative proceedings of an enforcement nature;
Regulatory matters regarding financial institutions; an adjudicatory matter; and
Other matters related to enforcement proceedings.
At times, changes in Commission priorities require alterations in the scheduling of meeting items.
For further information and to ascertain what, if any, matters have been added, deleted or postponed, please contact: The Office of the Secretary at (202) 551-5400.
Pursuant to section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange proposes to list and trade notes linked to the performance of the Dow Jones-AIG Commodity Index Total Return (the “Index”). The text of the proposal is available at Amex, the Commission's Public Reference Room, and
In its filing with the Commission, Amex 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, and the most significant aspects of such statements are set forth in sections A, B, and C below.
Under section 107(A) of the Amex
The Exchange states that the Notes will conform to the initial listing guidelines under section 107(A) of the Company Guide and the continued listing guidelines under sections 1001-1003 of the Company Guide. The Notes are senior, non-convertible debt securities of Lehman and have a term of thirteen months. The Notes are cash-settled in U.S. dollars and do not give the holder any right or other ownership interest in the Index or commodities comprising the Index. The Notes are designed for investors who desire to participate in, or gain exposure to, an index composed of a basket of actively-traded commodities and receive monthly coupon interest payments, and who are willing to forego principal protection on the Notes during such term. Lehman will issue the Notes in denominations of whole units, with each unit representing a single Note. The original public offering price will be $1,000 per Note.
Unless the Notes have been redeemed earlier, at maturity, a holder would receive per each $1,000 Note, a cash amount equal to the Daily Value (as defined herein) per $1,000 Note as of the Valuation Date,
Lehman may redeem the Notes early if, on any Index Business Day prior to the Valuation Date, the Daily Value per $1,000 Note falls below a certain pre-determined amount. This day is known as the “Early Redemption Determination Date.” This pre-determined amount will be determined at the time of issuance of the Notes. In the event of redemption, Lehman will pay an amount per $1,000
If an event of default occurs and the maturity of the Notes are accelerated, Lehman will pay holders an amount equal to the amount that would have been payable at maturity, calculated as though the date of acceleration was the stated maturity date, and the date three Index Business Days before the date of acceleration was the Valuation Date. If a bankruptcy proceeding is commenced, the claims of a holder of a Note may be limited.
The Index, developed by AIGI, is a proprietary index that is calculated by Dow Jones, AIGI, and AIG Financial Products Corp. (“AIG-FP” and, together with AIGI and Dow Jones, the “Sponsors”) and published by Dow Jones.
The Index is re-weighted and re-balanced each year in January on a price-percentage basis. The annual weightings for the Index are determined each year in June or July by AIG-FP under the supervision of the Index Supervisory Committee,
The Index is designed to track rolling futures positions in a diversified basket of 19 exchange-traded futures contracts on physical commodities. The 19 physical commodities selected for 2007 are aluminum, coffee, copper, corn, cotton, crude oil, gold, heating oil, lean hogs, live cattle, natural gas, nickel, silver, soybeans, soybean oil, sugar, unleaded gasoline, wheat, and zinc. Unlike equities, which typically entitle the holder to a continuing stake in a corporation, commodity futures contracts normally specify a certain date for the delivery of the underlying physical commodity. The Index tracks what is known as a rolling futures position, which is a position where, on a periodic basis, futures contracts on physical commodities specifying delivery on a nearby date must be sold and futures contracts on physical commodities that have not yet reached the delivery period must be purchased. An investor with a rolling futures position is able to avoid delivering underlying physical commodities while maintaining exposure to those commodities. The rollover for each Index component occurs over a period of five DJ-AIG Business Days each month according to a pre-determined schedule.
The 19 physical commodities selected for inclusion in the Index for 2007, and their respective weightings, are as follows:
Futures contracts on the Index are currently listed for trading on CBOT. The Index commodities currently trade on United States (“U.S.”) exchanges, with the exception of aluminum, nickel and zinc, which trade on the London Metal Exchange (“LME”).
The Sponsors have established a two-tier committee structure to assist them in connection with the operation of the Index.
The Designated Contracts for the Index commodities included in the Index for 2007 are traded on LME, CBOT, the New York Board of Trade (“NYBOT”),
The relative weightings of the component commodities included in the Index are determined annually according to both liquidity and dollar-adjusted production data in
The Index is designed to provide diversified exposure to commodities as an asset class. To ensure that no single commodity or commodity sector dominates the Index, the following diversification rules are applied to the annual re-weighting and re-balancing of the Index as of January of the applicable year:
• No related group of commodities designated as a commodity group (
• No single commodity may constitute more than 15% of the Index.
• No single commodity, together with its derivatives (
Following application of the diversification rules, CIPs are incorporated into the Index by calculating the new unit weights for each Index commodity. Near the beginning of each new calendar year, the CIPs, along with the settlement prices on that date for designated contracts included in the Index, are used to determine a commodity index multiplier (“CIM”) for each Index commodity. This CIM is used to achieve the percentage weightings of the Index commodities, in dollar terms, indicated by their respective CIPs. After the CIMs are calculated, they remain fixed throughout the year. As a result, the observed price percentage of each Index commodity will float throughout the year until the CIMs are reset the following year based on new CIPs.
The Index is calculated by the Sponsors by applying the impact of the changes to the futures prices of commodities included in the Index (based on their relative weightings). Once the CIMs are determined, the calculation of the Index is a mathematical process whereby the CIMs for the Index commodities are multiplied by the prices in U.S. dollars for the applicable designated contracts. These products are then summed (during the rollover period, the sum includes both nearby and deferred contracts weighted according to the specified roll percentage). The percentage change in this sum from the sum of the prior day is then applied to the prior Index level to arrive at the current Index value. Finally, the returns on cash collateral invested in Treasury Bills, which are calculated using the most recent weekly auction high rate for 91-day Treasury Bills, are added to the current Index value to arrive at the Index level.
From time to time, disruptions can occur in trading futures contracts on various commodity exchanges. The daily calculation of the Index may be adjusted in the event that the Sponsors determine that any of the following Index calculation disruption events exists:
• The termination or suspension of, or material limitation or disruption in, the trading of any futures contract used in the calculation of the Index on that day;
• The settlement price of any futures contract used in the calculation of the Index reflects the maximum permitted price change from the previous day's settlement price;
• The failure of an exchange to publish settlement prices for any futures contract used in the calculation of the Index; or
• With respect to any futures contract used in the calculation of the Index that trades on LME, a business day on which LME is not open for trading.
Amex represents that the Notes will trade on the Exchange subject to existing Amex trading rules applicable to the Notes
The Exchange represents that it prohibits the initial and/or continued listing of any security that is not in compliance with Rule 10A-3 under the Act.
The Exchange states that it will halt trading in the Notes if the circuit breaker parameters of Amex Rule 117 have been reached. In exercising its discretion to halt or suspend trading in the Notes, the Exchange may consider factors such as those set forth in Amex Rule 918C(b), in addition to other factors that may be relevant. In particular, if the Index value is not being disseminated as required, the Exchange may halt trading during the day in which the interruption to the dissemination of the Index value occurs. If the interruption to the dissemination of the Index value persists past the trading day on which it occurred, the Exchange will halt trading no later than the beginning of the trading day following the interruption.
The Exchange represents that its surveillance procedures are adequate to properly monitor the trading of the Notes. Specifically, Amex will rely on its existing surveillance procedures governing index-linked securities which are similar to its surveillance procedures governing exchange-traded funds and trust-issued receipts. With regard to the Index components, the Exchange currently has in place a comprehensive surveillance sharing arrangement with ICE, LME, and NYMEX, for the purpose of providing information in connection with trading in or related to futures contracts comprising the Index and traded on their respective exchanges. The Exchange also notes that CBOT, CME, and NYBOT are members of the Intermarket Surveillance Group (“ISG”). As a result, the Exchange asserts that it can obtain all necessary market surveillance information,
The Exchange will, prior to trading the Notes, distribute an Information Circular to its membership providing guidance with regard to member firm compliance responsibilities (including suitability recommendations)
The proposed rule change is consistent with Section 6 of the Act,
The Exchange does not believe that the proposed rule change would impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
The Exchange did not receive any 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. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form
• Send an e-mail to
• Send paper comments in triplicate to Nancy M. Morris, Secretary, Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-1090.
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”)
Amex proposes to adopt changes to Rule 126A—AEMI in order to fully conform the list of circumstances described therein with additional exceptions (a) Listed in Rule 611(b) of Regulation NMS
The text of the proposed rule change is available on Amex's Web site at
In its filing with the Commission, Amex 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. Amex has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The Exchange is currently operating, and has adopted rules in connection with the operation of, its new hybrid market trading platform for equity products and exchange traded funds, designated as AEMI
The current proposed changes are intended to expand the list of exceptional circumstances in Rule 126A—AEMI to include: (i) An additional exception from Rule 611(b)(9) of Regulation NMS
The Exchange asserts that the proposal to effect the foregoing changes to the AEMI trading system does not significantly affect the protection of investors or the public interest, does not impose any significant burden on competition, and does not have the effect of limiting the access to or availability of the system.
The proposed rule change is designed to be consistent with Regulation NMS, as well as consistent with Section 6(b) of the Act,
The proposed rule change will impose no burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were solicited or received with respect to the proposed rule change.
Because the proposed rule change does not: (1) Significantly affect the protection of investors or the public interest; (2) impose any significant burden on competition; and (3) have the effect of limiting the access to or availability of an existing order entry or trading system of the Exchange, the foregoing rule change has become effective immediately pursuant to Section 19(b)(3)(A)(iii) 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. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form at
• Send an e-mail to
• Send paper comments in triplicate to Nancy M. Morris, Secretary, Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-1090.
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”),
CBOE proposes to increase the class quoting limit in ten option classes. The text of the proposed rule change is available on CBOE's Web site
In its filing with the Commission, 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.
CBOE Rule 8.3A, Maximum Number of Market Participants Quoting Electronically per Product, establishes class quoting limits (“CQLs”) for each class traded on the Hybrid Trading System.
Rule 8.3A, Interpretation .01(c) provides a procedure by which the President of the Exchange may increase the CQL for a particular product. In this regard, the President of the Exchange may increase the CQL in exceptional circumstances, which are defined in the rule as “substantial trading volume, whether actual or expected.”
The trading volume in these option classes recently has increased substantially. Increasing the CQL in these classes will enable the Exchange to enhance the liquidity offered, thereby offering deeper and more liquid markets.
CBOE believes the proposed rule change is consistent with the Act and the rules and regulations under the Act applicable to a national securities exchange and, in particular, the requirements of section 6(b) of the Act.
CBOE 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 neither received nor solicited written comments on the proposal.
The foregoing proposed rule change will take effect upon filing with the Commission pursuant to Section 19(b)(3)(A)(i) of the Act
At any time within 60 days of the filing of the proposed rule change, the Commission may summarily abrogate such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes 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. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an e-mail to
• Send paper comments in triplicate to Nancy M. Morris, Secretary, Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-1090.
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” or “Exchange Act”),
Nasdaq proposes to adopt rules to govern participation in the NASDAQ Options Market, LLC (“NOM”), which will be an options exchange facility of Nasdaq. Nasdaq represents that NOM will operate a fully automated, price/time priority execution system built on the core functionality of Nasdaq's recently-approved Single Book equities platform, meaning that Nasdaq will operate its options market much as it operates its cash equities market today.
Nasdaq believes that NOM will benefit individual investors, options trading firms, and the options market generally. The entry of an innovative, low cost competitor such as Nasdaq will promote competition, spurring existing markets to improve their own execution systems and reduce trading costs. NOM will differentiate its market by offering executions in price/time priority, a feature that should increase order interaction and yield better executions. NOM's execution system will be designed to quote in penny increments where consistent with the Commission's penny pilot program for options, advancing the Commission's efforts to move the industry to penny quoting in an orderly fashion and helping to narrow spreads, reduce payment for order flow, and enhance price competition.
In its filing with the Commission, Nasdaq included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it had received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. Nasdaq has prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements.
Nasdaq is proposing to adopt a series of rules in connection with NOM, which will be a facility of Nasdaq. NOM will operate an electronic trading system developed to trade options (“System”) that will provide for the electronic display and execution of orders in price/time priority without regard to the status of the entities that are entering orders. The System will provide a routing service for orders when trading interest is not present on NOM, and will link with and comply with the obligations of the Plan for the Purpose of Creating and Operating an Intermarket Linkage (“Linkage Plan”).
All Nasdaq members will be eligible to participate in NOM provided that Nasdaq specifically authorizes them to trade in the System. New Nasdaq members will be required to fulfill the requirements of the Nasdaq Rule 1000 Series as well as the incremental requirements set forth in the proposed options rules; existing Nasdaq members will be required to comply with the incremental requirements of the proposed options rules. The proposed rules avoid to the greatest extent possible proposing requirements that overlap with the rules already set forth in the Rule 1000 Series of the Nasdaq Rule Manual.
NOM will have only one category of members, known as “Options Participants.” Only Options Participants will be permitted to transact business on NOM via the System. Nasdaq will authorize any Options Participant who meets certain enumerated qualification requirements to obtain access to NOM. Among other things, Options Participants must be registered as broker-dealers pursuant to the Act and have as the principal purpose of being an Options Participant the conduct of a securities business. Every Options Participant shall at all times maintain membership in another registered options exchange that is not registered solely under Section 6(g) of the Act.
There will be two types of Options Participants, Options Order Entry Firms (“OEFs”) and Options Market Makers. OEFs will be those Options Participants representing customer orders as agent on NOM and non-market maker participants conducting proprietary trading as principal. NOM will not list an options series for trading unless at least one Options Market Maker is registered in that options series. In addition, before NOM opens trading for any additional series of an options class, it would require at least one Options Market Maker to be registered for trading in that particular series. NOM may suspend or terminate any registration of an Options Market Maker when, in NOM's judgment, the interests of a fair and orderly market are best served by such action.
Options Market Makers are Options Participants registered with Nasdaq as Options Market Makers and registered with NOM in one or more series of options listed on NOM. Nasdaq is proposing to permit Options Market Makers to register on a series-by-series basis. Nasdaq does not view NOM as a “one-stop-shop” for trading all options. Nasdaq believes that permitting Options
To become an Options Market Maker, an Options Participant is required to register by filing a written application. NOM will not place any limit on the number of entities that may become Options Market Makers. NOM Options Market Makers will be required to electronically engage in a course of dealing to enhance liquidity available on NOM and to assist in the maintenance of fair and orderly markets. Among other things, Options Market Makers would have to satisfy the following responsibilities and duties during trading: (i) Maintain a two-sided market for at least 10 contracts in at least seventy-five percent (75%) of the options series to which the Options Market Maker is registered; (ii) participate in the opening; and (iii) maintain minimum net capital in accordance with Commission and Nasdaq Rules. Substantial or continued failure by an Options Market Maker to meet any of its obligations and duties will subject the Options Market Maker to disciplinary action, suspension, or revocation of the Options Market Maker's registration in one or more options series.
Options Market Makers receive certain benefits for carrying out their duties. For example, a lender may extend credit to a broker-dealer without regard to the restrictions in Regulation T of the Board of Governors of the Federal Reserve System
Nasdaq is proposing an Order Exposure requirement comparable to that which currently applies on other registered options exchanges. Specifically, as set forth in Chapter VII, Section 14, with respect to orders routed to NOM, Options Participants may not execute as principal orders they represent as agent unless (i) Agency orders are first exposed on NOM for at least three (3) seconds, or (ii) the Options Participant has been bidding or offering on NOM for at least three (3) seconds prior to receiving an agency order that is executable against such bid or offer.
Nasdaq's options trading system will leverage Nasdaq's current state of the art technology, including its customer connectivity, messaging protocols, quotation and execution engine, order router, data feeds, and network infrastructure. This approach minimizes the technical effort required for existing Nasdaq members to begin trading options on NOM. As a result, NOM will closely resemble Nasdaq's equities market, but will differ from most existing options exchanges by, most prominently, offering true price/time priority across all orders and participants rather than differentiating between Participant/trading interest classes.
Like the Nasdaq system for equities, all trading interest entered into the Options Trading System will be automatically executable. Orders entered into the system will be displayed anonymously or with attribution or non-displayed. For Participants seeking to trade anonymously, the NOM execution system will offer fully anonymous trading, however, options trades are not currently anonymous through settlement. NOM will become an exchange member of the Options Clearing Corporation (“OCC”).
At the opening of trading and also at any resumption following a halt, NOM will execute a cross modeled on the Nasdaq Halt Cross. The Halt Cross will be used, rather than the Nasdaq Opening Cross, because the Opening Cross is designed to operate in the midst of a continuous market such as exists for equities prior to 9:30 a.m., whereas the Halt Cross is designed to operate in the absence of a continuous market such as exists for equities that are halted and also exists for options trading at 9:30 a.m. Registered Options Market Makers will be required to participate in the opening of the market by, at a minimum, opening their quotations. Orders may be submitted, modified, and cancelled throughout a brief pre-opening phase preceding the commencement of trading on the market. During this pre-opening phase, NOM will calculate and disseminate a theoretical opening price, order imbalance, and the size and direction of any imbalance. Thereafter, NOM will determine via algorithm a single price at which a particular options series will open and will match via algorithm the maximum number of available orders.
At the close of trading, NOM will conduct a single price cross based upon the Nasdaq Closing Cross for equities. The NOM Closing Cross will utilize the same elements as the opening/halt
“Limit Orders” are orders to buy or sell options at a specified price or better. A limit order is marketable when, for a limit order to buy, at the time it is entered into the System, the order is priced at the current inside offer or higher, or for a limit order to sell, at the time it is entered into the System, the order is priced at the inside bid or lower.
“Discretionary Orders” are orders that have a displayed price and size, as well as a non-displayed discretionary price range, at which the entering party, if necessary, is also willing to buy or sell. The non-displayed trading interest is not entered into the System book but is, along with the displayed size, converted to an Immediate or Cancel (“IOC”) buy (sell) order priced at the highest (lowest) price in the discretionary price range when displayed contracts become available on the opposite side of the market or an execution takes place at any price within the discretionary price range. The generation of this IOC order is triggered by the automatic cancellation of the displayed contracts portion of the Discretionary Order. If more than one Discretionary Order is available for conversion to an IOC order, the system will convert and process all such orders in the same priority in which such Discretionary Orders were entered. If an IOC order is not executed in full, the unexecuted portion of the order is automatically re-posted and displayed in the System book with a new time stamp, at its original displayed price, and with its non-displayed discretionary price range.
“Reserve Orders” are limit orders that have both a displayed size as well as an additional non-displayed amount. Both the displayed and non-displayed portions of the Reserve Order are available for potential execution against incoming orders. If the displayed portion of a Reserve Order is fully executed, the System will replenish the display portion from reserve. A new timestamp is created for the replenished portion of the order each time it is replenished from reserve, while the reserve portion retains the time-stamp of its original entry.
“Minimum Quantity Orders” are orders that require that a specified minimum quantity of contracts be obtained, or the order is cancelled. Minimum Quantity Orders may only be entered with a time-in-force designation of IOC. Minimum Quantity Orders with an IOC time in force received prior to the opening cross will be rejected.
“Market Orders” are orders to buy or sell at the best price available at the time of execution.
“Price Improving Orders” are orders to buy or sell an option at a specified price at an increment smaller than the minimum price variation in the security. Price Improving Orders may be entered in increments as small as one cent. Price improving orders that are available for display will be displayed at the appropriate minimum quotation increment (rounding down to the proper increment for buys, up to the proper increment for sells).
“Expire Time” or “EXPR” are orders that, if after entry into the System, the order is not fully executed, the order (or the unexecuted portion thereof) shall remain available for potential display and/or execution for the amount of time specified by the entering Participant unless canceled by the entering party. EXPR Orders will be available for entry from 8 a.m. until market close and for execution from 9:30 a.m. until market close.
“Immediate Or Cancel” or “IOC” orders are orders that if, after entry into the System, a marketable limit order (or unexecuted portion thereof) becomes non-marketable, the order (or unexecuted portion thereof) will be canceled and returned to the entering participant. IOC Orders will be available for entry from 8 a.m. until market close and for potential execution from 9:30 a.m. until market close. IOC Orders entered between 8 a.m. and 9:30 a.m. Eastern Time will be held within the System until 9:30 a.m. at which time the System shall determine whether such orders are marketable.
“DAY” orders are orders that if, after entry into the System, the order is not fully executed, the order (or unexecuted portion thereof) will remain available for potential display and/or execution until market close, unless canceled by the entering party, after which it shall be returned to the entering party. DAY Orders will be available for entry from 8 a.m. until market close and for potential execution from 9:30 a.m. until market close.
“Good Til Cancelled” or “GTC” orders are orders that if, after entry into System, the order is not fully executed, the order (or unexecuted portion thereof) will remain available for potential display and/or execution unless cancelled by the entering party, or until the option expires, whichever comes first. GTC Orders will be available for entry from 8 a.m. until market close and for potential execution from 9:30 a.m. until market close.
Options Participants will be permitted to enter multiple orders at single or multiple price levels and will have the option to have a portion of their order held in reserve and not displayed to the marketplace.
NOM will participate in the Linkage Plan to receive orders from options exchanges that use the Options Intermarket Linkage (“Linkage”) to route orders. Nasdaq plans to use its proprietary order router to send orders to other options exchanges. Nonetheless, in order to participate and to receive orders, NOM is proposing to adopt rules relating to the Linkage that are substantially similar to the rules in place on all of the options exchanges that are Participants to the Linkage Plan.
In general, the proposed rules contain relevant definitions, establish the conditions pursuant to which Market Makers may enter Linkage orders, impose obligations on NOM regarding how it must process incoming Linkage orders, and establish a general standard that Options Participants should avoid trade-throughs. The proposed NOM Rules establish potential regulatory liability for Options Participants who engage in a pattern or practice of trading through other exchanges, establish obligations with respect to locked and crossed markets, and restrict a market maker on NOM from sending principal orders (other than principal acting as agent [“P/A”] orders), which reflect unexecuted customer orders through the Linkage if the market maker affects less than 80% of specified order flow on NOM.
For those limited instances where Nasdaq does use the Linkage to send orders, Nasdaq is proposing to designate one Market Maker per eligible class as the “InterMarket Linkage Market Maker” or “ILM” to be responsible for settling P/A and Satisfaction orders that would be sent to away markets through the Linkage for a given class of options trading on NOM.
The ILM also will be required to act with due diligence with regard to the interests of orders entrusted to it and fulfill other duties of an agent, including, but not limited to, ensuring that such orders, regardless of their size or source, receive proper representation and timely execution in accordance with the terms of the orders and the rules of NOM. NOM will immediately route all P/A orders on behalf of the ILM according to these instructions. The order would be generated automatically by NOM and routed to the away exchange with the required clearing information included. Each execution received from an away exchange would result in the automatic generation of a trade execution on NOM between the original order and the ILM. This designation of ILM will ensure that P/A and Satisfaction orders will be handled in accordance with the Linkage Plan.
Nasdaq proposes to adopt listing standards for Options traded on NOM (Chapter IV of the proposed rules) as well as for Index Options (Chapter VIX) that are identical to the approved rules of other options exchanges.
Nasdaq proposes to adopt rules that are substantially similar to the approved rules of other options exchanges. Thus, Nasdaq proposes to adopt rules that are substantially similar to the rules of BOX regarding: exercises and deliveries (NOM proposed rules, Chapter VIII); records, reports, and audits (Chapter IX); summaries and suspensions and minor rule violations (Chapter X); doing business with the public (Chapter XI); and margin (Chapter XIII).
Nasdaq proposes to adopt Business Conduct Rules (Chapter III) that are consistent with the BOX Business Conduct Rules, with certain exceptions.
NOM will operate as a full and equal participant in the national market system for options trading established under Section 11A of the Act,
NOM expects to participate in those plans on the same terms currently applicable to current members of those plans, and it expects little or no plan impact due to the fact that NOM's market will operate on price/time priority. Nasdaq has contacted the leadership of each options-related national market system plan to begin the membership process.
NOM will leverage many of the structures that Nasdaq established to operate a national securities exchange in compliance with Section 6 of the Act.
Section 17(d) of the Act and the related Exchange Act rules permit self-regulatory organizations (“SROs”) to allocate certain regulatory responsibilities to avoid duplicative oversight and regulation. Under Exchange Act Rule 17d-1,
Rule 17d-2 under the Act
All of the options exchanges, NASD, and the New York Stock Exchange have entered into the Options Sales Practices Agreement, a Rule 17d-2 agreement. Under this Agreement, the examining SROs will examine firms that are common members of Nasdaq and the particular examining SRO for compliance with certain provisions of the Act, certain of the rules and regulations adopted thereunder, certain examining SRO rules, and certain NOM Rules. In addition, NOM Rules contemplate participation in this Agreement by requiring that any Options Participant also be a member of at least one of the examining SROs.
For those regulatory responsibilities that fall outside the scope of any Rule 17d-2 agreements, Nasdaq will retain full regulatory responsibility under the Exchange Act. However, Nasdaq has entered into a Regulatory Services Agreement with NASD, pursuant to which NASD personnel operate as agents for Nasdaq in performing certain of these functions. As is the case with Nasdaq's equities market, Nasdaq will supervise NASD Regulation and continue to bear ultimate regulatory responsibility.
Finally, as it does with equities, Nasdaq Regulation will perform real-time surveillance of NOM for the purpose of maintaining a fair and orderly market at all times. As it does with Nasdaq's equities trading, Nasdaq Regulation will monitor Nasdaq's options trading market on a real-time basis to identify unusual trading patterns and determine whether particular trading activity requires further regulatory investigation by NASD.
In addition, Nasdaq Regulation will oversee the process for determining and implementing trade halts, identifying and responding to unusual market conditions, and administering Nasdaq's process for identifying and remediating “obvious errors” by and among its Options Participants.
Nasdaq believes that the proposed rule change is consistent with Section 6 of the Act,
Nasdaq does not believe that the proposed rule change will result in any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. Nasdaq operates in an intensely competitive global marketplace for listings, financial products, transaction services, and market data. Relying on its array of services and benefits, Nasdaq competes for the privilege of providing market and listing services to broker-dealers and issuers. Nasdaq's ability to compete in this environment is based in large part on the quality of its trading systems, the overall quality of its market and its attractiveness to the largest number of investors, as measured by speed, likelihood and cost of executions, as well as spreads, fairness, and transparency.
With these aspects of competition as a guide, Nasdaq designed its current proposal to create the fastest, fairest, most transparent, most efficient, and least expensive trading venue available for the trading of options. The proposed system will incorporate the best functional elements from Nasdaq's equity trading system. The resulting system will reduce overall trading costs and increase price competition, both pro-competitive developments. Nasdaq believes that the resulting system will have the pro-competitive effect of spurring further initiative and innovation among market centers and market participants. Market participants that disagree and do not view these developments as pro-competitive, will have the flexibility to use only those functions that improve their trading or to not use the system at all; participation in the system in whole or in part is completely voluntary.
Written comments were neither solicited nor received.
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, as amended, is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form
• Send an e-mail to
• Send paper comments in triplicate to Nancy M. Morris, Secretary, Securities and Exchange Commission, Station Place, 100 F Street, NE., Washington, DC 20549-1090.
All comments received will be posted without change; the Commission does not edit personal identifying information from submissions. You should submit only information that you wish to make publicly available. All submissions should refer to File Number SR-NASDAQ-2007-004 and should be submitted on or before May 22, 2007.
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”),
Nasdaq proposes to reestablish a quotation and trading system for securities that are designated by The PORTAL® Market (“PORTAL” or the “PORTAL® Market”) as PORTAL securities.
The text of the proposed rule change is available on Nasdaq's Web site at
In its filing with the Commission, Nasdaq 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. Nasdaq has prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements.
Nasdaq currently operates the PORTAL Market for securities that were sold in private placements and are eligible for resale under SEC Rule 144A
The sole current function of Nasdaq related to the PORTAL Market is to review whether an issue of privately placed securities meets the eligibility requirements of Rule 144A,
These market-related functions in PORTAL securities as originally approved by the SEC in 1990 did not, however, develop as anticipated. In particular, Nasdaq believes that the NASD's adoption of PORTAL rules that imposed trade reporting for all transactions in PORTAL securities, which occurred at a time when no trade reporting requirements applied to privately-placed securities in general, ultimately were not implemented because of: (1) A cumbersome technology for access to the PORTAL Market computer system for reporting purposes, which was a stand-alone computer system; and (2) resistance to the imposition of trade reporting in Rule 144A equity and in both Rule 144A and SEC-registered debt.
In a continuing effort to encourage trade-reporting in PORTAL-designated securities, the NASD obtained SEC approval in 1998 of an interpretation of the definition of the term “ACT Eligible Security” in NASD Rule 6110(a) for the Automated Confirmation Transaction Service (“ACT”)
On March 6, 2001,
The use of TRACE and ACT for mandatory trade reporting of secondary market transactions in PORTAL securities was intended to address the technological and cost problems that were associated with the reporting of such trades through the stand-alone PORTAL computer system. The SEC also, as part of the same rule change, approved the elimination of a large number of obsolete provisions in the PORTAL rules, including the registration requirements for NASD members and QIBs to trade in a closed system, rules regulating the quotation and trading of PORTAL securities, and the unsuccessful PORTAL trade reporting requirements.
The market, trading, and technological environments for PORTAL securities have evolved. As stated previously, mandatory trade reporting applies to almost all PORTAL securities. Today, pursuant to NASD Rule 6700 Series, trade reports in all PORTAL-designated equity securities are submitted to the NASD's OTC Reporting Facility (“OTC Reporting Facility”)
The existence of mandatory trade reporting for most PORTAL securities has led to an increased interest on the part of the securities industry for greater market transparency in PORTAL securities in the form of centralized quotations and last sale trade information. In addition, technological advances now allow a quotation, trade negotiation, and reporting system to be more easily integrated into the existing PORTAL Market structure.
Nasdaq is proposing to establish an updated version of the PORTAL Market that was originally envisioned when PORTAL was first approved in 1990. The proposed amendments to the PORTAL rules will: (i) Establish qualification requirements for brokers and dealers that are Nasdaq members and QIBs that wish to access PORTAL; and (ii) implement quotation, trade negotiation and trade reporting functions in the PORTAL Market with respect to PORTAL-designated securities. Most of the proposed amendments were previously approved by the Commission with respect to the earlier attempt by the NASD to establish PORTAL as a closed trading system for Rule 144A securities. Nasdaq's proposed PORTAL system is summarized below.
As a matter of practice, PORTAL designation is limited to those Rule 144A securities that are initially sold to QIBs by a broker/dealer acting as initial placement agent or initial purchaser.
PORTAL Dealers and PORTAL Brokers would be permitted to post anonymous one- or two-sided indicative quotations in PORTAL securities that may be accessed by other PORTAL Dealers and Brokers and QIBs qualified as “PORTAL Qualified Investors.”
As part of its original review and approval of a PORTAL trading system, the Commission and its staff granted several exemptions and no-action requests to the NASD as the then-operator of the PORTAL Market and made other related determinations. Nasdaq, through letter requests to be separately submitted to the Commission, will seek the issuance of similar and new exemptions so as to allow the operation of the PORTAL trading system as described in this filing. In summary, Nasdaq is seeking Commission exemptions in the following areas:
Nasdaq believes that the proposed rule change is consistent with the provisions of Section 6 of the Act,
In addition, Nasdaq believes that the proposed rule change is consistent with Section 11A(a)(1) of the Act.
Rule 144A is available only to institutional investors meeting the definition of “qualified institutional buyer” under Rule 144A(a)(1). A seller is required to form a reasonable belief that a purchaser is a “qualified institutional buyer” as the term is defined in Rule 144A(a)(1). With the exception of broker-dealers, a qualified institutional buyer is required to in the aggregate own and invest on a discretionary basis at least $100 million in securities of non-affiliated issuers. The proposed amendments to the PORTAL rules require that any investor applying to qualify as a PORTAL Qualified Investor meet the Rule 144A standards for qualified institutional buyers.
Rule 144A(d)(2) requires that the seller of 144A securities take reasonable steps to ensure that the purchaser is aware that the seller may rely on Rule 144A. To meet this requirement of Rule 144A, the proposed amendments to the PORTAL rules also provide in the designation requirements for PORTAL Qualified Investors that applicants sign an undertaking in a subscriber agreement that states that they are aware that they may purchase a PORTAL security from another qualified investor who may rely on an exemption from the provisions of Section 5 of the Securities Act
The PORTAL rules also have current eligibility requirements for admitting securities into the PORTAL system that parallel the Rule 144A eligibility requirements for securities. The PORTAL rules require, therefore, that the security be eligible to be sold pursuant to Rule 144A under the Securities Act. The application for designation of a PORTAL security requires the submission of specific information necessary to support the applicant's claim that the security meets the requirements of Rule 144A. In addition, the current PORTAL Rules provide Nasdaq with the authority to request any additional information that Nasdaq believes is necessary to make a determination of whether a security is eligible under Rule 144A.
Furthermore, Rule 144A conditions the eligibility of certain securities under Rule 144A on certain information being available to holders and prospective purchasers. Rule 144A(d)(4) provides that, with respect to securities of an issuer that is neither subject to Section 13 of the Act
In addition to structuring the PORTAL rules to provide that participants who comply with its requirements also are in compliance with the requirements of Rule 144A, the proposed rule change would structure PORTAL to limit the possibility that unregistered securities enter the U.S. retail market by requiring that PORTAL-designated securities be assigned a CUSIP or CINS security identification number that is different than the identification number assigned to any securities of the same class that do not satisfy the eligibility requirements for PORTAL securities. Since the original approval of the PORTAL Market, the security explanation protocol employed by S&P related to the CUSIP number assigned to PORTAL securities specifically distinguishes those securities from all other publicly-traded and restricted securities by using the words “Rule 144A” and “PORTAL.” For these reasons, Nasdaq believes that the PORTAL system, as proposed, is reasonably designed to facilitate compliance with Rule 144A, so long as there is compliance with the PORTAL rules and procedures, except where information is not provided on request pursuant to Rule 144A(d)(4).
Nasdaq does not believe that the proposed rule change will result in any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
Written comments were neither solicited nor received.
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. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form
• Send an e-mail to
• Send paper comments in triplicate to Nancy M. Morris, Secretary, Securities and Exchange Commission, Station Place, 100 F Street, NE., Washington, DC 20549-1090.
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 Exchange proposes to amend Commentary .05 to Exchange Rule 1012 in order to extend for a period of one year a pilot program that allows the Exchange to list options classes overlying five individual stocks with strike price intervals of $1.00 where, among other things, the underlying stock closes below $20.00 on the primary market trading it on the day before selection by the Exchange to list pursuant to the pilot, and the Exchange can list $1.00 strike prices on any options classes specifically designated by other securities exchanges that employ a similar pilot program under their rules (“Pilot Program”).
In its filing with the Commission, Phlx 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. Phlx has prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements.
The purpose of the proposed rule change is to extend the Pilot Program for one year until June 5, 2008, so that the Exchange may continue to list options at $1.00 strike price intervals within the parameters specified in Commentary .05 to Phlx Rule 1012.
The Commission approved the Pilot Program allowing the listing of strike prices for options at $1.00 intervals for securities trading under $20.00, and extended it through June 5, 2007.
In July 2003, Phlx chose and listed five options classes with $1 strike price intervals, thereafter listed on a multiple listing basis $1 strike prices options classes that were listed by other options exchanges pursuant to their $1 strike price pilot programs, and currently lists 22 options classes with $1 strike prices.
In the Phlx Pilot Extensions, the Commission indicated that if Phlx sought to extend, expand, or request permanent approval of the Pilot Program, it would be required to include a Pilot Program Report with its filing.
The Exchange believes 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.
No written comments were either solicited or received.
Because the foregoing rule change does not: (1) Significantly affect the protection of investors or the public interest; (2) impose any significant burden on competition; and (3) become operative for 30 days from the date of this filing, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A) of the Act
At any time within 60 days of the filing of the proposed rule change, the Commission may summarily abrogate such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance 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. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an e-mail to
• Send paper comments in triplicate to Nancy M. Morris, Secretary, Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-1090.
For the Commission, by the Division of Market Regulation, pursuant to delegated authority.
U.S. Small Business Administration.
Notice.
This is a Notice of the Presidential declaration of a major disaster for Public Assistance Only for the State of Maine (FEMA-1691-DR), dated 4/20/2007.
Submit completed loan applications to: U.S. Small Business Administration, Processing and Disbursement Center, 14925 Kingsport Road, Fort Worth, TX 76155.
A. Escobar, Office of Disaster Assistance, U.S. Small Business Administration, 409 3rd Street, SW., Suite 6050, Washington, DC 20416.
Notice is hereby given that as a result of the President's major disaster declaration on 4/20/2007, Private Non-Profit organizations that provide essential services of a governmental nature may file disaster loan applications at the address listed above or other locally announced locations.
The following areas have been determined to be adversely affected by the disaster:
The number assigned to this disaster for physical damage is 10851.
Trade and Development Agency.
Notice.
Notice is hereby given of the appointment of members of the Trade and Development Agency's Performance Review Board.
Carolyn Hum, Administrative Officer, Trade and Development Agency, 1000 Wilson Boulevard, Suite 1600, Arlington, VA 22209 (703) 875-4357.
Section 4314(c)(1) through (5), U.S.C., requires each agency to establish, in accordance with regulations prescribed by the Office of Personnel Management, one or more SES performance review boards. The board shall review and evaluate the initial appraisal of a senior executive's performance by the supervisor, along with any recommendations to the appointing authority relative to the performance of the senior executive.
The following have been selected as acting members of the Performance Review Board of the Trade and Development Agency: Leocadia Zak, Deputy Director, U.S. Trade and Development Agency; Geoffrey Jackson, Director for Policy and Program, U.S. Trade and Development Agency; Thomas Hardy, Chief of Staff, U.S. Trade and Development Agency; and James Wilderotter, General Counsel, U.S. Trade and Development Agency.
Federal Highway Administration (FHWA), DOT.
Notice of intent.
The Federal Highway Administration (FHWA) is issuing this notice to advise the public that an Environmental Impact Statement (EIS) will be prepared for a proposed highway project in Knox County, Tennessee.
Ms. Karen M. Brunelle, Planning and Program Management Team Leader, Federal Highway Administration—Tennessee Division Office, 640 Grassmere Park Road, Suite 112, Nashville, TN 37211. 615-781-5772.
A Final EIS (FEIS) was approved for the South Knoxville Boulevard project on June 24, 1977. That FEIS covered a project that started at Chapman Highway (U.S. 441/SR-71) near Longvale Drive and extended northward to State Route 158 (the Central Business District (CBD) Loop) in Knoxville. The segment of that project from the CBD Loop southward to Moody Avenue has been constructed as a four-lane, median divided freeway section, and opened to traffic. Construction plans were prepared for the approved alignment from Moody Avenue southward to Old Sevierville Pike, but this part of the project has not been constructed. The segment of the approved South Knoxville Boulevard alignment between Old Sevierville Pike and Chapman Highway was subsequently determined to have engineering constraints due to several sinkholes along the route.
An Environmental Assessment (EA) was prepared to address an alternate alignment between Old Sevierville Pike and Chapman Highway. The EA was approved by the FHWA on April 25, 2001. A Corridor and Design Public Hearing was conducted on July 31, 2001. A final environmental decision document was not issued. In the spring of 2003, the Tennessee Department of Transportation (TDOT) commissioned the University of Tennessee Center for Transportation to review fifteen proposed TDOT projects across the state. The James White Parkway (also known as South Knoxville Boulevard) Extension was included in those projects. Based on the results of this
During preparation of the EA for the segment of the project between Old Sevierville Pike and Chapman Highway, several environmental issues were identified that suggested other alternative alignments should be studied and evaluated. These identified issues could result in potential significant impacts. Therefore, due to potential environmental impacts in the study area, community concerns, and the desire to extend the project's south terminus, the FHWA in cooperation with TDOT will now prepare an EIS. The EIS will be for a proposal to complete State Route 71, South Knoxville Boulevard, from Governor John Sevier Highway (State Route 168) to Moody Avenue in Knox County, Tennessee, a distance of approximately four miles, depending upon the alternative alignment that could be selected.
Alternatives to be considered include: (1) No-build; (2) a Transportation System Management alternative; (3) one or more build alternatives that could include constructing a roadway on a new location, upgrading existing Chapman Highway (U.S. 441/State Route 33/71), or a combination of both; and (4) other alternatives that may arise from public input. Public scoping meetings will be held for the project corridor. As part of the scoping process, Federal, State, and local agencies and officials; private organizations; citizens; and interest groups will have an opportunity to identify issues of concern and provide input on the purpose and need for the project, range of alternatives, methodology, and the development of the EIS. A Coordination Plan will be developed to include the public in the project development process. This plan will utilize the following outreach efforts to provide information and solicit input: newsletters; an internet website; e-mail and direct mail; informational meetings and briefings; public hearings; and other efforts as necessary and appropriate. A public hearing will be held upon completion of the Draft EIS and public notice will be given of the time and place of the hearing. The Draft EIS will be available for public and agency review and comment prior to the public hearings.
To ensure that the full range of issues related to this proposed action are identified and taken into account, comments and suggestions are invited from all interested parties. Comments and questions concerning the proposed action should be directed to the FHWA contact person at the address provided above.
Federal Highway Administration (FHWA), DOT.
Notice of intent.
The FHWA is reissuing this Notice to advise the public of changes to the Environmental Assessment that was to be prepared for the proposed improvements to the I-94/I-69 corridor and the Black River Bridge in Port Huron Township, MI and changes to the Environmental Impact Statement that was to be prepared for the proposed improvements to the United States Port of entry Plaza for the Blue Water Bridge in St. Clair County, Michigan. This Notice revises the published Notices of Intent of January 27, 2005 and November 7, 2006.
Mr. Ryan Rizzo, Major Projects Manager, Federal Highway Administration, 315 W. Allegan Street, Room 201, Lansing, Michigan 48933, Telephone (517) 702-1833.
The FHWA in cooperation with the Michigan Department of Transportation (MDOT) is preparing an Environmental Impact Statement (EIS) to evaluate alternatives for potential improvements to the United States Border Plaza at the Blue Water Bridge.
The Blue Water Bridge is a major passenger and commercial border crossing between the United States and Canada and is the termination point for I-94 in the United States and for Highway 402 in Canada. MDOT owns and operates the Blue Water Bridge in conjunction with the Canadian Blue Water Bridge Authority (BWBA), MDOT also owns and operates the Blue Water Bridge Border Plaza. Several inspection agencies operate on the United States Plaza. The agencies are responsible for inspecting vehicles, goods, and people entering the United States and include: The Bureau of Customs and border Protection (CBO), the United States Department of Agriculture (USDA), and the Food and Drug Administration (FDA). The inspection agencies lease facilities on the United States Plaza from MDOT through the General Services Administration (GSA), which serves as the Federal-leasing agent. MDOT collects tolls from vehicles departing the United States for Canada on the plaza.
The study area is located within the City of Port Huron and Port Huron Township. The study area consists of approximately 30 blocks (195 acres) of urban land use surrounding the existing plaza and ramps and extends to the west along I-94/I-69 approximately 2.2 miles. The study area includes the Black River Bridge, Water Street interchange, Lapeer Connector interchange, and locations for possible off-site inspection facilities, located north of I-94/I-69 and west of the Water Street interchange.
In September 2002, this project started as an Environmental Assessment (EA) and proceeded through the scoping phase, Purpose and Need documentation, and three public information meetings. As a result of identified potentially significant impacts, FHWA and MDOT concluded in 2004 that an Environmental Impact Statement should be completed. In 2006 after further analysis, it was decided that the project could be split into two environmental documents: and Environmental Assessment for the I-94/I-69 corridor improvements and an Environmental Impact Statement for the plaza project. In early 2007, after additional consultation with stakeholders and interested parties, it was determined that the two separate studies should be merged into one and
Four plaza and transportation improvement alternatives have been identified within the recommended study area. Alternatives will include: (1) No-Build Alternative, (2) Township alternative with a secured I-94 corridor, (3) City alternative with Pine Grove Avenue relocated to the east and an unsecured I-94 corridor.
Agency and citizen involvement will continue to be solicited throughout this process. A public hearing will be held on the Draft Environmental Impact Statement (DEIS). Public notice will be given of the time and place of the hearing. The DEIS will be available for public and agency review and comment prior to the public hearing.
To ensure that the full range of issues related to this proposed action are addressed and all significant issues identified, comments and suggestions are invited from all interested parties. Comments or questions concerning this proposed action and the EIS should be directed to the FHWA at the address provided above.
Federal Motor Carrier Safety Administration (FMCSA), DOT.
Notice; request for public comment.
FMCSA announces the initiation of a project to demonstrate the ability of Mexico-based motor carriers to operate safely in the United States beyond the commercial zones along the U.S.-Mexico border. The project is part of FMCSA's implementation of the North American Free Trade Agreement (NAFTA) cross-border trucking provisions. The demonstration project will allow up to 100 Mexico-domiciled motor carriers to operate throughout the United States for one year. Up to 100 U.S.-domiciled motor carriers will be granted reciprocal rights to operate in Mexico for the same period. Participating Mexican carriers and drivers will be required to comply with all applicable U.S. laws and regulations, including those concerned with motor carrier safety, customs, immigration, vehicle registration and taxation, and fuel taxation. The safety of the participating carriers will be tracked closely by FMCSA and its State partners, a joint U.S.-Mexico monitoring group, and an evaluation panel independent of the Department of Transportation (DOT). The resulting data will be considered carefully before further decisions are made concerning the implementation of the NAFTA trucking provisions.
Comments must be received on or before May 31, 2007.
You may submit comments identified by DOT DMS Docket Number FMCSA-2007-28055 by any of the following methods:
• Web Site:
• Fax: 1-202-493-2251.
• Mail: Docket Management Facility, U.S. Department of Transportation, 400 Seventh Street, SW., Nassif Building, Room PL-401, Washington, DC 20590-0001.
• Hand Delivery: Room PL-401 on the plaza level of the Nassif Building, 400 Seventh Street, SW., Washington, DC, between 9 a.m. and 5 p.m., e.t., Monday through Friday, except Federal holidays.
• Federal eRulemaking Portal: Go to
Mr. Milt Schmidt, Division Chief, North American Borders Division, Federal Motor Carrier Safety Administration, 400 Seventh Street, SW., Washington, DC 20590-0001. Telephone (202) 366-4049; e-mail
Before 1982, Mexico- and Canada-domiciled motor carriers could apply to the Interstate Commerce Commission (ICC) for authority to operate within the United States. As a result of complaints that U.S. motor carriers were not allowed the same access to Mexican and Canadian markets that carriers from those nations enjoyed in this country, the Bus Regulatory Reform Act of 1982 imposed a moratorium on the issuance of new grants of operating authority to motor carriers domiciled, or owned or controlled by someone, in Canada or Mexico. While the disagreement with Canada was quickly resolved, the issue of trucking reciprocity with Mexico was not. Currently, most Mexican carriers are allowed to operate only within the border commercial zones extending approximately 25 miles into the United States. Every year Mexico-domiciled commercial motor vehicles (CMVs) cross into the U.S. about 4.5 million times. U.S.-domiciled motor carriers are not authorized to operate in Mexico at all.
Trucking issues at the U.S./Mexico border were not fully addressed until NAFTA in the early 1990s, when both nations agreed to change their policies. NAFTA required the United States incrementally to lift the moratorium on licensing Mexico-domiciled motor carriers to operate beyond the border zones. On January 1, 1994, the President modified the moratorium and the ICC began accepting applications from Mexico-domiciled passenger carriers to conduct international charter and tour bus operations in the United States. In December 1995, the ICC published a rule and a revised application form for the processing of Mexico-domiciled
After the Administration announced its intent to resume the process for opening the border in 2001, Congress enacted section 350 of the DOT and Related Agencies Appropriations Act for Fiscal Year 2002 (Pub. L. 107-87, 115 Stat. 833, at 864). Section 350 prohibited FMCSA from using Federal funds to review or process applications from Mexico-domiciled motor carriers to operate beyond the border commercial zones until certain preconditions and safety requirements were met. The requirements of section 350 have been reenacted in each subsequent DOT Appropriations Act. The rulemaking requirements of the Act were met by a series of rules published on March 19, 2002 (67 FR 12653, 67 FR 12702, 67 FR 12758, 67 FR 12776) and a further rule published on May 13, 2002 (67 FR 31978).
In November 2002, Secretary of Transportation Norman Mineta certified, as required by section 350(c)(2), that authorizing Mexican carrier operations beyond the border commercial zones does not pose an unacceptable safety risk to the American public. Later that month, the President modified the moratorium to permit Mexico-domiciled motor carriers to provide cross-border cargo and scheduled passenger transportation beyond the border commercial zones. The Secretary's certification was made in response to the June 25, 2002, report of DOT's Office of Inspector General (OIG) on the implementation of safety requirements at the U.S.-Mexico border. In a January 2005 follow-up report, the OIG concluded that FMCSA had sufficient staff, facilities, equipment, and procedures in place to substantially meet the eight Section 350 requirements the OIG was required to review.
On February 23, 2007, United States Secretary of Transportation Mary E. Peters and Mexico Secretary of Communications and Transportation Luis Te
The demonstration project has a one-year limit. It will allow up to 100 Mexico-domiciled motor carriers to operate beyond the border commercial zones and transport international cargo throughout the United States. For purposes of the demonstration project, “international cargo” means cargo transported by Mexico-domiciled motor carriers in CMVs from Mexico to the United States, with no loading in the United States, or from the United States to Mexico, with no unloading in the United States [49 CFR 365.501(b)]. Drivers for participating motor carriers must comply with the entry requirements of the Department of Homeland Security (DHS). Under DHS regulations, “[p]urely domestic [U.S.] service or solicitation [by non-U.S. drivers], in competition with the United States operators [i.e., drivers], is not permitted” [8 CFR 214.2(b)(4)(i)(E)(1)]. Participating motor carriers will be required to comply with all State and Federal environmental and emission regulations. Carriers must certify that their vehicles have been manufactured in accordance with the National Highway Traffic Safety Administration's (NHTSA) Federal Motor Vehicle Safety Standards (FMVSS).
All Mexico-domiciled participants operating in the United States under the demonstration project will be required to comply with all United States safety standards including hours of service, driver medical standards, financial responsibility, drug and alcohol testing, size and weight limits, and the ability to communicate in English. Every Mexico-domiciled CMV scheduled to be used beyond the border commercial zones will undergo an in-depth safety inspection before being allowed to operate in the U.S. and must display a valid Commercial Vehicle Safety Alliance (CVSA) inspection decal indicating it has passed a thorough vehicle inspection. CVSA decals are valid for up to 3 consecutive months, so follow-up inspections on Mexico-domiciled CMVs will be required at least every 3 months. Each vehicle will be checked for a valid CVSA decal every time it enters the U.S., and the validity of each operator's driver's license will also be checked. The display of a valid CVSA decal will not necessarily exempt a vehicle from safety inspections.
Participating motor carriers must file proof of insurance underwritten by a U.S. insurance company and pay State registration fees and State and Federal fuel taxes.
The demonstration project gives participants no exemptions from U.S. safety requirements. In fact, it requires compliance with additional safety requirements not applicable to other motor carriers operating in this country, such as having a current CVSA decal on the vehicle at all times, and passing a safety audit prior to receiving operating authority. Furthermore, under 49 CFR 385.105, FMCSA has developed additional monitoring criteria for Mexico-domiciled motor carriers. Every vehicle operated by these carriers in the U.S. will also be subject to the inspection standards in 49 CFR 365.511.
The demonstration program is reciprocal. Up to 100 U.S.-domiciled motor carriers will be allowed to operate in Mexico on terms similar to those applicable to Mexico-domiciled carriers operating in this country. The Mexican government is finalizing an application form and procedures for use by interested U.S. motor carriers.
To participate in the project, a Mexico-domiciled motor carrier must, pursuant to regulations already in place, submit (1) Form OP-1(MX), entitled “Application to Register Mexican Carriers for Motor Carrier Authority to Operate Beyond U.S. Municipalities and Commercial Zones on the U.S.-Mexico Border”; (2) Form MCS-150, the “Motor Carrier Identification Report”; and (3) notification of the means used to designate agents for service of legal process, either by submitting Form BOC-3, “Designation of Agents—Motor Carriers, Brokers and Freight Forwarders,” or a letter stating that the applicant will use a process agent service that will submit Form BOC-3 electronically. The forms are available on the Internet at
FMCSA has developed special rules that govern Mexico-domiciled motor carriers during the application process and for several years after receiving OP-1(MX) operating authority. They are codified in 49 CFR 365.501 through 365.511. These rules impose requirements on Mexico-domiciled motor carriers in addition to those imposed on U.S. domiciled motor carriers seeking operating authority.
Several hundred Mexico-domiciled carriers have filed a complete OP-1(MX) application, and more applications are expected. The carriers that were ready for an audit were subjected to an extensive vetting process. Those known to transport hazardous materials or passengers were eliminated. All carriers were also checked against the FMCSA enforcement management information database. Carriers were eliminated if there were any enforcement actions pending, such as unpaid fines, unresolved expedited action letters, or operating authority suspensions/revocations. The remaining carriers were then checked against a U.S. database for involvement in illegal drug activities. Those that passed the vetting process were considered for the demonstration project. Other carriers may be considered for the project as new applications are submitted.
From among the currently-eligible prospective participants, FMCSA is in the process of conducting pre-authorization safety audits on a group of motor carriers diverse both in fleet size and geographical location. Of the carrier applicants selected by the Agency for audit, 18 percent are from non-border states in Mexico, while 82 percent are domiciled in one of Mexico's six border states. About 46 percent of the participants are expected to enter the United States through California, 41 percent through Texas/New Mexico, and 13 percent through Arizona. Some 70 percent of the carrier applicants operate small vehicle fleets, while 25 percent have medium-sized and 5 percent have large fleets. For this demonstration program, a small vehicle fleet is 20 trucks or less, while a medium-sized fleet consists of 21 to 100 trucks. A large fleet is anything in excess of 100 trucks.
A Mexico-domiciled carrier must satisfactorily complete the FMCSA-administered pre-authorization safety audit (PASA) required under FMCSA regulations before it is granted provisional authority to operate in the United States beyond the border commercial zones. This pre-authorization audit is not required for U.S.-based motor carriers. The PASA is a review of the carrier's safety management systems including written procedures and records to validate the accuracy of information and certifications provided in the application. The PASA will determine whether the carrier has established and exercises the basic safety management controls necessary to ensure safe operations. The carrier will not be granted provisional operating authority if FMCSA finds that its safety management controls are inadequate, using the standards in Appendix A to Subpart E of 49 CFR part 365. All PASAs performed under the demonstration project will be conducted at the motor carrier's place of business in Mexico. Vehicles the motor carrier intends to use for operations within the U.S. will be inspected and will be required to have a valid CVSA decal affixed or to pass an in-depth North American Standard Truck Inspection.
As required by FMCSA regulations, the carrier will be denied provisional operating authority if the FMCSA can not:
1. Verify the existence of a controlled substances and alcohol testing program consistent with 49 CFR part 40. The Agency will ensure that the carrier has information on collection sites and laboratories it intends to use.
2. Verify a system of compliance with hours-of-service rules in 49 CFR part 395, including recordkeeping and retention;
3. Verify proof of financial responsibility, as required by 49 CFR part 387;
4. Verify records of periodic vehicle inspections, as required by 49 CFR part 396; and
5. Verify that each driver the carrier intends to assign to operate under the demonstration project meets the requirements of 49 CFR parts 383 and 391. This will include confirmation of the validity of each driver's Licencia Federal de Conductor through the Mexican driver license information system and a check of the Commercial Driver's License Information System (CDLIS) for violations, suspensions, etc.
If a carrier successfully completes the PASA and the FMCSA approves its application, the Agency will publish a summary of the application as a preliminary grant of authority in the FMCSA Register, which is available at
Upon granting provisional operating authority, the Agency will assign a unique USDOT Number, including an “X” suffix, which identifies the motor carrier as authorized to operate beyond the municipalities and commercial zones on the U.S.-Mexico border.
The issuance of OP-1(MX) provisional operating authority will supersede any other operating authority the FMCSA may have issued the carrier, including authority to operate within the border commercial zone. The participating carrier's entire U.S. operations will be subject to the terms and limitations in the OP-1(MX) document, including the prohibition on transporting hazardous materials and passengers.
The demonstration project will terminate and all provisional operating authority certificates expire one year from the date FMCSA grants the first provisional certificate.
Provisional operating authority may be suspended or revoked at any time during the demonstration project if FMCSA determines that the carrier's safety performance does not meet the standards established in 49 CFR part 385, subpart B. Operating authority may also be suspended or revoked if the motor carrier is found to have transported hazardous materials or passengers in the U.S., or otherwise to be operating beyond the scope of its provisional authority.
If a Mexico-domiciled motor carrier held FMCSA operating authority to operate exclusively within the border commercial zones (OP-2 authority) before being granted provisional OP-1(MX) operating authority, the certificate of registration to operate exclusively within the border commercial zones will be reinstated at no cost to the motor carrier upon expiration of the demonstration project, providing the carrier's safety record during the project has been satisfactory.
Mexico-domiciled motor carriers are subject to DHS and DOT cabotage requirements and prohibited from providing domestic point-to-point transportation while operating in the U.S. Carriers found to have violated the cabotage requirements will be placed out-of-service under the DOT regulations. DHS could also prohibit the driver from entering the U.S. in the future. FMCSA, in coordination with the International Association of Chiefs of Police (IACP), has developed and provided training to State and local law enforcement agencies on the cabotage requirements.
FMCSA will monitor the operational safety of all Mexico-domiciled motor carriers participating in the demonstration project. To accomplish this, FMCSA will work closely with State commercial vehicle safety agencies, the IACP, CVSA, DHS, and others.
Field monitoring will include inspections of vehicles, verification of compliance with the terms of the provisional operating authority, driver license checks, crash reporting, and initiation of enforcement actions when appropriate. Additionally, a Mexico-domiciled motor carrier committing any violations specified in 49 CFR 385.105(a) and identified through roadside inspections or by other means, may be subject to a compliance review and enforcement action.
Monitoring will also include electronic data collection and analysis. Data collected as a result of field monitoring and other activities will be entered into FMCSA databases. The data will be tracked and analyzed to identify potential safety issues. Appropriate action will be taken to resolve any identified safety issues. This could include suspension or revocation of the provisional operating authority or the initiation of other enforcement action against the carrier or driver.
The DOT and the Mexican Secretari
Enforcement is a key component of the monitoring and oversight effort. FMCSA has trained and provided guidance to Federal and State auditors, inspectors and investigators to ensure their knowledge and understanding of the demonstration project and the procedures for taking enforcement actions against carriers or drivers participating in the project.
To ensure carrier compliance with operating authority limitations, including the prohibition of domestic point-to-point transportation of cargo in the U.S., FMCSA and the IACP have developed and implemented a training program that provides State and local officials detailed information on cabotage regulations and enforcement procedures.
FMCSA is also working with the DHS to develop guidance concerning the enforcement of DHS cabotage regulations. This material will be incorporated into the CVSA North American Standard Inspection Course and provided to roadside enforcement officers.
FMCSA will be issuing policy memoranda and guidance to the Federal field staff, State agencies and others concerning monitoring and enforcement issues, including English language proficiency, inspection of each participating Mexico-domiciled vehicle every time it enters the U.S., enforcement of the Federal Motor Vehicle Safety Standards, and enforcement of the CVSA decal requirement.
To ensure uniformity and effective enforcement, the CVSA has revised the North American Standard Out-of-Service Criteria to include as out-of service criteria, violations of 49 CFR 391.11(b)(2) relating to the driver's ability to communicate in English while operating in the U.S. and violations of 49 CFR 385.103(c) relating to the display of a valid CVSA decal on vehicles operated by project participants.
The DOT will evaluate the success of the demonstration project by examining the safety performance of Mexico-domiciled motor carriers operating in the U.S. Specifically, FMCSA anticipates examining the crash rate of Mexican carriers, convictions of Mexican drivers for violations of U.S. traffic safety laws, the rate at which Mexican drivers and vehicles are placed out of service when inspected in the U.S., violations discovered during pre-authority safety audits, and compliance of Mexican trucking companies with U.S. drug and alcohol testing regulations. These data will be collected through police reporting of crashes and moving violations, uploads of roadside inspection results performed by FMCSA or our State partners, and uploads of safety audits and compliance reviews of Mexican motor carriers performed by FMCSA staff.
The DOT also intends to provide for an independent evaluation of the demonstration project. The Secretary has asked former DOT Inspector General Kenneth Mead, former DOT Deputy Secretary Mortimer Downey and former House Appropriations Sub-Committee Chairman Jim Kolbe to serve on an evaluation panel. The panel will be responsible for evaluating the safety impacts of allowing Mexico-domiciled motor carriers to operate on U.S. roads beyond the border commercial zone. They will operate independently from other monitoring efforts and provide their own assessment of the project. Their conclusions will be considered carefully before a decision is made on a permanent full implementation of the NAFTA trucking provisions.
The FMCSA has decided to request public comment from all interested persons on the demonstration project outlined above. The FMCSA has fulfilled all of the statutory requirements necessary for the lifting of the moratorium against certain Mexico-domiciled motor carriers. The Agency intends the demonstration project to be the means of validating its safety oversight regime.
All comments received before the close of business on the comment closing date indicated at the beginning of this notice will be considered and will be available for examination in the docket at the location listed under the address section of this notice. Comments received after the comment closing date will be filed in the public docket and will be considered to the extent practicable. In addition to late comments, the FMCSA will also continue to file, in the public docket, relevant information that becomes available after the comment closing date. Interested persons should continue to examine the public docket for new material.
Federal Transit Administration (FTA), DOT.
Notice of agency response to comments.
Section 3011(c) of the Safe, Accountable, Flexible, Efficient Transportation Equity Act: A Legacy for Users (“SAFETEA-LU”) authorizes the U.S. Secretary of Transportation (the “Secretary”) to establish and implement a pilot program to demonstrate the advantages and disadvantages of public-private partnerships (“PPPs”) for certain new fixed guideway capital projects (the “Pilot Program”). This notice summarizes and responds to comments solicited by FTA by notice published in the
Shauna J. Coleman, Esq., Federal Transit Administration, Office of the Chief Counsel, U.S. Department of Transportation, 400 Seventh Street, SW., Washington, DC 20590-0001, (202) 366-4011,
Section 3011(c) of the SAFETEA-LU authorizes the Secretary to establish and implement the Pilot Program to demonstrate the advantages and disadvantages of public-private partnerships for certain new fixed guideway capital projects. On March 22, 2006, FTA issued a notice and solicitation for comments with respect to the Secretary's establishment and implementation of the Pilot Program (71 FR 14568). FTA received comments from 19 parties in response to the notice. FTA responds to these comments by topic and in the following order: (A) Statutory background; (B) objective of the Pilot Program; (C) operation of the Pilot Program; (D) common grant rule; (E) seniority of the Federal Interest; and (F) tax-exempt financing.
FTA requested comments on the following questions: (i) What, if any, operative criteria beyond those set forth in the statute should the Secretary adopt to implement the Pilot Program; (ii) what, if any, benefits should the Secretary confer on selected projects; (iii) whether it is significant that section 3011(c) provides no special funding for the Pilot Program; and (iv) what, if any, changes in law or new financial incentives are appropriate or necessary to promote the participation of private enterprise in the delivery and operation of transit systems?
Six commenters responded to this question. Some of these commenters thought that additional operating criteria should not limit the opportunities for creativity and that FTA should allow private, state, and local parties maximum latitude to determine the parameters and merits of potential projects. In addition, several of these commenters recommended that selected projects should incorporate innovative contracting mechanisms.
Five commenters responded to this question. Two commenters submitted general comments on the benefits the Secretary should confer on selected projects. For instance, one commenter generally recommended that FTA tailor the benefits it confers to the particular requirements of a project. Another commenter generally recommended that FTA award PPPs the highest priority available from programs for which such projects apply and qualify. Two commenters recommended that FTA waive strict compliance with one or more New Starts and/or NEPA evaluation requirements. One commenter recommended that FTA support Congressional earmarks for selected projects.
FTA received the following three comments on this question: one commenter thought that it was unremarkable that Congress authorized no special funding for this program; one commenter noted that by not designating any specific source of funding, Congress provided FTA with the flexibility to identify funds and develop program requirements; and one commenter thought Congress intended to limit the use of private investment in PPPs for selected fixed guideway projects.
Three commenters responded to this question. One commenter suggested that FTA reclassify the retirement of a capital debt from an operating expense to a capital expense. Two commenters suggested that providing Federal grant or loan money for developmental or pre-construction work could induce private investment.
FTA requested comments on whether, and on what terms, the Pilot Program should streamline the New Starts application process, specifically with regard to its due diligence and NEPA components, to promote PPPs that would realize significant savings in the procurement of eligible projects.
FTA requested comments regarding how its New Starts application process may be altered to accelerate project delivery without impairing FTA's duties as a steward of Federal funds. Six commenters responded to this question. Two commenters supported the use of contract terms to allocate risk and ensure due diligence. Three commenters recommended that FTA utilize concurrent rather than linear procedures in its New Starts process, and provided specific recommendations on how FTA could alter its New Starts application process. One commenter requested that FTA clarify how the requirement for public accountability and due diligence can be met under the PPP approach.
FTA requested comments on whether, and on what terms, the Pilot Program should streamline its NEPA components to accelerate project delivery without impairing FTA's duties as a steward of the environment.
Several commenters responded to this question. All but one of these commenters supported the acquisition of engineering and design services prior to the issuance of a ROD.
Three commenters responded to this question and all of these commenters supported FTA's adoption of procedures similar to those in section 1503 of SAFETEA-LU, concerning design-build contracts.
One commenter responded to this question. This commenter urged FTA to consider increasing real estate prices as one factor used to establish the imminence of increasing development pressures so that increasing prices in highly developed or rapidly developing areas would permit an agency to rely upon the CE.
Five commenters responded to this question and all of these commenters recommended that FTA should not reopen the NEPA process and/or existing ROD for review of a new impact that is not determined to be substantial.
FTA requested comments on whether, and on what terms, the Pilot Program should provide grants for eligible projects contemplated by long-term operation or concession agreements with private enterprise. Six commenters supported FTA providing grants for eligible projects contemplated by long-term operation or concession agreements with private enterprise. Three commenters offered suggestions as to how the Pilot Program might encourage transit systems to enter into PPPs. One commenter suggested that FTA allow the Pilot Program to privatize all or part of the capital asset. Another commenter suggested FTA provide financial capacity for pre-construction work. One commenter recommended that FTA tie the Pilot Program directly to New Starts funding.
FTA requested comments on whether, and to what extent, the Pilot Program should authorize the use of program income to support a PPP that sponsors an eligible project. Five commenters supported the flexible use of program income.
FTA requested comments on whether, and to what degree, FTA's subordination of priority of repayment of Federal loans would be useful in structuring a PPP. FTA also requested comments on the extent to which loans, loan guarantees, and other credit enhancing devices available under the Transportation Infrastructure Financing and Innovation Act (“TIFIA”) might be used to facilitate the financing of an eligible project. Four commenters supported subordination of the Federal Interest. Three commenters generally supported the use of the loan guarantees available under TIFIA for financing PPPs.
FTA requested comments on the extent to which private activity bonds (“PABs”) or PABs not subject to State population-based bond issuance limits (“new PABs”) might assist in financing an eligible project. Seven commenters generally supported the use of PABs to assist in financing eligible projects.
Nissan North America, Inc. (Nissan) has determined that certain rims on certain vehicles that it produced in 2000 through 2005 do not comply with paragraphs S5.2(a) and S5.2(c) of 49 CFR 571.120, Federal Motor Vehicle Safety Standard (FMVSS) No. 120,
Affected are a total of approximately 5,000 optional dealer accessory wheels that have been sold and have been installed on approximately 1,250 model year 2000 through 2005 Nissan Xterra multipurpose passenger vehicles and Frontier pickup trucks. Specifically, paragraph S5.2 of FMVSS No. 120, rim marking, requires that each rim be marked with certain information on the weather side, including:
S5.2(a) requiring a one-letter designation which indicates the source of the rim's published nominal dimensions, and S5.2(c) requiring the symbol DOT.
The rims installed on the affected vehicles do not contain the markings required by paragraphs S5.2(a) or S5.2(c). Nissan has corrected the problem that caused these errors so that they will not be repeated in future production.
Nissan believes that the noncompliance is inconsequential to motor vehicle safety and that no corrective action is warranted. Nissan states that the affected rims are 16″ x 7″ aluminum alloy, which are commonly available and utilized in the United States. They are a correct specification for mounting 16″ original equipment tires specified for Xterra and Frontier models, and are capable of carrying the gross vehicle weight rating (GVWR) of the vehicle. Nissan first became aware of the noncompliance of these vehicles during a regulatory compliance review that Nissan conducted during March 2006.
Nissan states that no accidents or injuries have occurred, and no customer complaints have been received related to the lack of the markings or any problem that may have resulted from the lack of the markings. Nissan further states that the missing markings do not affect the performance of the wheels or the tire and wheel assemblies.
The rims are marked in compliance with paragraphs S5.2(b), rim size designation; S5.2(d), manufacturer identification; and S5.2(e) month, day and year or month and year of manufacture. The rims are also marked with a 4030S RSD20-10/20 part number.
The tire size is marked on the tire sidewalls, and the owner's manual and tire inflation pressure placard contain the appropriate tire size to be installed on the original equipment rims. Therefore, Nissan does not believe there is a possibility of a tire and rim mismatch as a result of the missing rim markings. All other requirements under FMVSS No. 120 are met.
NHTSA agrees that the noncompliance is inconsequential to motor vehicle safety. The rims are marked in compliance with paragraphs S5.2(b) rim size designation; S5.2(d) manufacturer identification; and S5.2(e) month, day and year or month and year of manufacture. The rims are also marked with a part number. The tire size is marked on the tire sidewalls, and the owner's manual and tire inflation pressure placard contain the appropriate tire size to be installed on the original equipment rims. Therefore, there is little likelihood of a tire and rim mismatch as a result of the missing rim markings. With regard to the omission of the DOT symbol, the agency regards the noncompliance with paragraph S5.2(c) as a failure to comply with the certification requirements of 49 U.S.C. 30115, and not a compliance failure requiring notification and remedy.
In consideration of the foregoing, NHTSA has decided that the petitioner has met its burden of persuasion that the noncompliance described is inconsequential to motor vehicle safety. Accordingly, Nissan's petition is granted and the petitioner is exempted from the obligation of providing notification of, and a remedy for, the noncompliance.
49 U.S.C. 30118, 30120; delegations of authority at 49 CFR 1.50 and 501.8.
U.S. Bus Corporation (U.S. Bus) has determined that certain school buses that it produced from 1998 through 2006 do not comply with paragraph S9.3(c) of 49 CFR 571.111, Federal Motor Vehicle Safety Standard (FMVSS) No. 111, Rearview Mirrors. As explained below, the noncompliance involves placement of a required label on school buses with cross view mirrors. U.S. Bus has filed an appropriate report pursuant to 49 CFR part 573, “Defect and Noncompliance Responsibility and Reports.” Pursuant to 49 U.S.C. 30118(d) and 30120(h), U.S. Bus also has petitioned for a determination that this noncompliance is inconsequential to motor vehicle safety. Notice of receipt of the petition was published, with a 30-day public comment period, on December 13, 2006 in the
Affected are a total of approximately 4,019 Universe and Sturdibus model school buses produced by U.S. Bus from 1998 through October 23, 2006 that do not meet the requirements of paragraph S9.3(c) of the standard. Specifically, paragraph S9.3(c) of FMVSS No. 111 requires that:
Each school bus which has a mirror installed in compliance with S9.3(a) that has an average radius of curvature of less than 889 mm, as determined under S12, shall have a label visible to the seated driver. . . . The label shall state the following: “USE CROSS VIEW MIRRORS TO VIEW PEDESTRIANS WHILE BUS IS STOPPED. DO NOT USE THESE MIRRORS TO VIEW TRAFFIC WHILE BUS IS MOVING. IMAGES IN SUCH MIRRORS DO NOT ACCURATELY SHOW ANOTHER VEHICLE'S LOCATION.”
On the noncompliant buses, the required label is affixed in a location behind the interior rearview mirror (used to observe vehicle occupants), thereby obscuring the label from view.
As discussed in its petition, U.S. Bus argued that the noncompliance is inconsequential to motor vehicle safety and that no corrective action is warranted. U.S. Bus based its conclusion on the following reasoning:
1. The decal in question is required only on school buses; 2. The crossview mirrors requiring the decal are only required on school buses; 3. School bus drivers are thoroughly trained in driving a school bus, including proper adjustment and viewing images through both the rearview and crossview mirrors; 4. The placement of the decal has no effect on the safety or reliability of the vehicle; 5. The placement of the decal may or may not be visible from the driver's seated position, and depends upon the adjustment of the rearview mirror as to whether the decal is visible by the driver.
In reaching our decision, NHTSA has carefully reviewed the subject petition, as well as a similar petition which was submitted to NHTSA in 2005 by another school bus manufacturer, Les Entreprises Corbeil, Inc. (Corbeil). To view the Corbeil petition and all supporting documents, go to: Docket No. NHTSA-2006-20923. The following explains our rationale.
As part of its reasoning, U.S. Bus asserted that because cross view mirrors and the associated warning label are only required on school buses, the noncompliance is inconsequential to motor vehicle safety and no corrective action is warranted. NHTSA does not understand or agree with this line of reasoning. School buses are regulated as a special vehicle type because they have a unique usage to transport large numbers of school-aged children to and from school and other activities. School buses are equipped with cross view mirrors primarily for the purpose of allowing the driver, prior to moving a bus, to observe pedestrians who have entered the zone in front of and on the sides of the bus where the driver has limited direct line-of-sight. Thus, cross view mirrors and the label describing their use are critical to the safety of these students who may not be visible to the driver.
U.S. Bus also stated that placement of the label has no effect on the safety of the vehicle and that school bus drivers are thoroughly trained in driving school buses, including the proper adjustment of and viewing images in both rearview and cross view mirror systems. NHTSA does not agree that driver training can replace the need for proper placement of the warning label. The label must be visible because it serves dual purposes, both of which are safety-related: (1) To inform the driver to use the cross view mirrors to view pedestrians while the bus is stopped, and (2) to remind the driver that the cross view mirrors are not to be used to view traffic while the bus is moving. Cross view convex mirrors affect distance perception because objects viewed in convex surface mirrors appear smaller (thereby giving the appearance of greater distance) than when viewed in flat surface mirrors. Furthermore, although NHTSA is aware that both the school bus industry and school systems place great importance on driver training, the thoroughness and consistency of driver training is not regulated and, consequently, may not be the same in all jurisdictions. In addition, school bus drivers tend to switch vehicles often, and their employment turnover rate is high. Therefore, the label, which is intended to be a constant reminder as to the use and limitations of cross view mirror systems, is a safety-critical feature, even for seasoned drivers.
U.S. Bus stated that the label in the subject noncompliant buses may or may not be visible from the driver's seated position, depending on the rear view mirror adjustment. Based on examination of the tested non-compliant bus, NHTSA has determined that when the inside mirror is properly adjusted to view the seated students the label is obscured for drivers of nearly any size.
In addition, we note the agency's June 2005 decision to grant the Corbeil petition, in which case the required cross view mirror warning labels for school buses were never installed (see 70 FR 33769 (June 9, 2005)). However, we would distinguish that case here. NHTSA based its Corbeil decision on the fact that the number of non-compliant vehicles was relatively small (245 buses), that corrections were made to rectify the situation in the future, and that driver training assured that the mirrors were used correctly. For U.S. Bus, however, the number of non-complaint buses is significantly higher at 4,019.
Lastly, since the Corbeil decision, NHTSA published in the fall of 2006 a Traffic Safety Facts report titled “School Transportation-Related Crashes,” DOT-HS-810626, which report states that since 1995, 170 school-age pedestrians (younger than 19) have died in school transportation-related crashes. The report also lists the numbers of pedestrian fatalities (school-age and other pedestrians) resulting from individuals being struck by school vehicles in 2003-2005, as 22, 27 and 27, respectively. The yearly pedestrian/school vehicle fatalities have risen from 16 in 2002 to 27 in 2005. We believe that strict compliance with applicable standards can help reverse this upward trend. According to an earlier Traffic Safety Facts report (DOT-HS-809770), there were 32 pedestrian/school vehicle fatalities in 1993. Based upon these findings, NHTSA believes that the decline in fatalities during the years
Since the cross view mirror labels remind school bus drivers of the appropriate use of these mirrors, NHTSA has reconsidered its view concerning the label and now believes that driver training is not an adequate substitute for missing labels or labels that are not visible to the seated driver.
In consideration of the foregoing, NHTSA has decided that U.S. Bus has not met its burden of persuasion that the noncompliance described is inconsequential to motor vehicle safety. Accordingly, U.S. Bus's petition is hereby denied, and the petitioner must notify according to 49 U.S.C. 30118 and remedy according to 49 U.S.C 30120.
49 U.S.C. 30118, 30120; delegations of authority at 49 CFR 1.50 and 501.8.
Financial Crimes Enforcement Network, Department of the Treasury.
Notice.
The Financial Crimes Enforcement Network (“FinCEN”) is issuing this notice to communicate a delay in the dates for using the revised Suspicious Activity Report (“SAR”) forms. The revised SAR forms that support joint filing were originally scheduled to become effective on June 30, 2007 and mandatory on December 31, 2007. FinCEN will establish new dates for using the revised SAR forms in a future notice.
Regulatory Policy and Programs Division, Financial Crimes Enforcement Network at (800) 949-2732.
It is FinCEN's intention to implement revised SAR forms that facilitate joint filing for depository institutions,
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 proposed regulation, REG-138176-02 (NPRM), Timely Mailing Treated As Timely Filing.
Written comments should be received on or before July 2, 2007 to be assured of consideration.
Direct all written comments to Glenn Kirkland, Internal Revenue Service, Room 6516, 1111 Constitution Avenue, NW., Washington, DC 20224.
Requests for additional information or copies of the regulation should be directed to Allan Hopkins, at (202) 622-6665, or at Internal Revenue Service, Room 6516, 1111 Constitution Avenue, NW., Washington, DC 20224, or through the Internet at
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 proposed regulation, REG-145987-03 (NPRM), Qualified Severance of a Trust for Generation-Skipping Transfer (GST) Tax Purposes.
Written comments should be received on or before July 2, 2007 to be assured of consideration.
Direct all written comments to Glenn Kirkland, Internal Revenue Service, Room 6516, 1111 Constitution Avenue, NW., Washington, DC 20224.
Requests for additional information or copies of the regulation should be directed to Allan Hopkins, at (202) 622-6665, or at Internal Revenue Service, Room 6516, 1111 Constitution Avenue, NW., Washington, DC 20224, or through the Internet at
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 Revenue Procedure 2001-37, Extraterritorial Income Exclusion Elections.
Written comments should be received on or before July 2, 2007 to be assured of consideration.
Direct all written comments to Glenn P. Kirkland, Internal Revenue Service, Room 6516, 1111 Constitution Avenue, NW., Washington, DC 20224.
Requests for additional information or copies of the revenue procedure should be directed to Allan Hopkins at Internal Revenue Service, Room 6516, 1111 Constitution Avenue, NW., Washington, DC 20224, or at (202) 622-6665, or through the Internet at
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 1116, Foreign Tax Credit.
Written comments should be received on or before July 2, 2007 to be assured of consideration.
Direct all written comments to Glenn P. Kirkland, Internal Revenue Service, Room 6516, 1111 Constitution Avenue, NW., Washington, DC 20224.
Requests for additional information or copies of the form and instructions should be directed to Allan Hopkins, at Internal Revenue Service, Room 6516, 1111 Constitution Avenue, NW., Washington, DC 20224, or at (202) 622-6665, or through the Internet at
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 8655, Reporting Agent Authorization for Magnetic Tape/Electronic Filers.
Written comments should be received on or before July 2, 2007 to be assured of consideration.
Direct all written comments to Glenn P. Kirkland, Internal Revenue Service, Room 6516, 1111 Constitution Avenue, NW., Washington, DC 20224.
Requests for additional information or copies of the form and instructions should be directed to Allan Hopkins at Internal Revenue Service, Room 6516, 1111 Constitution Avenue, NW., Washington, DC 20224, or at (202) 622-6665, or through the Internet at
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.
This document contains a Notice that the IRS has made available a supplemental period within which organizations in Colorado may apply for a Low Income Taxpayer Clinic (LITC) matching grant for the remainder of the 2007 grant cycle (the 2007 grant cycle runs January 1, 2007, through December 31, 2007). The supplemental application period shall run from April 27, 2007, to May 25, 2007.
The LITC grant program is now in its ninth year and continues to expand. To date in 2007, the LITC Program Office has awarded LITC grants to 154 organizations in 49 states, the District of Columbia, Puerto Rico, and Guam. Currently there are no LITCs in the state of Colorado. The IRS has approximately $55,000 available in matching grant funds to award to qualifying organizations in Colorado. In order to be considered for a supplemental 2007 Low Income Taxpayer Clinic grant, a qualifying organization must be in a position to provide qualified services to taxpayers in Colorado. Qualifying organizations that provide representation for free or for a nominal fee to low income taxpayers involved in tax controversies with the IRS or that provide education on taxpayer rights and responsibilities to taxpayers for whom English is a second language or who have limited English proficiency can apply for matching grants for the remainder of the 2007 grant cycle.
Examples of qualifying organizations include: (1) Clinical programs at accredited law, business or accounting schools, whose students may represent low income taxpayers in tax controversies with the IRS, and (2) organizations exempt from tax under I.R.C. § 501(a) which represent low income taxpayers in tax controversies with the IRS or refer those taxpayers to qualified representatives.
All grant applications for the remainder of the 2007 grant cycle must be postmarked by May 25, 2007, in order to be considered timely. If filing electronically, applications must be submitted on or before May 25, 2007.
Send completed grant applications to: Internal Revenue Service, Taxpayer Advocate Service, LITC Program Office, TA:LITC, Attention: LITC Supplemental Applications, 1111 Constitution Ave., NW., Room 1034, Washington, DC 20224. Copies of the 2007 Grant Application Package and Guidelines, IRS Publication 3319 (Rev. 5-2006), can be downloaded from the IRS Internet site at
The LITC Program Office at 202-622-4711 (not a toll-free number) or by e-mail at
Section 7526 of the Internal Revenue Code authorizes the IRS, subject to the availability of appropriated funds, to award organizations matching grants of up to $100,000 per year for the development, expansion, or continuation of qualified low income taxpayer clinics. Section 7526 authorizes the IRS to provide grants to qualified organizations that represent low income taxpayers in controversies with the IRS or inform individuals for whom English is a second language of their taxpayer rights and responsibilities. The IRS may award grants to qualifying organizations to fund one-year, two-year or three-year project periods. Grant funds may be awarded for start-up expenditures incurred by new clinics during the grant period.
The 2007 Grant Application Package and Guidelines, Publication 3319 (Rev. 5-2006), outlines requirements for the operation of a qualifying LITC program and provides instructions on how to apply for a grant. The costs of preparing and submitting an application are the responsibility of each applicant. Each application will be given due consideration and the LITC Program Office will mail notification letters to each applicant.
Applications that pass the eligibility screening process will be numerically ranked based on the information contained in their proposed program plan. Please note that the IRS Volunteer Income Tax Assistance (VITA) and Tax Counseling for the Elderly (TCE) Programs are independently funded and separate from the LITC Program.
Interested parties are encouraged to provide comments on the IRS's administration of the grant program on an ongoing basis. Comments may be sent to Sandra McQuin, P.O. Box 2305, Stop 1006MIL, Milwaukee, WI 53201-3205.
Internal Revenue Service (IRS), Treasury.
Notice.
An open meeting of the Area 6 Committee of the Taxpayer Advocacy Panel will be conducted (via teleconference). The Taxpayer Advocacy Panel (TAP) is soliciting public comments, ideas, and suggestions on improving customer service at the Internal Revenue Service. The TAP will use citizen input to make recommendations to the Internal Revenue Service.
The meeting will be held Thursday, May 24, 2007.
Dave Coffman at 1-888-912-1227, or (206) 220-6096.
Notice is hereby given pursuant to Section 10(a)(2) of the Federal Advisory Committee Act, 5 U.S.C. App. (1988) that an open meeting of the Area 6 Committee of the Taxpayer Advocacy Panel will be held Thursday, May 24, 2007 from 1 p.m. to 2:30 p.m. Pacific Time via a telephone conference call. The public is invited to make oral comments. Individual comments will be limited to 5 minutes. Due to limited conference lines, notification of intent to participate in the telephone conference call meeting must be made to Dave Coffman. Mr. Coffman can be reached at 1-888-912-1227 or (206) 220-6096. If you would like to have the TAP consider a written statement, please call or write to Dave Coffman, TAP Office, 915 2nd Avenue, MS W-406, Seattle, WA 98174, or you can contact us at
The agenda will include the following: Various IRS issues.
U.S. Customs and Border Protection, Department of Homeland Security.
Proposed collection; comments requested.
U.S. Customs and Border Protection (CBP) of the Department of Homeland Security has submitted the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995: Land Border Carrier Initiative. This is a proposed extension of an information collection that was previously approved. CBP is proposing that this information collection be extended with a change to the burden hours. This document is published to obtain comments from the public and affected agencies. This proposed information collection was previously published in the
Written comments should be received on or before May 31, 2007.
Interested persons are invited to submit written comments on the proposed information collection to the Office of Information and Regulatory Affairs, Office of Management and Budget. Comments should be addressed to Nathan Lesser, Desk Officer, Department of Homeland Security/Customs and Border Protection, and sent via electronic mail to
U.S. Customs and Border Protection (CBP) encourages the general public and affected Federal agencies to submit written comments and suggestions on proposed and/or continuing information collection requests pursuant to the Paperwork Reduction Act of 1995 (Pub. L. 104-13). Your comments should address one of the following four points:
(1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency/component, including whether the information will have practical utility;
(2) Evaluate the accuracy of the agencies/components estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
(3) Enhance the quality, utility, and clarity of the information to be collected; and
(4) Minimize the burden of the collections of information on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
U.S. Customs and Border Protection, Department of Homeland Security (DHS).
Notice of Federal Advisory Committee meeting.
The U.S. Customs and Border Protection (“CBP”) Airport and Seaport Inspections User Fee Advisory Committee (“Advisory Committee”) will meet in open session. The meeting will be open to the public.
Wednesday, June 6, 2007, 12:30 p.m. to 3 p.m.
The meeting will be held at Conference Room B 1.5-10, Ronald Reagan Building, 1300 Pennsylvania Avenue, NW., Washington, DC. If you desire to submit comments, requests for time to make oral presentations must be submitted by May 23, 2007. Comments must be identified by USCBP-2007-0044 and may be submitted by one of the following methods:
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Mr. Roberto Williams, Cost Management Division, 1300 Pennsylvania Avenue, NW., Suite 4.5A, U.S. Customs and Border Protection, Department of Homeland Security, Washington, DC 20229; telephone number 202-344-1101; facsimile: 202-344-1818; e-mail:
Pursuant to the Federal Advisory Committee Act (5 U.S.C., app. 1), DHS hereby announces the meeting of the U.S. Customs and Border Protection Airport and Seaport Inspections User Fee Advisory Committee (hereinafter, “Advisory Committee”). This Advisory Committee was established pursuant to section 286(k) of the Immigration and Nationality Act (INA), codified at title 8 U.S.C. 1356(k), which references the Federal Advisory Committee Act (5 U.S.C. App. 1
The fifth meeting of the CBP Advisory Committee will be held at the date, time and location specified above. A tentative agenda for the meeting is set forth below.
This meeting is open to the public. Public participation in the deliberations is welcome; however, please note that matters outside of the scope of this committee will not be discussed.
All visitors to the Ronald Reagan Building will have to show a picture ID in order to be admitted into the building. Since seating is limited, all persons attending this event must provide notice, preferably by close of business Wednesday, May 23, 2007, to Mr. Roberto Williams, Cost Management Division, 1300 Pennsylvania Avenue, NW., Suite 4.5A, U.S. Customs and Border Protection, Department of Homeland Security, Washington, DC 20229; telephone number 202-344-1101; e-mail address:
For information on facilities or services for individuals with disabilities or to request special assistance at the meeting, contact Mr. Roberto Williams as soon as possible.
1. Introduction of Committee members and CBP Personnel.
2. Report of activities since last meeting of August 22, 2006.
3. Operational initiatives and programs.
4. Workload issues and traffic trends.
5. Funding levels.
6. User fee initiatives.
7. Specific concerns and questions of Committee members addressed.
8. Discussion of relevant written statements submitted in advance by members of the public.
9. Committee's administrative housekeeping issues and scheduling of next meeting.
10. Adjourn.
U.S. Customs and Border Protection, Department of Homeland Security (DHS).
Notice of Federal Advisory Committee meeting.
The Departmental Advisory Committee on Commercial Operations of U.S. Customs and Border Protection and Related Homeland Security Functions (popularly known as “COAC”) will meet on May 15, 2007 in Washington, DC. The meeting will be open to the public.
COAC will meet Tuesday, May 15th from 9 a.m. to 1 p.m. Please note that the meeting may close early if the committee has completed its business.
The meeting will be held at the Ronald Reagan Building in the Rotunda Ballroom, 1300 Pennsylvania Avenue, NW., Washington, DC 20004. Written material and comments should reach the contact person listed below by May 4. Requests to have a copy of your material distributed to each member of the committee prior to the meeting should reach the contact person at the address below by May 8, 2007. Comments must be identified by USCBP-2007-0054 and may be submitted by
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Ms. Wanda Tate, Office of International Affairs and Trade Relations, U.S. Customs and Border Protection, Department of Homeland Security, 1300 Pennsylvania Ave., NW., Room 8.5C, Washington, DC 20229;
Pursuant to the Federal Advisory Committee Act (5 U.S.C., app.), DHS hereby announces the meeting of the Departmental Advisory Committee on Commercial Operations of U.S. Customs and Border Protection and Related Homeland Security Functions (COAC). COAC is tasked with providing advice to the Secretary of Homeland Security, the Secretary of the Treasury, and the Commissioner of U.S. Customs and Border Protection (CBP) on matters pertaining to the commercial operations of CBP and related functions within DHS or the Department of the Treasury.
The second meeting of the tenth term of COAC will be held at the date, time and location specified above. A tentative agenda for the meeting is set forth below.
1. Advance Trade Data.
2. Customs-Trade Partnership Against Terrorism (C-TPAT).
3. International Container Security.
4. Supply Chain Security Strategy.
5. National Response Plan.
6. Post Incident Trade Resumption.
7. Office of International Trade.
8. World Customs Organization—High Level Strategic Group.
This meeting is open to the public. Please note that the meeting may close early if all business is finished.
Participation in COAC deliberations is limited to committee members, Department of Homeland Security officials, and persons invited to attend the meeting for special presentations.
All visitors to the Ronald Reagan Building will have to go through a security checkpoint to be admitted to the building. Since seating is limited, all persons attending this meeting should provide notice, preferably by close of business Friday, May 11, 2007, to Ms. Wanda Tate, Office of Trade Relations, U.S. Customs and Border Protection, Department of Homeland Security, Washington, DC 20229, telephone 202-344-1440; facsimile 202-344-2064.
For information on facilities or services for individuals with disabilities or to request special assistance at the meeting, contact Ms. Wanda Tate as soon as possible.
The Department of Veterans Affairs (VA) gives notice under Public Law 92-463 (Federal Advisory Committee Act) that the Advisory Committee on OIF/OEF Veterans and Families will meet on May 14-16, 2007, at The Hilton Alexandria Old Town, 1767 King Street, Alexandria, Virginia. The meeting sessions will begin at 9 a.m. each day and will adjourn at 4;30 p.m. on May 14, 3:30 p.m. on May 15, and 1 p.m. on May 16. The meeting will be open to the public.
The purpose of the Committee is to advise the Secretary of Veterans Affairs on the full spectrum of health care, benefits delivery and related family support issues that confront servicemembers during their transition from active duty to veteran status and during their post-service years. The Committee will focus on the concerns of all men and women with active military service in Operation Iraqi Freedom and/or Operation Enduring Freedom, but will pay particular attention to severely disabled veterans and their families.
The agenda for the May 14-16 meeting will include briefings by senior officials of the Veterans Health Administration, Veterans Benefits Administration, and National Cemetery Administration on VA programs and policies that particularly affect OIF/OEF veterans. Other presentations will focus on the ongoing activities of VA's Office of Seamless Transition, and deliberations of the Joint (VA-DoD) Executive Council. The May 16 session will be devoted to Committee discussion of its general workplan, possible site visits to VA facilities, and future meeting dates.
The meeting will include time reserved for public comments.
Any member of the public seeking additional information should contact Ronald Thomas, Esq., Designated Federal Officer, at (202) 273-5182.
By direction of the Secretary.
The Department of Veterans Affairs (VA) gives notice under Public Law 92-463 (Federal Advisory Committee Act) that the Veterans' Disability Benefits Commission has scheduled a meeting for May 9-11, 2007, at the Doubletree Hotel Washington, 1515 Rhode Island Avenue, NW., Washington, DC. On May 9-10, the sessions will begin at 8:30 a.m. and end at 5 p.m. each day. On May 11, the session will begin at 8:30 a.m. and end at 3 p.m. The meeting is open to the public.
The purpose of the Commission is to carry out a study of the benefits under the laws of the United States that are provided to compensate and assist veterans and their survivors for disabilities and deaths attributable to military service.
The agenda for the meeting will feature updates on the progress of the studies being conducted by the Center for Naval Analyses (CNA) and the Institute of Medicine (IOM). There will be additional discussions with CNA on topics of ongoing research and analyses, and the IOM Post Traumatic Stress Disorder Compensation Committee will provide an overview of its final report. The Commission will receive presentations on several draft Issue Papers in various stages of development and discuss the composition of sections of the Commission's final report.
Interest persons may attend and present oral statements to the Commission on May 9. Oral presentations will be limited to five minutes or less, depending on the number of participants. Interested parties may also provide written comments for review by the Commission prior to the meeting or at any time, by e-mail to
By Direction of the Secretary:
Environmental Protection Agency (EPA).
Final rule.
Under the Clean Air Act, as amended by Section 1501 of the Energy Policy Act of 2005, the Environmental Protection Agency is required to promulgate regulations implementing a renewable fuel program. The statute specifies the total volume of renewable fuel that the regulations must ensure is used in gasoline sold in the U.S. each year, with the total volume increasing over time. In this context, this program is expected to reduce dependence on foreign sources of petroleum, increase domestic sources of energy, and help transition to alternatives to petroleum in the transportation sector. The increased use of renewable fuels such as ethanol and biodiesel is also expected to have the added effect of providing an expanded market for agricultural products such as corn and soybeans. Based on our analysis, we believe that the expanded use of renewable fuels will provide reductions in carbon dioxide emissions that have been implicated in climate change. Also, there will be some reductions in air toxics emissions such as benzene from the transportation sector, while some other emissions such as oxides of nitrogen are expected to increase.
This action finalizes regulations designed to ensure that refiners, blenders, and importers of gasoline will use enough renewable fuel each year so that the total volume requirements of the Energy Policy Act are met. Our rule describes the standard that will apply to these parties and the renewable fuels that qualify for compliance. The regulations also establish a trading program that will be an integral aspect of the overall program, allowing renewable fuels to be used where they are most economical while providing a flexible means for obligated parties to comply with the standard.
This final rule is effective on September 1, 2007. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of September 1, 2007.
EPA has established a docket for this action under Docket ID No. EPA-HQ-OAR-2005-0161. All documents in the docket are listed in the
Julia MacAllister, U.S. Environmental Protection Agency, National Vehicle and Fuel Emissions Laboratory, 2000 Traverwood, Ann Arbor MI, 48105; telephone number (734) 214-4131; fax number (734) 214-4816; e-mail address
Entities potentially affected by this action include those involved with the production, distribution and sale of gasoline motor fuel or renewable fuels such as ethanol and biodiesel. Regulated categories and entities could include:
This table is not intended to be exhaustive, but provides a guide for readers regarding entities likely to be regulated by this action. This table lists the types of entities that EPA is now aware could potentially be affected by this action. Other types of entities not listed in the table could also be affected. To decide whether your organization might be affected by this action, you should carefully examine today's notice and the existing regulations in 40 CFR part 80. If you have any questions regarding the applicability of this action to a particular entity, consult the persons listed in the preceding
Through today's final rule, we are putting in place a compliance and enforcement program that implements the renewable fuel program, also known as the Renewable Fuel Standard (RFS) program. This program accomplishes the statutory goal of increasing the volume of renewable fuels that are required to be used in vehicles in the U.S. as required in Section 211(o) of the Clean Air Act (CAA) enacted as part of the Energy Policy Act of 2005 (the Energy Act or the Act). This final rule resulted from a collaborative effort with stakeholders, including refiners, renewable fuel producers, and distributors, who together helped to design a program that is simple, flexible, and enforceable.
As a result of the favorable economics of renewable fuels in comparison to conventional gasoline and diesel, renewable fuel volumes are expected to exceed the requirements of the RFS program. We have evaluated the impacts of a range of renewable fuel volumes as high as 10 billion gallons in 2012. This represents a significant increase over the volume of renewable fuel used in 2004 which was approximately 3.5 billion gallons, and this increase is estimated to produce a number of significant effects. For instance, we estimate that the transition to renewable fuels will reduce petroleum consumption by 2.0 to 3.9 billion gallons or approximately 0.8 to 1.6 percent of the petroleum that would otherwise be used by the transportation sector.
The increased use of renewable fuels is also expected to produce reductions in some regulated pollutants. Carbon monoxide emissions from gasoline powered vehicles and equipment will be reduced by 0.9 to 2.5 percent and emissions of benzene (a mobile source air toxic) will be reduced by 1.8 to 4.0 percent.
The use of renewable fuel will likewise reduce greenhouse gas emissions such as carbon dioxide by 8.0 to 13.1 million metric tons, about 0.4 to 0.6 percent of the anticipated greenhouse gas emissions from the transportation sector in the United States in 2012. Greenhouse gas emissions contribute to climate change, and thus, increased renewable use is an important step in addressing this issue.
Finally, we estimate that increases in the use of renewable fuels will increase net farm income and the nation's energy security. Net U.S. farm income is estimated to increase by between $2.6 and $5.4 billion through transfers from users of gasoline and consumers of agricultural products used to produce ethanol. However, as feedstocks used in the production of renewable fuels expand beyond the corn and soybeans that are most common today, the renewable fuels industry is expected to continue to diversify and grow in its ability to benefit the nation's environment and economy.
Renewable fuels have been an important part of our nation's transportation fuel supply for many years. Following the CAA amendments of 1990, the use of renewable fuels, particularly ethanol, increased dramatically. Several key clean fuel programs required by the CAA established new market opportunities for ethanol. A very successful mobile source control strategy, the reformulated gasoline (RFG) program, was implemented in 1995. This program set stringent new controls on the emissions performance of gasoline, which were designed to significantly reduce summertime ozone precursors and year round air toxics emissions. The RFG program also required that RFG meet an oxygen content standard. Several areas of the country began blending ethanol into gasoline to help meet this new standard, such as Chicago and St. Louis. Another successful clean fuel strategy required certain areas exceeding the national ambient air quality standard for carbon monoxide to also meet an oxygen content standard during the winter time to reduce harmful carbon monoxide emissions. Many of these areas, such as Denver and Phoenix, also blended ethanol during the winter months to help meet this new standard.
Today, the role and importance of renewable fuels in the transportation sector continue to expand. In the past several years as crude oil prices have soared above the lower levels of the 1990's, the relative economics of renewable fuel use have improved dramatically. In addition, since the vast majority of crude oil produced in or imported into the U.S. is consumed as gasoline or diesel fuel in the U.S., concerns about our dependence on foreign sources of crude oil have renewed interest in renewable transportation fuels. The emergence of more in-depth understanding of the impacts of human activities on climate change has also focused attention on the various ways that renewable fuels can reduce the consumption of fossil fuels. The passage of the Energy Policy Act of 2005 demonstrated a strong commitment on the part of U.S. policymakers to consider additional means of supporting renewable fuels as a supplement to petroleum-based fuels in the transportation sector. The RFS program is one such means.
The RFS program was debated by the U.S. Congress over several years before finally being enacted through passage of the Energy Policy Act of 2005. The RFS program is first and foremost designed
The requirement for use of a specified volume of renewable fuels complements other provisions of the Energy Act. In particular, the required volume of renewable fuel use will offset any possible loss in demand for renewable fuels occasioned by the Act's repeal of the oxygen content mandate in the RFG program while allowing greater flexibility in how renewable fuels are blended into the nation's fuel supply. The RFS program also creates a specific annual level for minimum renewable fuel use which increases over time, ensuring overall growth in the demand and opportunity for renewable fuels.
Because renewable fuels such as ethanol and biodiesel are not new to the U.S. transportation sector, the expansion of their use is expected to follow distribution and blending practices already in place. For instance, the market already has the necessary production and distribution mechanisms in place in many areas and the ability to expand these mechanisms into new markets. Recent spikes in ethanol use resulting first from the state MTBE bans, and now the virtual elimination of MTBE from the marketplace, have tested the limits of the ethanol distribution system. However, future growth is expected to move in a more orderly fashion since the use of renewable fuels will not be geographically constrained and, given EIA volume projections, investment decisions can follow market forces rather than regulatory mandates. In addition, the increased production volumes of ethanol and the expanded penetration of ethanol in new markets may create new opportunities for blending of E85, a blend of 85 percent ethanol and 15 percent gasoline, in the long run. The increased availability of E85 will mean that more flexible fueled vehicles (FFV) can use this fuel. Of the approximately 5 million FFVs currently in use in the U.S, most are currently fueled with conventional gasoline rather than E85, in part due to the limited availability of E85.
Given the ever-increasing demand for petroleum-based products in the transportation sector, the RFS program also moves the nation in the direction of replacing part of this demand with renewable energy. The RFS program provides the certainty that at least a minimum amount of renewable fuel will be used in the U.S., which in turn provides some certainty for investment in production capacity of renewable fuels. However, it should be understood that the RFS program is not the only factor currently impacting demand for ethanol and other renewable fuels. As Congress was developing the RFS program in the Energy Act, several large states were adopting and implementing bans on the use of MTBE in gasoline. As a result, refiners supplying reformulated gasoline (RFG) in those states switched to ethanol to satisfy the oxygen content mandate for their RFG, causing a large, sudden increase in demand for ethanol. Even more importantly, with the removal of the oxygen content mandate for RFG, refiners elected to remove essentially all MTBE from the gasoline supply in the U.S. during the spring of 2006. In order to accomplish this transition quickly, while still maintaining gasoline volume, octane, and gasoline air toxics performance standards, refiners elected to blend ethanol into virtually all reformulated gasoline nationwide. This caused a second dramatic increase in demand for ethanol, which in the near term was met by temporarily shifting large volumes of ethanol out of conventional gasoline and into the RFG areas.
Perhaps the largest impact on renewable fuel demand, however, has been the increase in the cost of crude oil. In the last few years, both crude oil prices and crude oil price forecasts have increased dramatically. This has resulted in a large economic incentive for the use of ethanol and biodiesel. The Energy Information Administration (EIA) and others are currently projecting renewable fuel demand to exceed the minimum volumes required under the RFS program by a substantial margin. In this context, the effect of the RFS program is to provide a minimum level of demand to support ongoing investment in renewable fuel production. However, market demand for renewable fuels is expected to exceed the statutory minimums. We believe that the program we are finalizing today will operate effectively regardless of the level of renewable fuel use or market conditions in the energy sector.
Section 1501 of the Energy Policy Act amended the Clean Air Act and provides the statutory basis for the RFS program in Section 211(o). It requires EPA to establish a program to ensure that the pool of gasoline sold in the contiguous 48 states contains specific volumes of renewable fuel for each calendar year starting with 2006. The required overall volumes for 2006 through 2012 are shown in Table I.B-1 below.
In order to ensure the use of the total renewable fuel volume specified for each year, the Agency must set a standard for each year representing the amount of renewable fuel that each refiner, blender, or importer must use, expressed as a percentage of gasoline sold or introduced into commerce. This yearly percentage standard is to be set at a level that will ensure that the total renewable fuel volumes shown in Table I.B-1 will be used based on gasoline volume projections provided by the Energy Information Administration (EIA). The standard for each year must be published in the
The Act defines renewable fuels primarily on the basis of the feedstock. In general, renewable fuel must be a motor vehicle fuel that is produced from plant or animal products or wastes, as opposed to fossil fuel sources. The Act
The standard set annually by EPA is to be a single percentage applicable to refiners, blenders, and importers, as appropriate. The percentage standard is used by obligated parties to determine a volume of renewable fuel that they are responsible for introducing into the domestic gasoline pool for the given year. The percentage standard must be adjusted such that it does not apply to multiple parties for the same volume of gasoline. The standard must also take into account the use of renewable fuel by small refineries that are exempt from the program until 2011.
Under the Act, the required volumes in Table I.B-1 apply to the contiguous 48 states. However, Alaska and Hawaii can opt into the program, in which case the pool of gasoline used to calculate the standard, and the number of regulated parties, would change. In addition, other states can request a waiver of the RFS program under certain conditions, which would affect the national quantity of renewable fuel required under the program.
The Act requires the Agency to promulgate a credit trading program for the RFS program whereby an obligated party may generate credits for over-complying with their annual obligation. The obligated party can then use these credits to meet their requirements in the following year or trade them for use by another obligated party. Thus the credit trading program allows obligated parties to comply in the most cost-effective manner by permitting them to generate, transfer, and use credits. The trading program also permits renewable fuels that are not blended into gasoline, such as biodiesel, to participate in the RFS program.
The Agency must determine who can generate credits, under what conditions credits may be traded, how credits may be transferred from one party to another, and the appropriate value of credits for different types of renewable fuel. If a party is not able to generate or purchase sufficient credits to meet their annual obligation, they are allowed to carry over the deficit to the next annual compliance period, but must achieve full compliance in that following year.
Section 1501 of the Energy Act prescribed the RFS program, including the required total volumes, the timing of the obligation, the parties who are obligated to comply, the definition of renewable fuel, and the general framework for a credit trading program. Various aspects of the program require additional development by the Agency beyond the specifications in the Act. The Agency must develop regulations to ensure the successful implementation of the RFS program, based on the framework spelled out in the statute.
Under the RFS program the trading provisions comprise an integral element of compliance. Many obligated parties do not have access to renewable fuels or the ability to blend them, and so must use credits to comply. The RFS trading program is also unique in that the parties liable for meeting the standard (refiners, importers, and blenders of gasoline) are not generally the parties who make the renewable fuels or blend them into gasoline. This creates the need for trading mechanisms that ensure that the means to demonstrate compliance will be readily available for use by obligated parties.
The first step we took in developing the proposed program was to seek input and recommendations from the affected stakeholders. There were initially a wide range of thoughts and views on how to design the program. However, there was broad consensus that the program should satisfy a number of guiding principles, including, for example, that the compliance and trading program should provide certainty to the marketplace and minimize cost to the consumers; that the program should preserve existing business practices for the production, distribution, and use of both conventional and renewable fuels; that the program should be designed to accommodate all qualifying renewable fuels; that all renewable volumes produced are made available to obligated parties for compliance; and that the Agency should have the ability to easily verify compliance to ensure that the volume obligations are in fact met. These guiding principles and the comments we received on our Notice of Proposed Rulemaking (NPRM) helped to move us toward the program in today's final rule.
We published a Notice of Proposed Rulemaking on September 22, 2006 (71 FR 55552) which described our proposed approach to compliance and the trading program, as well as preliminary analyses of the environmental and economic impacts of increased use of renewable fuels. The program finalized today largely mirrors the proposed program, with some revisions reflecting continued input from stakeholders during the formal comment period.
Today's action establishes the final requirements for the RFS program, as well as our assessment of the environmental and economic impacts of the nation's transition to greater use of renewable fuels. This section provides an overview of our program and renewable fuel impacts assessment. Sections III through V provide the details of the structure of the program, while Sections VI through X describe our assessment of the impacts on emissions of regulated pollutants and greenhouse gases, air quality, fossil fuel use, energy security, economic impacts in the agricultural sector, and cost from the expanded use of renewable fuels.
In a typical major rulemaking, EPA would conduct a full assessment of the economic and environmental impacts of the specific rule that it is promulgating. However, as discussed in Section I.A., the replacement of MTBE with ethanol and the extremely favorable economics for renewable fuels brought on by the rise in crude oil prices are causing renewable fuel use to far exceed the RFS requirements. Given these circumstances, it is important to assess the impacts of this larger increase in renewable use and the related changes occurring to gasoline. For this reason we have carried out an assessment of the economic and environmental impacts of the broader changes in fuel quality resulting from our nation's transition to greater utilization of renewable fuels, as opposed to an assessment that is limited to the RFS program itself.
To carry out our analyses, we elected to use 2004 as the baseline from which to compare the impacts of expanded renewable use. We chose 2004 as a baseline primarily due to the fact that all the necessary refinery production data, renewable fuel production data, and fuel quality data were already in hand at the time we needed to begin the analysis. We did not use 2005 as a baseline year because 2005 may not be an appropriate year for comparison due to the extraordinary impacts of hurricanes Katrina and Rita on gasoline production and use. To assess the impacts of anticipated increases in renewable fuels, we elected to look at what they would be in 2012, the year the statutorily-mandated renewable fuel volumes will be fully phased in. By conducting the analysis in this manner, the impacts include not just the impact of expanded renewable fuel use by itself, but also the corresponding decrease in the use of MTBE, and the
We evaluated the impacts of expanded renewable fuel use and the corresponding changes to the fuel supply on fuel costs, consumption of fossil fuels, and some of the economic impacts on the agricultural sector and energy security. We also evaluated the impacts on emissions, including greenhouse gas emissions that contribute to climate change, and the corresponding impacts on nationwide and regional air quality. Our analyses are summarized in this section.
As shown in Table I.B-1, the Act stipulates that the nationwide volumes of renewable fuel required under the RFS program must be at least 4.0 billion gallons in 2006 and increase to 7.5 billion gallons in 2012. However, we expect that the volume of renewable fuel will actually exceed the required volumes by a significant margin. Based on economic modeling in 2006, EIA projected renewable fuel demand in 2012 of 9.6 billion gallons for ethanol, and approximately 300 million gallons for biodiesel using crude oil prices forecast at $48 per barrel.
The Act also stipulates that at least 250 million gallons out of the total volume required in 2013 and beyond must meet the definition specified for cellulosic biomass ethanol. As described in Section VI, there are a number of companies already making plans to produce ethanol from cellulosic feedstocks and/or waste-derived energy sources that could potentially meet the definition of cellulosic biomass ethanol. Accordingly, we anticipate a ramp-up in production of cellulosic biomass ethanol production in the coming years, and for analysis purposes we have assumed that 250 million gallons of cellulosic biomass ethanol will be used in 2012.
As discussed in Section VI, we chose 2004 to represent current baseline conditions. However, a direct comparison of the fuel quality impacts on emissions and air quality that are expected to occur once the RFS program is fully phased in required that changes in overall fuel volume, fleet characterization, and other factors be constant. Therefore, we created a 2012 reference case from the 2004 base case for use in the emissions and air quality analysis that maintained current fuel quality parameters while incorporating forecasted increases in vehicle miles traveled and changes in fleet demographics. The 2012 fuel reference case was developed by growing out the 2004 renewable fuel baseline according to EIA's forecasted energy growth rates between 2004 and 2012.
For the analyses, we created two 2012 scenarios representing expanded renewable fuel production. The “RFS Case” represents volume levels designed to exactly meet the requirements of the RFS program, and includes the effects of higher credit values for cellulosic ethanol and biodiesel. Since higher credit values mean that one gallon of renewable fuel counts as more than one gallon for compliance purposes, less than 7.5 billion gallons of renewable fuel is needed to meet the 7.5 billion gallon statutory requirement, but credits equivalent to 7.5 billion gallons of renewable fuel would still be available for compliance purposes. The “EIA Case” represents volume levels based on EIA projections. A summary of the assumed renewable fuel volumes for the scenarios we evaluated is shown in Table II.A.1-1. Details of the calculations used to determine these volumes are given in Chapter 2 of the Regulatory Impact Analysis (RIA) in the docket for this rulemaking.
We evaluated the impacts of increased use of ethanol and biodiesel on emissions and air quality in the U.S. relative to the reference case. We estimated that nationwide VOC emissions in 2012 from gasoline vehicles and equipment will increase by about 0.3% in the RFS Case and about 0.7% in the EIA Case. For NO
We also estimated the change in emissions in those areas which are projected to experience a significant change in ethanol use; i.e., where the market share of ethanol blends was projected to change by 50 percent or more. We focused on July emissions since these are most relevant to ozone formation and modeled 2015 because our ozone model is based upon a 2015 emissions inventory (though we would expect similar results in 2012). Finally, we developed separate estimates for RFG areas, low RVP areas (i.e., RVP standards less than 9.0 RVP), and conventional gasoline areas with a summer 9.0 RVP standard. For areas with a significant change in ethanol use,
Unlike VOC and NO
We do not have sufficient data to predict the effect of ethanol use on levels of either directly emitted particulate matter (PM) or secondarily formed PM. The increased NO
The emission impact estimates described above are based on the best available data and models. However, it must be highlighted that most of the fuel effect estimates are based on very limited or old data which may no longer be reliable in estimating the emission impacts on vehicles in the 2012 fleet with advanced emission controls.
We used the Ozone Response Surface Model (RSM) to estimate the impacts of the increased use of ethanol on ozone levels for both the RFS Case and the EIA Case. The ozone RSM approximates the effect of VOC and NO
We investigated several other issues related to emissions and air quality that could affect our estimates of the impacts of increased use of renewable fuels. These are discussed in Section VIII and in greater detail in the RIA. For instance, our current models assume that recent model year vehicles are insensitive to many fuel changes. However, a limited amount of new test data suggest that newer vehicles may be just as sensitive as older model year vehicles. Our sensitivity analysis suggests that if this is the case, VOC emissions could decrease by as much as 0.3%, instead of increasing by up to 0.7%. NO
Finally, a lack of emission data and atmospheric modeling tools prevented us from making specific projections of the impact of renewable fuels on ambient PM levels. As mentioned, however, ethanol use may affect ambient PM levels due to the increase in NO
In Section VII of this preamble, we estimate the cost of producing the extra volumes of renewable fuel anticipated through 2012. For corn ethanol, we estimate the per gallon cost of ethanol to range from $1.26 per gallon in 2012 (2004 dollars) in the RFS Case to $1.32 per gallon in the EIA Case. These costs take into account the cost of the feedstock (corn), plant equipment and operation and the value of any co-products (distiller's dried grain and solubles, for example). For biodiesel, we estimate the per gallon cost to be between $1.89 and $2.06 per gallon if produced using soy bean oil, and less if using yellow grease ($1.11 to $1.56 per gallon) or other relatively low cost or no-cost feedstocks. The price paid for ethanol, however, is reduced by the $0.51 per gallon federal tax subsidy as well as any state subsidies that might apply. Similarly the price paid for biodiesel is reduced due to the $1.00 per gallon federal tax subsidy biodiesel produced from soy bean oil and $0.50 per gallon tax subsidy for biodiesel produced from yellow grease. We also note that these costs represent the production cost of the fuel and not the market price. In recent years, the prices of ethanol and biodiesel have tended to track the prices of gasoline and diesel fuel, in some cases even exceeding those prices.
These renewable fuels are then blended in gasoline and diesel fuel. While biodiesel is typically just blended with typical petroleum diesel, additional efforts are sometimes necessary and/or economically advantageous at the refiner level when adding ethanol to gasoline. For example, ethanol's high octane reduces the need for other octane enhancements by the refiner, whereas offsetting the volatility increase caused by ethanol may require removal of other highly volatile components. Section VII examines these fuel cost impacts and concludes that the net cost to society in 2012 in comparison to the reference case will range from an estimate of 0.5 cent to 1.0 cent per gallon of gasoline due to the increased use of renewable fuels and their displacement of MTBE. The resulting total nationwide costs in 2012 are $823 million per year for the RFS case and $1,739 million per year for the EIA case. This total excludes the effects of the 51 cent/gal federal excise tax credit as well as state tax subsidies.
Our estimates of fuel impacts do not consider other societal benefits. For example, the displacement of petroleum-based fuel (largely imported) by renewable fuel (largely produced in the United States), should reduce our use of imported oil and fuel. We estimate that 95 percent of the lifecycle petroleum reductions resulting from the use of renewable fuel will be met
Furthermore, the above estimate on reduced petroleum import expenditures only partly assess the economic impacts. One of the effects of increased use of renewable fuel is that it diversifies the energy sources used in making transportation fuel. To the extent that diverse sources of fuel energy reduce the dependence on any one source, the risks, both financial as well as strategic, of a potential disruption in supply reflected in the price volatility of a particular energy source are reduced. As indicated in the proposal, EPA has worked with researchers at Oakridge National Laboratory to update a study they previously published and which has been used or cited in several government actions impacting oil consumption. A draft report is being made available in the docket at this time for further consideration. This analysis only looks at the impact of reduced petroleum imports on energy security. Other energy security issues could arise with the wider use of biofuels. For example, ethanol's production and costs are determined by the availability of corn as a feedstock. Corn production, in turn, is weather-dependent. Also, the use of biofuels may increase the use of natural gas. A full integrated analysis of the energy security implications of the wider use of biofuels has yet to be undertaken.
While increased use of renewable fuel will reduce expenditures on imported oil, it will also increase expenditures on renewable fuels and in-turn, on the sources of those renewable fuels. The RFS program attempts to spur the increased use of renewable transportation fuels made principally from agricultural crops produced in the U.S. As a result, it is important to analyze the consequences of the transition to greater renewable fuel use in the U.S. agricultural sector. To perform this analysis, EPA selected the Forest and Agricultural Sector Optimization Model (FASOM) developed by Professor Bruce McCarl of Texas A&M University and others over the past thirty years. FASOM is a dynamic, nonlinear programming model of the agriculture and forestry sectors of the U.S. (For this analysis, we focused on the agriculture portion of the model.)
Due to the greater demand for corn as a feedstock for ethanol production, corn prices are estimated to increase in 2012 by 18 cents per bushel for the RFS Case and 39 cents per bushel of corn for the EIA Case from $2.32 (in 2004 dollars) in the Reference Case. Although soybean prices are expected to rise slightly, the increased cost is likely due to higher input costs, such as land prices. We estimate a price increase of 18 cents (RFS Case) to 21 cents (EIA Case) per bushel of soybeans from a Reference Case price of $5.26 per bushel. These higher commodity prices are predicted to also result in higher U.S. farm income. Our analysis predicts that farm income will increase by $2.6 billion annually by 2012 for the RFS Case and $5.4 billion for the EIA Case, roughly a 5 to 10 percent increase.
Due to higher corn prices, U.S. exports of corn are estimated to decrease by $573 million in the RFS Case and by $1.29 billion in the EIA Case in 2012. With higher commodity prices, we would expect some upward pressure on food costs as the higher cost of corn and soybeans is passed along to consumers. We estimate a relatively modest increase in annual household food costs associated with the higher price commanded by corn and soybeans. For the RFS Case, annual per capita wholesale food cost are estimated to increase by approximately $7, while the higher renewable fuel volumes anticipated by the EIA Case will result in a $12 annual increase in the per capita wholesale food cost. This equates to roughly a $2.1 to $3.6 billion increase in nationwide food costs in 2012.
There has been considerable interest in the impacts of fuel programs on greenhouse gases implicated in climate change and on fossil fuel consumption due largely to concerns about dependence on foreign sources of petroleum. Therefore, in this rulemaking we have undertaken an analysis of the greenhouse gas and fossil fuel consumption impacts of a transition to greater renewable fuel use. This is the first analysis of its kind in a high profile rule, and as such it may guide future work in this area.
As a result of the transition to greater renewable fuel use, some petroleum-based gasoline and diesel will be directly replaced by renewable fuels. Therefore, consumption of petroleum-based fuels will be lower than it would be if no renewable fuels were used in transportation vehicles. However, a true measure of the impact of greater use of renewable fuels on petroleum use, and indeed on the use of all fossil fuels, accounts not only for the direct use and combustion of the finished fuel in a vehicle or engine, but also includes the petroleum use associated with production and transportation of that fuel. For instance, fossil fuels are used in producing and transporting renewable feedstocks such as plants or animal byproducts, in converting the renewable feedstocks into renewable fuel, and in transporting and blending the renewable fuels for consumption as motor vehicle fuel. Likewise, fossil fuels are used in the production and transportation of petroleum and its finished products. In order to estimate the true impacts of increases in renewable fuel use on fossil fuel use, we must take these steps into account. Such analyses are termed lifecycle analyses.
There is also no consensus on the most appropriate approach for conducting such lifecycle analyses. We have chosen to base our lifecycle analysis on Argonne National Laboratory's GREET model for the reasons described in Section IX. However, there are other lifecycle models in use. The choice of model inputs and assumptions all have a bearing on the results of lifecycle analyses, and many of these assumptions remain the subject of debate among researchers.
With these caveats, we compared the lifecycle impacts of renewable fuels to the petroleum-based gasoline and diesel fuels that they replace. This analysis allowed us to estimate not only the overall impacts of renewable fuel use on petroleum use, but also on emissions of greenhouse gases such as carbon dioxide from all fossil fuels. In comparison to the reference case, we estimate that the increased use of renewable fuels in the RFS and EIA cases will reduce transportation sector petroleum consumption by about 0.8 and 1.6 percent, respectively, in the transportation sector in 2012. This is equivalent to 2.0-3.9 billion gallons of petroleum in 2012. We also estimated that greenhouse gases from the transportation sector will be reduced by about 0.4 and 0.6 percent for the RFS and EIA cases, respectively, equivalent to about 8-13 million metric tons. These reductions are projected to continue to increase beyond 2012 since crude oil prices have been projected by EIA to continue to be high relative to the prices of the 1990's, and as a result there is expected to be an economic advantage to using renewable fuels beyond 2012. These greenhouse gas emission reductions are also highly dependent on the expectation that the majority of the future ethanol use will be produced
The Energy Policy Act of 2005, in addition to setting the standards to be adopted through 2012, requires EPA, in coordination with the Departments of Agriculture and Energy, to determine the applicable volume for the renewable fuel standard for the year 2013 and subsequent calendar years. This determination is to be based on a review of the program's implementation in 2006 through 2012 as well as review of the impact of renewable fuels on the environment, air quality, energy security, job creation, rural economic development and the expected annual rate of renewable fuel production, including production of cellulosic ethanol.
In today's final rulemaking, we do not suggest any specific renewable fuel volumes for 2013 and beyond that may be appropriate under the statutory criteria. However, we would note that the President, in his State of the Union address this January, set specific goals reducing the amount of gasoline usage in the United States by 20 percent in the next 10 years. This would be accomplished by reforming and modernizing fuel economy standards for cars and setting mandatory fuels standard equivalent to requiring use of 35 billion gallons of renewable and alternative
From a program structure perspective, we believe that what we are putting in place today will remain useful as part of a 2013 and later program. For example, EPA considers that the identification of renewable fuel via a Renewable Identification Number (RIN), the determination of liable parties, the averaging, banking and trading system and the recordkeeping and reporting system would all be elements of a post-2013 program. Depending on the structure of any final legislation approved by Congress and signed into law, such elements could also be incorporated into an expanded renewable and alternative fuels program.
The RFS program being finalized today requires refiners, importers, and blenders (other than oxygenate blenders) to show that a required volume of renewable fuel is used in gasoline. The required volume is determined by multiplying their annual gasoline production by a percentage standard specified by EPA. Compliance is demonstrated through the acquisition of unique Renewable Identification Numbers (RINs) assigned by the producer or importer to every batch of renewable fuel produced or imported. The RIN shows that a certain volume of renewable fuel was produced or imported. Each year, the refiners, blenders and importers obligated to meet the renewable volume requirement (referred to as “obligated parties”) must acquire sufficient RINs to demonstrate compliance with their volume obligation. RINs can be traded, thereby functioning as the credits envisioned in the Act. A system of recordkeeping and electronic reporting for all parties that have RINs ensures the integrity of the RIN pool. This RIN-based system will both meet the requirements of the Act and provide several other important advantages:
• Renewable fuel production volumes can be easily verified.
• RIN trading can occur in real time as soon as the renewable fuel is produced rather than waiting to the end of the year when an obligated party would determine if it had exceeded the standard.
• Renewable fuel can continue to be produced, distributed, and blended in those markets where it is most economical to do so.
• Instances of double-counting of renewable fuel claimed for compliance purposes can be identified based on electronically reported data.
Our RIN-based trading program is an essential component of the RFS program, ensuring that every obligated party can comply with the standard while providing the flexibility for each obligated party to use renewable fuel in the most economical ways possible.
EPA is required to convert the aggregate national volumes of renewable fuel specified in the Act into corresponding renewable fuel standards expressed as a percent of gasoline production or importation. The renewable volume obligation that will apply to an individual obligated party will then be determined based on this percentage and the total gasoline production or import volume in a calendar year, January 1 through December 31. EPA will publish the percentage standard in the
Under our program, any party that produces or imports gasoline for consumption in the U.S., including refiners, importers, and blenders (other than oxygenate blenders), will be subject to a renewable volume obligation that is based on the renewable fuel standard. These obligated parties will determine the level of their obligation by multiplying the percentage standard by their annual volume of gasoline production or importation. The result will be the renewable fuel volume which each party must ensure is blended into gasoline consumed in the U.S., with credit for certain other renewable fuels that are not blended into gasoline.
For 2007, we are requiring that the renewable fuel volume obligation be determined by multiplying the percentage standard by the volume of gasoline produced or imported prospectively from September 1, 2007 until December 31, 2007. While the standard will not apply to all of 2007 gasoline production, we are nevertheless confident that the total volume of renewable fuel used in all of 2007 will still exceed the volume specified in the Act due to expectations that the demand for renewable fuel will exceed the RFS requirements.
In determining their annual gasoline production volume, obligated parties must include all of the finished gasoline which they produced or imported for use in the contiguous 48 states, and must also include reformulated blendstock for oxygenate blending (RBOB), and conventional blendstock for oxygenate blending (CBOB). For refiners and importers this includes unfinished gasoline produced or imported that will become gasoline upon addition of an oxygenate downstream of the refiner. Other producers of gasoline, such as blenders,
Small refiners and small refineries are exempt from meeting the renewable fuel requirements through 2010. All gasoline producers located in Alaska, Hawaii, and noncontiguous U.S. territories and parties who import gasoline into these areas will be exempt indefinitely. However, if Alaska, Hawaii or a noncontiguous territory opts into the RFS program, all of the refiners (except for exempt small refiners and refineries), importers, and blenders located in the state or territory will be subject to the renewable fuel standard.
Section III.A provides more details on the standard that must be met, while Section III.C describes the parties that are obligated to meet the standard.
We have designed the program to cover the range of renewable fuels produced today as well as any that might be produced in the future, so long as they meet the Act's definition of renewable fuel and have been registered and approved for use in motor vehicles. In this manner, we believe that the program provides the greatest possible encouragement for the development, production, and use of renewable fuels to reduce our dependence on petroleum as well as to reduce the carbon dioxide emissions that contribute to climate change. In general, renewable fuels must be produced from plant or animal products or wastes, as opposed to fossil fuel sources. Valid renewable fuels include ethanol made from starch seeds, sugar, or cellulosic materials, biodiesel (mono-alkyl esters), non-ester renewable diesel, and a variety of other products. Both renewable fuels blended into conventional gasoline or diesel and those used in their neat (unblended) form as motor vehicle fuel will qualify. Section III.B provides more details on the renewable fuels that will be allowed to be used for compliance with the standard under our program.
One question that we faced in developing the program was what value to place on different renewable fuels and on what basis should that value be determined. The Act specifies that each gallon of cellulosic biomass ethanol and waste-derived ethanol be treated as if it were 2.5 gallons of renewable fuel for compliance purposes, but does not specify the values for other renewable fuels. Although in the NPRM we considered a range of options including straight volume, energy content, and requested comment on the merit and basis for setting “Equivalence Values” on several metrics including lifecycle energy or greenhouse gas emissions, for this final rule we are requiring that the “Equivalence Values” for the different renewable fuels be based on their energy content in comparison to the energy content of ethanol, and adjusted as necessary for their renewable content. The result is an Equivalence Value for corn ethanol of 1.0, for biobutanol of 1.3, for biodiesel (mono alkyl ester) of 1.5, for non-ester renewable diesel of 1.7, and for cellulosic ethanol and waste-derived ethanol of 2.5. The proposed methodology can be used to determine the appropriate Equivalence Value for any other potential renewable fuel as well. Section III.B.4 provides details of the determination of Equivalence Values.
Under our program, every gallon of renewable fuel produced or imported into the U.S. must be assigned a unique RIN. A block of RINs would be assigned to any batch of renewable fuel that is valid for compliance purposes under the RFS program. These RINs must be transferred with renewable fuel as ownership of a volume of renewable fuel is initially transferred through the distribution system. Once the renewable fuel is obtained by an obligated party or actually blended into a motor vehicle fuel, the RIN can be separated from the batch of renewable fuel and then either used for compliance purposes, held, or traded.
RINs represent proof of production which is then taken as proof of consumption as well, since all but a trivial quantity of renewable fuel produced or imported will be either consumed as fuel or exported. For instance, ethanol produced for use as motor vehicle fuel is denatured specifically so that it can only be used as fuel. Similarly, biodiesel is produced only for use as fuel and has no other significant uses. An obligated party demonstrates compliance with the renewable fuel standard by accumulating sufficient RINs to cover their individual renewable volume obligation. It will not matter whether the obligated party used the renewable fuel themselves. An obligated party's obligation will be to ensure that a certain amount of renewable fuel was used, either by themselves or by someone else, and the RIN is evidence that this occurred for a certain volume of renewable fuel. Exporters of renewable fuel will also be required to acquire RINs in sufficient quantities to cover the volume of renewable fuel exported. RINs claimed for compliance purposes by obligated parties will thus represent renewable fuel actually consumed as motor vehicle fuel in the U.S.
RINs are valid for compliance purposes for the calendar year in which they are generated, or the following calendar year. This approach to RIN life is consistent with the Act's prescription that credits be valid for compliance purposes for 12 months as of the date of generation, where credits are generated at the end of a year when compliance is determined. An obligated party can either use RINs to demonstrate compliance, or can transfer RINs to any other party. If an obligated party is not able to accumulate sufficient RINs for compliance in a given year, it can carry a deficit over to the next year so long as the full deficit and obligation is covered in the next year.
In order to ensure that previous year RINs are not used preferentially for compliance purposes in a manner that would effectively circumvent the limitation that RINs be valid for only 12 months after the year generated, we are setting a cap on the use of RINs generated the previous year when demonstrating compliance with the renewable volume obligation for the current year. The cap will mean that no more than 20 percent of a current year obligation can be satisfied using RINs from the previous year. In this manner there is no ability for excess renewable fuel use in successive years to cause an accumulation of RINs to significantly depress renewable fuel demand in any future year. In keeping with the Act, excess RINs not used in the year they are generated or in the subsequent year will expire.
Section III.D provides more details on how obligated parties must use RINs for compliance purposes.
Renewable fuel producers and importers will be required to generate RINs when they produce or import a batch of renewable fuel (unless, for importers, the RINs have been assigned by a foreign producer registered with EPA). They will then be required to transfer those RINs along with the renewable fuel batches that they represent whenever they transfer ownership of the batch to another party. Likewise any other non-obligated party
Once a RIN is separated from a volume of renewable fuel, it can be used for compliance purposes, banked, or traded to another party. Separated RINs can be transferred to any party any number of times. Recordkeeping and reporting requirements will apply to any party that takes ownership of RINs, whether through the ownership of a batch of renewable fuel or through the transfer of separated RINs.
Thus obligated parties can acquire RINs directly through the purchase of renewable fuel with assigned RINs or through the open market for RINs that is allowed under this proposal. Section III.E provides more details on how our RIN trading program will work.
As in all EPA fuel regulations, there is a system of registration, recordkeeping, and reporting requirements for obligated parties, renewable producers and importers (RIN generators), and any parties that procure or trade RINs either as part of their renewable purchases or separately. In most cases, the recordkeeping requirements are not significantly different from what these parties might be doing already as a part of normal business practices. The lynch pin to the compliance program, however, is the unique RIN number itself coupled with an electronic reporting system where RIN generation, RIN use, and RIN transactions will be reported and verified. Thus, EPA, as well as industry can have confidence that invalid RINs are not generated and that there is no double counting.
In the proposal EPA asked for comments on the idea of creating a voluntary labeling program to encourage the adoption and use of practices that minimize the environmental concerns associated with renewable fuel production. The proposal suggested adding a “G” (for green) to the end of the RIN of a fuel to indicate that a gallon of renewable fuel was produced with the combination of best farming practices and environmentally friendly production methods and facilities. EPA received a number of comments on this idea.
The majority of respondents were very supportive of voluntary labeling and encouraged EPA to establish this program through this final rulemaking. Two commenters opposed the labeling concept, telling EPA that the number and complexity of issues associated with fuel production, and particularly with farming practices, would make such a program impractical and difficult to implement. EPA also was told that it would be hard to audit such a program. Most commenters agreed that using the RIN to host the label makes sense, however the use of “G” for green fuel is insufficient to capture the full range of environmental impacts of renewable fuel production and that it would be difficult for EPA to establish an appropriate cut-off point for determining which fuel qualified for a “G” designation. Several respondents suggested that EPA instead use a more continuous scale based on energy or lifecycle greenhouse gas emissions.
A well designed voluntary labeling program could permit producers and blenders to distinguish their fuels in the marketplace and allow consumers to express preferences for “green” products through their fuel purchases. While such a program could be valuable to producers, blenders, and consumers, given the range of comments received on the topic, we believe it is important first to continue the dialogue with the various stakeholders to ensure that the program adequately addresses the issues raised prior to putting any such program in place. Thus we are not finalizing a voluntary labeling program. We will continue to investigate the issues surrounding a voluntary labeling program and the various ways in which it could be designed. In particular we are interested in further exploring methods to incorporate lifecycle impacts into a voluntary labeling program and consumer expectations for such “green” labeling.
According to the Energy Act, the RFS program places obligations on individual parties such that the renewable fuel volumes shown in Table I.B-1 are used as motor vehicle fuel in the U.S. each year. To accomplish this, the Agency must calculate and publish a standard by November 30 of each year which is applicable to every obligated party. On the basis of this standard each obligated party determines the volume of renewable fuel that it must ensure is consumed as motor vehicle fuel. In addition to setting the standard, we must clarify who the obligated parties are and what volumes of gasoline are subject to the standard. Obligated parties must also know which renewable fuels are valid for RFS compliance purposes, and the relative values of each type of renewable fuel in terms of compliance. This section discusses how the annual standard is determined and which parties and volumes of gasoline will be subject to the requirements.
Because renewable fuels are not produced or distributed evenly around the country, some obligated parties will have easier access to renewable fuels than others. As a result, the RFS program depends on a robust trading program. This section also describes all the elements of our trading program.
Table I.B-1 shows the required total volume of renewable fuel specified in the Act for 2007 through 2012. The renewable fuel standard is based primarily on (1) the 48-state gasoline consumption volumes projected by EIA (as the Act exempts Hawaii and Alaska, subject to their right to opt-in, as discussed in Section III.C.4), and (2) the volume of renewable fuels required by the Act for the coming year. The renewable fuel standard will be expressed as a volume percentage of gasoline sold or introduced into commerce in the U.S., and will be used by each refiner, blender or importer to determine their renewable volume obligation. The applicable percentage is set so that if each regulated party meets the percentage and total gasoline consumption does not fall short of EIA projections then the total amount of renewable fuel used will meet the total renewable fuel volume specified in Table I.B-1.
In determining the applicable percentage for a calendar year, the Act requires EPA to adjust the standard to prevent the imposition of redundant obligations on any person and to account for the use of renewable fuel during the previous calendar year by exempt small refineries, defined as refineries that process less than 75,000 bpd of crude oil. As a result, in order to be assured that the percentage standard will in fact result in the volumes shown in Table I.B-1, we must make several adjustments to what is otherwise a simple calculation.
As stated, the renewable fuel standard for a given year is basically the ratio of the amount of renewable fuel specified in the Act for that year to the projected 48-state non-renewable gasoline volume
In the proposal, we stated that EIA had indicated that the best estimation of the coming year's gasoline consumption is found in Table 5a (U.S. Petroleum Supply and Demand: Base Case) of the October issue of the monthly EIA publication Short-Term Energy Outlook which publishes quarterly energy projections. Commenters on this issue supported the use of the October issue of EIA's Short-Term Energy Outlook (STEO), Table 5a, for the purpose of estimating the next year's gasoline consumption, and we have used the October 2006 STEO values for estimating 2007 gasoline consumption for this final rule.
The gasoline volumes in the STEO include renewable fuel use. As discussed below in Section III.C.1, the renewable fuel obligation does not apply to renewable blenders. Thus, the gasoline volume used to determine the standard must be the non-renewable portion of the gasoline pool, in order to achieve the volumes of renewables specified in the Act. In order to get a total non-renewable gasoline volume, we must subtract the renewable fuel volume from the total gasoline volume. EIA has indicated that the best estimation of the coming year's renewable fuel consumption is found in Table 11 (U.S. Renewable Energy Use by Sector: Base Case) of the October issue of the STEO. As with the gasoline projections discussed above, we have used the October 2006 STEO values for estimating 2007 renewable fuel values for this final rule.
The Act exempts small refineries
The Act requires that the small refinery adjustment also account for renewable fuels used during the prior year by small refineries that are exempt and do not participate in the RFS program. Accounting for this volume of renewable fuel would reduce the total volume of renewable fuel use required of others, and thus directionally would reduce the percentage standard. However, as discussed in the proposal, there are no such data available, the amount of renewable fuel that would qualify (i.e., that was used by exempt small refineries and small refiners but not used as part of the RFS program) is expected to be very small and would not significantly change the resulting percentage standard. Because whatever renewables small refiners and small refineries blend will be reflected as RINs available in the market, there is no need for a separate accounting of their renewable fuel use in the equation used to determine the standard. We thus proposed that this value be zero, and we are finalizing the equation as such.
We also proposed not to include renewable fuel used in Alaska, Hawaii, or U.S. territories when subtracting renewable fuel volumes from the anticipated total gasoline volumes in EIA projections. The Act requires that the renewable fuel be consumed in the contiguous 48 states unless Alaska, Hawaii, or a U.S. territory opt-in. However, because renewable fuel produced in Alaska, Hawaii, and U.S. territories is unlikely to be transported to the contiguous 48 states, including their renewable fuel volumes in the calculation of the standard would not serve the purpose intended by the Act of ensuring that the statutorily required renewable fuel volumes are consumed in the 48 contiguous States. We are finalizing the exclusion of these areas' renewable fuel use as proposed.
We stated that any deficit carryover from 2006 would increase the 2007 standard. Since renewable fuel use in 2006 exceeded the 2.78 percent default standard, there is no deficit to carry over to 2007. Beginning with the 2007 compliance period, when annual individual party compliance replaces collective compliance, any deficit is calculated for an individual party and is included in the party's Renewable Volume Obligation (RVO) determination, as discussed in Section III.A.4.
In summary, the total projected non-renewable gasoline volumes from which the annual standard is calculated is based on EIA projections of gasoline consumption in the contiguous 48 states, adjusted by a constant percentage of 13.5% to account for small refinery/refiner volume, with built-in correction factors to be used when and if non-contiguous states and territories opt-in to the program. If actual gasoline consumption were to exceed the EIA projection, the result would be that renewable fuel volumes will exceed the statutory requirements. Conversely, if actual gasoline consumption was less than the EIA projection for a given year, theoretically a renewable fuel shortfall could occur. However, our projections of renewable fuel use due to market demand would make a shortfall extremely unlikely regardless of the error in gasoline consumption projections.
The following formula will be used to calculate the percentage standard:
After 2012 the Act requires that the applicable volume of required renewable fuel specified in Table I.B-1 include a minimum of 250 million gallons that are derived from cellulosic biomass. As shown in Table III.A.2-1 below, we have estimated this value (250 million gallons) as a percent of an obligated party's production for 2013. Thus, an obligated party will be subject to two standards in 2013 and beyond, a non-cellulosic standard and a cellulosic standard. We are therefore also finalizing the following formula for calculating the cellulosic standard that is required beginning in 2013:
Note that after 2012 cellulosic RINs cannot be used to satisfy the non-cellulosic RFS standard (RFStd
We are not finalizing regulations that would specify the criteria under which a state could petition the EPA for a waiver of the RFS requirements, nor the ramifications of Agency approval of such a waiver in terms of the level or applicability of the standard. As discussed in the proposal, there was no clear way to include such a provision in the context of the program being finalized. As a result, the formula for the standard shown above does not include any components to account for Agency approval of a state petition for a waiver of the RFS requirements. Should EPA grant such a waiver in the future, it will determine at that time what adjustments to make to the standard.
As discussed in the proposal, EPA will set the percentage standard for each upcoming year based on the most recent EIA STEO projections, and using the other sources of information as noted above. EPA will publish the standard in the
In the NPRM, we estimated the standards for 2007 and later using data available at the time and the formulas discussed above.
As discussed in Section II.A.5, for calendar year 2013 and thereafter, the applicable volumes will be determined in accordance with separate statutory provisions that include EPA coordination with the Departments of Agriculture and Energy, and a review of the program during calendar years 2006 through 2012. The Act specifies that this review consider the impact of the use of renewable fuels on the environment, air quality, energy security, job creation, and rural economic development, and the expected annual rate of future production of renewable fuels, including cellulosic ethanol. We intend to conduct another rulemaking as we approach the 2013 timeframe that would include our review of these factors. That rulemaking will present our conclusions regarding the appropriate applicable volume of renewable fuel for use in calculating the renewable fuel standard for 2013 and beyond. The program finalized by today's rule will continue to apply after 2012, though some elements may be modified in the rulemaking setting the standards for 2013 and beyond. Today's rule does not contain a mechanism for establishing a post-2012 standard.
The Energy Act requires that EPA promulgate regulations to implement the RFS program, and if EPA did not issue such regulations then a default standard for renewable fuel use would apply in 2006. On December 30, 2005 we promulgated a direct final rule to interpret and implement the application of the statutory default standard of 2.78 percent in calendar year 2006 (70 FR 77325). However, the Act provides no default standard for any other year.
In the NPRM we stated our expectation that, due to the limited time available for this rulemaking, we would be unable to publish the final rule and have it become effective by January 1, 2007. We discussed several ways that we could specify how, and for what time periods, the applicable standard and other program requirements would apply to regulated parties for gasoline produced during 2007. We discussed a collective compliance approach similar to that applied in 2006, as well as a “full year” approach that would have based the renewable volume obligation for each obligated party on all gasoline produced starting on January 1, 2007 regardless of the effective date of the rule. However, due to a number of issues with these approaches, we proposed a “prospective” approach in which the renewable fuel standard would be applied to only those volumes of gasoline produced after the effective date of the final rule. Essentially the renewable volume obligation for 2007 would be based on only those volumes of gasoline produced or imported by an obligated party prospectively from the effective date of the rulemaking forward, and renewable producers would not have to begin generating RINs and maintaining the necessary records until this same date.
We received no comments supporting the alternative “full year” approach to 2007 compliance. However, several parties expressed a preference for either a collective compliance approach for 2007, or if not that then delaying implementation of the comprehensive program to January 1, 2008. They argued that regulated parties needed additional time to put into place the sophisticated RIN tracking systems that would be required. The additional time would also allow regulated parties to debug the systems, train personnel, and put support programs into place. The American Coalition for Ethanol also argued that the prospective approach did not guarantee that the total renewable fuel volumes required by the Act for 2007 would actually be used in 2007, whereas a collective compliance approach would. Parties in favor of a collective compliance approach argued that EPA has the authority to implement such an approach despite the fact that the Act does not explicitly give EPA this authority, and also argued that there was no need to include any form of credit carryover under a collective compliance approach.
However, a number of refiners and their associations opposed a collective compliance approach to 2007 and expressed strong support for the proposed prospective approach. They argued that a start date at least 60 days from the date of publication of the final rule would provide sufficient time to obligated parties for making the necessary adjustments for compliance. They also argued that they should be afforded the opportunity to participate as soon as possible in the trading program, which the collective compliance approach used for 2006 would preclude for 2007.
We continue to believe that a collective compliance approach is not appropriate for 2007. The Energy Act requires us to promulgate regulations that provide for the generation of credits by any person who over complies with their obligation. It also stipulates that a person who generates credits must be permitted to use them for compliance purposes, or to transfer them to another party. These credit provisions have meaning only in the context of an individual obligation to meet the applicable standard. Delaying a credit program until 2008 would mean the credit provisions have no meaning at all for 2007, since under a collective compliance approach no individual facility or company would be liable for meeting the applicable standard. Including a “collective” credit or deficit carryforward as part of a collective compliance program would also not fully implement the credit provisions of the Act. The prospective compliance approach, in contrast, not only provides obligated parties with the opportunity to generate credits, but also provides the industry with the certainty they need to comply and is relatively straightforward to implement.
Rather than requiring the program to begin on the effective date of the rule as proposed (60 days following publication in the
As stated in the NPRM, we recognize that the prospective approach to 2007 compliance will not guarantee by regulation that the total renewable fuel volumes required by the Act for 2007 would actually be used in 2007. However, current projections from the Energy Information Administration (EIA) on the volume of renewable fuel expected to be produced in 2007 indicate that the Act's required volumes will be exceeded by a substantial margin due to the relative economic value of renewable fuels in comparison to gasoline. We are confident that the combined effect of the regulatory
In order for an obligated party to demonstrate compliance, the percentage standards described in Section III.A.2 which are applicable to all obligated parties must be converted into the volume of renewable fuel each obligated party is required to satisfy. This volume of renewable fuel is the volume for which the obligated party is responsible under the RFS program, and is referred to here as its Renewable Volume Obligation (RVO).
The calculation of the RVO requires that the standard shown in Table III.A.2-1 for a particular compliance year be multiplied by the gasoline volume produced by an obligated party in that year. To the degree that an obligated party did not demonstrate full compliance with its RVO for the previous year, the shortfall is included as a deficit carryover in the calculation. The equation used to calculate the RVO for a particular year is shown below:
The Energy Act only permits a deficit carryover from one year to the next if the obligated party achieves full compliance with its RVO including the deficit carryover in the second year. Thus deficit carryovers could not occur two years in succession. They could, however, occur as frequently as every other year for a given obligated party.
The calculation of an obligated party's RVO is necessarily retrospective, since the total gasoline volume that it produces in a calendar year will not be known until the year has ended. However, the obligated party will have an incentive to project gasoline volumes, and thus the RVO, throughout the year so that it can spread its efforts to comply across the entire year. Most refiners and importers will be able to project their annual gasoline production volumes with a minimum of uncertainty based on their historical operations, capacity, plans for facility downtimes, knowledge of gasoline markets, etc. Even if unforeseen circumstances (e.g., hurricane, unit failure, etc.) significantly reduced the production volumes in comparison to their projections, their RVO will likewise be reduced proportionally and their ability to comply with the RFS requirements will be only minimally affected. Each obligated party's projected RVO for a given year becomes more accurate as that year progresses, but the obligated party should nevertheless have a sufficiently accurate estimate of its RVO at the beginning of the year to allow it to begin its efforts to comply.
Section 211(o) of the Clean Air Act defines “renewable fuel” and specifies many of the details of the renewable fuel program. The following section provides EPA's views and interpretations on issues related to what fuels may be counted towards compliance with the RVO, and how they are counted.
The statutory definition of renewable fuel includes cellulosic ethanol and waste derived ethanol. It includes biodiesel, as defined in the Energy Act.
According to the Act, the motor vehicle fuels must be used “to replace or reduce the quantity of fossil fuel present in a fuel mixture used to operate a motor vehicle.” Some motor vehicle fuels can be used in both motor vehicles or nonroad engines or equipment. For example, highway gasoline and diesel fuel are often used in both highway and off-highway applications. Compressed natural gas can likewise be used in either highway or nonroad applications. For purposes of the renewable fuel program, EPA considers a fuel to be a “motor vehicle fuel” and to be “a fuel mixture used to operate a motor vehicle,” based on its potential for use in highway and nonroad vehicles, without regard to whether it, in fact, is used in a highway vehicle application. EPA does not believe that the much more complex and costly regulatory scheme that would be needed to track motor vehicle fuel use versus off-road fuel use would be justified. (As discussed further below, heaters and boilers are not considered highway or nonroad engine applications and renewable fuel produced or imported specifically for use in such equipment is not valid for compliance purposes under the RFS program.) If it is a fuel that could be used in highway vehicles, it will satisfy these parts of the definition of renewable fuel, whether it is later used in highway or nonroad applications. This will allow a motor vehicle fuel that otherwise meets the definition to be counted towards a party's RVO without the need to track it to determine its actual application in a highway vehicle, and provided only that the producer does not know that the fuel will be used for a purpose other than highway and nonroad engine applications. This is also consistent with the requirement that EPA base the renewable fuel obligation on estimates of the entire volume of gasoline consumed, without regard to whether it is used in highway or nonroad applications.
Renewable fuel as defined, may be made from a number of different types of feedstocks. For example, the Fisher-Tropsch process can use methane gas from landfills as a feedstock, to produce diesel or gasoline. Vegetable oil made
As this discussion shows, the definition of renewable fuel in the Act is broad in scope, and covers a wide range of fuels. While ethanol is used primarily in combination with gasoline, the definition of renewable fuel in the Act is not limited to fuels that can be blended with gasoline. Various fuels that meet the definition of renewable fuel can be used in their neat form, such as ethanol, biodiesel, methanol or natural gas. Others, including ethanol may be used to produce a gasoline blending component (such as ETBE). At the same time, the RFS regulatory program is to “ensure that gasoline sold or introduced into commerce * * * contains the applicable volume of renewable fuel.” This applicable volume is specified as a total volume of renewable fuel on an aggregate basis. Congress also clearly specified that one renewable fuel, biodiesel, could be counted towards compliance even though it is not a gasoline component, and does not directly displace or replace gasoline. The Act is unclear on whether other fuels that meet the definition of renewable fuel, but are not used in gasoline, could also be used to demonstrate compliance towards the aggregate national use of renewable fuels.
EPA interprets the Act as allowing regulated parties to demonstrate compliance based on any fuel that meets the statutory definition for renewable fuel, whether it is directly blended with gasoline or not. This would include neat alternative fuels such as ethanol, methanol, and natural gas that meet the definition of renewable fuel. This is appropriate for several reasons. First, it promotes the use of all renewable fuels, which will further the achievement of the purposes behind this provision. Congress did not intend to limit the program to only gasoline components, as evidenced by the provision for biodiesel, and the broad definition of renewable fuel evidences an intention to address more renewable fuels than those used with gasoline. Second, in practice EPA expects that the overwhelming volume of renewable fuel used to demonstrate compliance with the renewable fuel obligation would still be ethanol blended with gasoline. Finally, as discussed later, EPA's compliance program is based on assigning volumes at the point of production, and not at the point of blending into motor vehicle fuel. This interpretation avoids the need to track renewable fuels downstream to ensure they are blended with gasoline and not used in their neat form; the gasoline that is used in motor vehicles is reduced by the presence of renewable fuels in the gasoline pool whether they are blended with gasoline or not. Comments received on this interpretation were favorable towards it. EPA continues to believe, therefore, that this approach is consistent with the intent of Congress and is a reasonable interpretation of the Act. One commenter indicated that a logical extension of this reasoning would provide that renewable fuel that could be used in motor vehicles is still a renewable fuel under the Act when used by renewable fuel producers in a boiler or heater. EPA disagrees. The term “renewable fuel” means “motor vehicle fuel that * * * is used to replace or reduce the quantity of fossil fuel present in a fuel mixture used to operate a motor vehicle.” We believe that all but a trivial quantity of renewable fuels that can be used in motor vehicles will ultimately be used as motor vehicle fuel. Producers of ethanol biodiesel and other products that can be used as motor vehicle fuel can generally assume, therefore, that their products will be used in that way, and can assign RINs to their product without tracking its ultimate use. However, renewable fuel used onsite in a boiler or heater by a renewable fuel producer clearly is not a motor vehicle fuel used to replace or reduce the quantity of fossil fuel present in a fuel mixture used to operate a motor vehicle.
Under the Act, renewable fuel includes “cellulosic biomass ethanol” and “waste derived ethanol”, each of which is defined separately. Ethanol can be cellulosic biomass ethanol in one of two ways, as described below.
The simplest process of producing ethanol is by fermenting sugar in sugar cane or beets, but ethanol can also be produced from starch in corn and other feedstocks by first converting the starch to sugar. Ethanol can also be produced from complex carbohydrates, such as the cellulosic portion of plants or plant products. The cellulose is first converted to sugars (by hydrolysis); then the same fermentation process is used as for sugar to make ethanol. Cellulosic feedstocks (composed of cellulose and hemicellulose) are currently more difficult and costly to convert to sugar than are starches. While the cost and difficulty are a disadvantage, the cellulosic process offers the advantage that a wider variety of feedstocks can be used. Ultimately with more feedstocks available from which to make ethanol more volume of ethanol can be produced.
The Act provides the definition of cellulosic biomass ethanol, which states:
“The term ‘cellulosic biomass ethanol’ means ethanol derived from any lignocellulosic or hemicellulosic matter that is available on a renewable or recurring basis, including:
(i) Dedicated energy crops and trees;
(ii) Wood and wood residues;
(iii) Plants;
(iv) Grasses;
(v) Agricultural residues;
(vi) Animal wastes and other waste materials, and
(viii) Municipal solid waste.”
Examples of cellulosic biomass source material include rice straw, switch grass, and wood chips. Ethanol made from these materials would qualify under the definition as cellulosic ethanol. In addition to the above sources of feedstocks for cellulosic biomass ethanol, the Act's definition also includes animal waste, municipal solid wastes, and other waste materials. “Other waste materials” generally includes waste material such as sewage sludge, waste candy, and waste starches from food production, but for purposes of the definition of cellulosic ethanol discussed in III.B.1.b below, it can also mean waste heat obtained from an off-site combustion process.
Although the definitions of “cellulosic biomass ethanol” and “waste derived ethanol” both include animal wastes and municipal solid waste in their respective lists of covered feedstocks, there remains a distinction between these types of ethanol. If the animal wastes or municipal solid wastes contain cellulose or hemicellulose, the resulting ethanol can be termed “cellulosic biomass ethanol.” If the animal wastes or municipal solid wastes do not contain cellulose or hemicellulose, then the resulting ethanol is labeled “waste derived ethanol.” This is discussed further in Section III.B.1.c below.
The definition of cellulosic biomass ethanol in the Act also provides that ethanol made at any facility—regardless of whether cellulosic feedstock is used or not—may be defined as cellulosic if at such facility “animal wastes or other waste materials are digested or otherwise used to displace 90 percent or more of the fossil fuel normally used in the production of ethanol.” The statutory language suggests that there are two methods through which “animal and other waste materials” may be considered for displacing fossil fuel. The first method is the digestion of animal wastes or other waste materials. EPA has interpreted the term “digestion” to mean the conversion of animal or other wastes into methane, which can then be combusted as fuel. We base our interpretation on the practice in industry of using anaerobic digesters to break down waste products such as manure into methane. Anaerobic digestion refers to the breakdown of organic matter by bacteria in the absence of oxygen, and is used to treat waste to produce renewable fuels. We note also that the digestion of animal wastes or other waste materials to produce the fuel used at the ethanol plant does not have to occur at the plant itself. Methane made from animal or other wastes offsite and then purchased and used at the ethanol plant would also qualify.
The second method is suggested by the term “otherwise used” which we interpret to mean (1) the direct combustion of the waste materials as fuel at an ethanol plant, or (2) the use of thermal energy that itself is a waste product; e.g., waste heat that is obtained from an off-site combustion process such as a neighboring plant that has a furnace or boiler from which the waste heat is captured. With respect to the first meaning, “other waste materials” includes but is not limited to waste materials from tree farms (tops, branches, limbs, etc.), or waste materials from saw mills (sawdust, shavings and bark) as well as other vegetative waste materials such as corn stover, or sugar cane bagasse, that could be used as fuel for gasifier/boiler units at ethanol plants. Since these materials are not also used as a feedstock to starch-based ethanol plants, they are truly waste materials. Although these waste materials conceivably could be feedstocks to a cellulosic ethanol plant, their use in that manner is sufficiently challenging at the current time that EPA believes that such use does not subvert the intent of the definition.
Regarding the use of waste heat as a source of thermal energy, we note that there may be situations in which an off-site furnace, boiler or heater creates excess or waste heat that is not used in the process for which the thermal energy is employed. For example, a glass furnace generates a significant amount of waste heat that often goes unused. We have therefore included in the regulatory definition of cellulosic biomass ethanol waste heat generated from off-site sources in the definition of “other waste materials” that can be used to displace 90% of the fossil fuel otherwise used at an ethanol production facility.
Several commenters argued that because the source of the waste heat is ultimately a fossil fuel in most cases that it should not be considered an “other waste material”. The Agency recognizes that fossil fuel is ultimately the source of most waste heat, but it is also the case that waste heat that is uncaptured represents a loss of energy that could otherwise displace fossil fuel use elsewhere. Specifically, waste heat used at an ethanol plant would result in displacement of fossil fuel use at the plant. In writing the proposed rule, we were aware of the concern raised by the commenters and therefore proposed to restrict waste heat to off-site sources only. We believe that this approach minimizes the concern. We disagree with another commenter that such restriction would create a perverse incentive for facilities near ethanol plants to oversize its combustion units to sell waste heat to the neighboring ethanol facilities where it would be used to displace fossil fuel. It is highly unlikely that businesses would incur the additional expense of building an oversized combustion unit for the sale of waste heat. Also, the 2.5 gallon value given for one gallon of cellulosic ethanol as provided by the Act extends only through 2012. Any additional market value for waste heat used to qualify ethanol as cellulosic would therefore be of relatively short duration and not likely to warrant investment in oversized combustion units.
The term “fossil fuel normally used in the production of ethanol” means fossil fuel used at the facility in the ethanol production process itself, rather than other phases such as trucks transporting product, and fossil fuel used to grow and harvest the feedstock. Therefore the diesel fuel that trucks consume in hauling wood waste from sawmills to the ethanol facility would not be counted in determining whether the 90% displacement criterion has been met. We are interpreting it in this way because we believe the accounting of fuel use associated with transportation and other life cycle activities would be extremely difficult and in many cases impossible.
Based on the operation of ethanol plants, we are viewing this definition to apply to waste materials used to produce thermal energy rather than electrical energy. Electrical usage at ethanol plants is used for lights and equipment not directly related to the production of ethanol. Also, the calculation of fossil fuel used to generate such electrical usage would be difficult because it is not always possible to track the source of electricity that is purchased off-site. Therefore, the final regulations consider displacement of 90 percent of fossil fuels at the ethanol plant to mean those fuels consumed on-site and that are used to generate thermal energy used to produce ethanol.
One commenter suggested that electricity from cogeneration (i.e., combined heat and power) units be considered in determining the percentage of fossil fuel use that is displaced. The commenter claims that allowing consideration of electricity use would provide an incentive for cogeneration to be used at ethanol plants. Our findings regarding the use of electricity at ethanol plants remain the same—that is, it is not used as part of
Owners who claim their product qualifies as cellulosic biomass ethanol based on the 90 percent fossil fuel displacement through the use of waste materials (i.e., animal wastes, and other waste materials) are required under today's rule to keep records of fuel (waste-derived and fossil fuel) used for thermal energy for verification of their claims. They will also be required to track the fossil fuel equivalent of any off-site generated waste heat that is captured and which displaces fossil fuel used in the ethanol production process. Since such waste heat would typically be purchased through agreement with the off-site owner, we do not feel it burdensome for owners to track such information. Owners will therefore calculate the amount of energy in Btu's associated with waste-derived fuels (including the fossil fuel equivalent waste heat), and divided by the total energy in Btus used to produce ethanol in a given year. Ethanol produced from such facilities will get the benefit of the 2.5 ratio. (Section III.D.3.e discusses the requirements for owners of facilities that claim to have produced cellulosic ethanol under the 90 percent displacement provision, but which fail to meet those requirements.)
“Waste derived ethanol” is defined in the Act as ethanol derived from “animal wastes, including poultry fats and poultry wastes, and other waste materials; * * * or municipal solid waste.” Both animal wastes and municipal solid waste are also listed as allowable feedstocks for the production of “cellulosic biomass ethanol.” When such feedstocks do not contain cellulose, however, the resulting ethanol is waste derived. Both waste-derived and cellulosic ethanol both are considered equivalent to 2.5 gallons of renewable fuel when determining compliance with the renewable volume obligation.
Some commenters stated that foreign ethanol producers should not be able to have their cellulosic or waste-derived ethanol treated in the same manner as domestic cellulosic or waste-derived ethanol under the RFS program because of the difficulty in verifying their compliance with the provisions discussed above. Today's rule allows such producers to participate, provided they meet the requirements discussed in Section IV.D.2. of the preamble. The requirements for foreign producers of cellulosic or waste-derived ethanol are different than for domestic producers and allow for verification of compliance.
The Act states that “The term ‘renewable fuel’ includes * * * biodiesel (as defined in section 312(f)) of the Energy Policy Act of 1992.” This definition, as modified by Section 1515 of the Energy Act states:
The term “biodiesel” means a diesel fuel substitute produced from nonpetroleum renewable resources that meets the registration requirements for fuels and fuel additives established by the Environmental Protection Agency under section 7545 of this title, and includes biodiesel derived from animal wastes, including poultry fats and poultry wastes, and other waste materials, or municipal solid waste and sludges and oils derived from wastewater and the treatment of wastewater.
This definition of biodiesel would include both mono-alkyl esters which meet the current ASTM specification D-6751-07
To implement the above definition of biodiesel in the context of the RFS rulemaking while still recognizing the unique history and role of mono-alkyl esters meeting ASTM D-6751, we have divided the Act's definition of biodiesel into two separate parts: Biodiesel (mono-alkyl esters) and non-ester renewable diesel. The combination of “biodiesel (mono-alkyl esters)” and “non-ester renewable diesel” in the regulations fulfills the Act's definition of biodiesel. Commenters supported EPA's approach in defining biodiesel in this manner.
Under today's rule, the term “biodiesel (mono-alkyl esters)” means a motor vehicle fuel which: (1) Meets the registration requirements for fuels and fuel additives established by the Environmental Protection Agency under section 7545 of this title (Clean Air Act Section 211); (2) is a mono-alkyl ester; (3) meets ASTM specification D-6751-07; (4) is intended for use in engines that are designed to run on conventional, petroleum-derived diesel fuel, and (5) is derived from nonpetroleum renewable resources.
The term “non-ester renewable diesel” means a motor vehicle fuel which: (1) Meets the registration requirements for fuels and fuel additives established by the Environmental Protection Agency under section 7545 of this title (Clean Air Act Section 211); (2) is not a mono-alkyl ester; (3) is intended for use in engines that are designed to run on conventional, petroleum-derived diesel fuel, and (4) is derived from nonpetroleum renewable resources. Current examples of a non-ester renewable diesel include: “Renewable diesel” produced by the Neste or UOP process, or diesel fuel produced by processing fats and oils through a refinery hydrotreating process.
Renewable fuels can be produced by processing biologically derived wastes such as animal fats, as well as other nonpetroleum based feedstocks in a traditional refinery—that is, a refinery that normally uses crude oil or other fossil fuel-based blendstocks as feeds to processing units. Such wastes are pre-processed so that they are in liquid form to enable their further processing in units at a traditional refinery. In the proposed rule, we defined such feedstocks as “biocrudes” and included a discussion on how the fuels resulting from these feedstocks should be counted. Our basic approach remains the same. We have changed the term “biocrudes” to “renewable crudes”, since we believe it is more accurate. We are providing additional discussion in this preamble on how renewable fuels are made from renewable crudes.
The fuels resulting from the co-processing of the pre-processed liquid form of these renewable crudes (i.e., those feedstocks listed in the definition of “renewable fuel” and, for biodiesel, in the statutory definition of “biodiesel”) in a traditional refinery are
The processing approach for the renewable feedstock dictates whether the resulting fuel is distinguishable from crude oil-based fuels by virtue of its being made and stored separately from fossil fuels as discussed in further detail below. Therefore, our method for counting renewable fuels made from renewable feedstocks differ based on how the renewable feedstock is processed
Under some circumstances renewable feedstocks can be preprocessed into a liquid that is similar to petroleum-based feedstocks used in traditional refineries. We are classifying such liquids as “renewable crudes,” and any motor vehicle fuel that is made from such liquids is defined broadly as “renewable crude-based fuel”.
There are three approaches that can be taken to making renewable fuels from renewable crudes. The first would include gasoline or diesel products resulting from the processing of renewable crudes in production units within refineries that simultaneously process crude oil and other petroleum based feedstocks. In these cases, the final product consists of a mixture of renewable fuel and fossil-based fuel, and may include both motor vehicle fuel and non-motor vehicle fuel. The second approach would include diesel and other products resulting from processing renewable crudes at a stand-alone facility that does not process any fossil fuels, or at a facility dedicated to renewable crudes within a traditional refinery.
As discussed above, some renewable feedstocks are processed in facilities other than refineries, or in equipment located within a traditional refinery but which is dedicated to renewable feedstocks. The resulting product is “renewable diesel” (and such units may in the future also produce “renewable gasoline” though none is currently made in such dedicated facilities). In other situations, renewable crudes are coprocessed along with crude oils in traditional refineries, resulting in gasoline or diesel products that may be combinations of renewable and non-renewable fuels.
In the case of renewable crude coprocessed with fossil fuels in refineries, we are assuming that all of the renewable crude used as a feedstock in a refinery unit will end up as a renewable crude-based fuel that is valid for RFS compliance purposes. We are taking this approach because renewable crudes that are processed through distillate hydrotreaters are first pre-processed so that they are in liquid form, and such liquid produces diesel fuel in volumes approximately equal to the amount that is input to the hydrotreater. We are assuming that renewable crudes could also be processed in other process units at refineries to make gasoline. The renewable crude processed at a refinery is functionally equivalent to crude oil, and the end products (gasoline and/or diesel) are indistinguishable from products made from crude oil. Thus, rather than requiring the refiner to document what portion of the renewable crude-based fuel is renewable fuel, we are requiring that the volume of the renewable crude itself count as the volume of renewable fuel produced for the purposes of determining the volume block codes that are in the RIN (discussed in further detail in Section III.D).
One question that EPA needed to address in developing the regulations was how to count volumes of renewable fuel in determining compliance with the renewable volume obligation. The Act stipulates that every gallon of waste-derived ethanol and cellulosic biomass ethanol should count as if it were 2.5 gallons for RFS compliance purposes. The Act does not stipulate similar values for other renewable fuels, but as described below we believe it is appropriate to do so.
We are requiring that the “Equivalence Values” for renewable fuels other than those for which specific values are set forth in the Act be based on their energy content in comparison to the energy content of ethanol, adjusted as necessary for their renewable content. The result is an Equivalence Value for corn ethanol of 1.0, for biobutanol of 1.3, for biodiesel (mono alkyl ester) of 1.5, and for non-ester renewable diesel of 1.7. However, the methodology can be used to determine the appropriate equivalence value for any other potential renewable fuel as well.
This section describes why the use of the Equivalence Value approach in today's rule is appropriate under the Act, and our conclusions regarding the possible future use of lifecycle analyses as the basis of Equivalence Values.
We are requiring that Equivalence Values be assigned to every renewable fuel to provide an indication of the number of gallons that can be claimed for compliance purposes for every physical gallon of renewable fuel. An Equivalence Value of 1.0 means that every physical gallon of renewable fuel counts as one gallon for RFS compliance purposes. An Equivalence Value greater than 1.0 means that every physical gallon of renewable fuel counts as more than one gallon for RFS compliance
We have interpreted the Act as allowing us to develop Equivalence Values according to the methodology discussed below. We believe that the use of Equivalence Values based on energy content in comparison to the energy content of ethanol is consistent with the intent of Congress to treat different renewable fuels differently in different circumstances, and to provide incentives for use of renewable fuels in certain circumstances, as evidenced by those specific circumstances addressed by Congress. The Act has several provisions that provide for mechanisms other than straight volume measurement to determine the value of a renewable fuel in terms of RFS compliance. For example, 1 gallon of cellulosic biomass or waste derived ethanol is to be treated as 2.5 gallons of renewable fuel. EPA is also required to establish an “appropriate amount of credits” for biodiesel, and to provide for “an appropriate amount of credit” for using more renewable fuels than are required to meet your obligation. EPA is also to determine the “renewable fuel portion” of a blending component derived from a renewable fuel. These statutory provisions provide evidence that Congress did not limit this program solely to a straight volume measurement of gallons in the context of the RFS program.
In response to the NPRM, some commenters supported our view that the Act provides sufficient context and direction to permit the use of Equivalence Values, while other commenters opposed this view. Some parties commented that the methodology proposed in the NPRM did not go far enough. These parties argued that instead of energy content, EPA should be using lifecycle impacts to set the Equivalence Values. Lifecycle analyses are discussed in more detail in Section III.B.4.c.
Parties that opposed our proposed approach to Equivalence Values argued that since the Act did not explicitly give EPA the authority to set Equivalence Values for renewable fuels other than cellulosic biomass ethanol and waste-derived ethanol, EPA had no authority to do so. In their view, the explicit inclusion of a 2.5 credit value for cellulosic and waste-derived ethanol and the omission of any credit values for other renewables fuels should be taken as evidence that Congress intended all other renewable fuels to have Equivalence Values of 1.0.
We disagree that our discretion is so strictly limited. The Act specifically gave EPA the authority to determine an “appropriate” credit for biodiesel, and also establishes a 2.5 value for cellulosic biomass ethanol and waste-derived ethanol. As ethanol and biodiesel were likely the two primary renewable fuels envisioned in the near-term under the Act, it would seem normal for Congress to have focused on these. However, Congress also clearly allowed for other renewable fuels to participate in the RFS program, and it is appropriate for EPA to consider how they should be treated under the Act. Furthermore, in addition to the Act's direction that EPA determine an appropriate level of credit for biodiesel, the Act also directs EPA to determine the “appropriate” amount of credit for renewable fuel use in excess of the required volumes, and to determine the “renewable fuel portion” of a blending component derived from a renewable fuel. These statutory provisions lend further support to our belief that Congress did not limit the RFS program solely to a straight volume measurement of gallons. Having concluded that it is appropriate to determine an appropriate level of credit for biodiesel based on energy content as compared to ethanol, EPA is using a consistent approach for other types of renewable fuels for which a specific statutory credit value is not prescribed.
Another reason given by parties opposing our approach to Equivalence Values was that Equivalence Values higher than 1.0 would result in actual volumes of renewable fuel being less than the volumes required by the Act. Although it is true that the Act specifies the annual volumes of renewable fuel that the program must require and directs EPA to promulgate regulations ensuring that gasoline sold each year “contains the applicable volume of renewable fuel,” the Act also contains language that makes the achievement of those volumes imprecise. For instance, the deficit carryover provision allows any obligated party to fail to meet its RVO in one year if it meets the deficit and its RVO in the next year. If many obligated parties took advantage of this provision, it could result in the nationwide total volume obligation for a particular calendar year not being met. In addition, the calculation of the renewable fuel standard is based on projected nationwide gasoline volumes provided by EIA (see Section III.A). If the projected gasoline volume falls short of the actual gasoline volume in a given year, the standard will fail to create the demand for the full renewable fuel volume required by the Act for that year. The Act contains no provision for correcting for underestimated gasoline volumes, and as a result the volumes required by the Act may not be consumed in use.
Some commenters disagreed with our belief that there will only be very limited additional situations where an Equivalence Value other than 1.0 is used. They expressed concern that the provision for Equivalence Values will interfere with meeting the total national volume goals for usage of renewable fuel.
While in the long term we agree that renewable fuels with an Equivalence Value greater than 1.0 may grow to become a larger portion of the renewable fuel pool, we do not believe that this is likely to be the case before 2013, the time period when the statute specifies the overall national volumes. EPA will be issuing a new rule prior to 2013, and can reconsider its approach to Equivalence Values for renewable fuel at that time if it is appropriate to do so. For instance, EIA projects that biodiesel volumes will reach 300 million gallons by 2012. With the Equivalence Value of 1.5 that we are finalizing today, this means that the 7.5 billion gallons required by the Act for 2012 could be met with 7.35 billion gallons of renewable fuel. However, this result is well within the variability in actual volumes resulting from the other statutory provisions described above, and would still result in 7.5 billon gallons of ethanol-equivalent (in terms of energy content) renewable fuel being consumed. Congress explicitly recognized the expected use of credits for biodiesel, as it did for cellulosic ethanol. By requiring or authorizing EPA to assign credit values for such products, Congress recognized that the national volumes specified in the Act would not necessarily be met on a gallon per gallon basis. For the very limited number of other renewable fuels not covered by these express statutory provisions, assigning an equivalence value is consistent with this overall approach. Moreover, EIA is projecting that the total volume of renewable fuel will exceed the Act's requirements by a substantial margin due primarily to the favorable economics of ethanol in comparison to gasoline. Under such projections, the existence of renewable fuels with Equivalence Values higher than 1.0 will have no impact on the demand for renewable fuel.
Finally, the Act also contains language indicating that EPA has flexibility in determining how various renewable fuels should count towards meeting the required annual volumes. For instance, valid renewable fuels are defined as those that “replace or reduce the quantity of fossil fuel present in a fuel mixture used to operate a motor
A case in point would be butanol. It is produced from the same feedstocks as ethanol (i.e., starch crops such as corn) in a similar process. However, it results in an alcohol with a higher volumetric energy content than ethanol. If we were to give butanol an Equivalence Value of 1.0, it would provide an economic disincentive for corn to be used to produce butanol instead of ethanol.
As a result, we continue to believe that the assignment of Equivalence Values other than 1.0 to some renewable fuels is a reasonable way for the RFS program to establish “appropriate” credit values while also ensuring that the Act's volume obligations, read together with the Act's directions regarding credit values towards fulfillment of that obligation, are satisfied. This approach is consistent with the way Congress treated the various specific circumstances noted above, and thus is basically a continuation of that process.
To appropriately account for the different energy contents of different renewable fuels as well as the fact that some renewable fuels actually contain some non-renewable content, we are requiring that Equivalence Values be calculated using both the renewable content of a renewable fuel and its energy content. This section describes the calculation methodology for Equivalence Values.
In order to take the energy content of a renewable fuel into account when calculating the Equivalence Values, we must identify an appropriate point of reference. Ethanol is a reasonable point of reference as it is currently the most prominent renewable fuel in the transportation sector, and it is likely that the authors of the Act saw ethanol as the primary means through which the required volumes would be met in at least the first years of the RFS program. By comparing every renewable fuel to ethanol on an equivalent energy content basis, each renewable fuel is assigned an Equivalence Value that precisely accounts for the amount of petroleum in motor vehicle fuel that is reduced or replaced by that renewable fuel in comparison to ethanol. To the degree that corn-based ethanol continues to dominate the pool of renewable fuel, this approach allows actual volumes of renewable fuel to be consistent with the volumes required by the Act.
Equivalence Values also account for the renewable content of renewable fuels, since the presence of any non-renewable content impairs the ability of the renewable fuel to replace or reduce the quantity of fossil fuel present in a fuel mixture used to operate a motor vehicle. The Act specifically states that only the renewable fuel portion of a blending component should be considered part of the applicable volume under the RFS program. As described in more detail below, we have interpreted this to mean that every renewable fuel should be evaluated at the molecular level to distinguish between those molar fractions that were derived from a renewable feedstock, versus those molar fractions that were derived from a fossil fuel feedstock. Along with energy content in comparison to ethanol, the relative energy fraction of renewable versus non-renewable content is thus used directly as the basis for the Equivalence Value.
We are requiring that the calculation of Equivalence Values simultaneously take into account both the renewable content of a renewable fuel and its energy content in comparison to denatured ethanol. To accomplish this, we are requiring the following formula:
Instead of the higher heating value, the lower heating value (LHV) is used to represent energy content because it more accurately reflects the energy available in the fuel to produce work.
R is a measure of that portion of the renewable fuel molecules which can be considered to have come from a renewable source. Since R (that is, R
In the case of ethanol, denaturants are added to preclude the ethanol's use as food. Denaturants are generally a fossil-fuel based, gasoline-like hydrocarbon in concentrations of 2-5 volume percent, with 5 percent being the most common historical level. One commenter argued that the Equivalence Value of ethanol must be specified as 0.95 for this very reason. However, as described in the NPRM, we believe that the Equivalence Value for ethanol should be specified as 1.0 despite the presence of a denaturant. First, as stated above, ethanol is expected to dominate the renewable fuel pool for at least the next several years, and it is likely that the authors of the Act recognized this fact. Thus it seems likely that it was the intent of the authors of the Act that each physical gallon of denatured ethanol be counted as one gallon for RFS compliance purposes. Second, the accounting of ethanol has historically ignored the presence of the denaturant. For instance, under Internal Revenue Service (IRS) regulations the denaturant can be counted as ethanol by parties filing claims to the IRS for the federal excise tax credit. Also, EIA reporting requirements for ethanol producers allow them to include the denaturant in their reported volumes. The commenter arguing for the use of an Equivalence Value of 0.95 for ethanol provided no additional information to counter these arguments.
Since we are requiring that denatured ethanol be assigned an Equivalence Value of 1.0, this must be reflected in the values of R
For the specific case of biogas which cannot be measured in volumetric units, we are specifying that 77,550 Btu of biogas will be considered to be the equivalent of one gallon of renewable fuel.
The calculation of the Equivalence Value for a particular renewable fuel can lead to values that deviate only slightly from 1.0, and/or can have varying degrees of precision depending on the uncertainty in the value of R or EC
Consistent with the NPRM,
Since there are a wide variety of possible renewable fuels that could qualify under the RFS program, there may be cases in which a party produces a renewable fuel not shown in Table III.B.4-1. A party may also produce a renewable fuel listed in the above table, but which has a different renewable content or energy content than the values assumed for our calculations. For such cases we have created a regulatory mechanism through which the producer may submit a petition to the Agency describing the renewable fuel, its feedstock and production process, and the calculation of its Equivalence Value. The Agency will review the petition and approve an appropriate Equivalence Value based on the information provided. We will publish newly assigned Equivalence Values in the
In the NPRM, we also described an additional approach to setting the Equivalence Value for biodiesel (mono alkyl esters). Since ethanol derived from waste products such as animal wastes and municipal solid waste will be assigned an Equivalence Value of 2.5 based on a requirement in the Act, we pointed out that it might be appropriate to create a parallel provision for biodiesel made from wastes. Under this approach, biodiesel made from waste products would have been assigned an Equivalence Value of 2.5 through 2012. Supporters of 2.5 Equivalence Value argued that it would place the treatment of waste-derived biodiesel on the same level as waste-derived ethanol, and that it would be good Agency policy to encourage and reward parties that turn materials that would otherwise be wasted into usable motor vehicle fuel. While some of these arguments may have merit, we nevertheless believe that it is most appropriate to maintain the general methodology applicable to renewable fuels at this time and reserve the 2.5:1 valuation for just the fuel specified by Congress. Therefore, we have not finalized a 2.5 Equivalence Value for waste-derived biodiesel.
For the specific case of ETBE, we have chosen for this final rule to eliminate a uniquely determined Equivalence Value. As described in Section III.D.2.b, ETBE is generally made from ethanol to which RINs will have already been assigned. An ETBE producer, therefore, would need only assign the RINs received with the ethanol to the ETBE made from that ethanol. In this case, there will be no need to generate new RINs, and therefore no need for a separate Equivalence Value.
Except for cellulosic biomass ethanol and waste-derived ethanol, the Equivalence Values shown in Table III.B.4-1, or any others approved through the petition process, will be applicable for all years. However, beginning in 2013, the 2.5 to 1 ratio no longer applies for cellulosic biomass
In the NPRM we also described an alternative approach in which Equivalence Values for renewable fuels would be based on lifecycle analyses. We described both the merits and challenges associated with such an approach and requested comment. Based on the comments received we continue to believe that lifecycle analyses could provide a means of reflecting the relative benefits of one renewable fuel in comparison to another. However, we are not, in this action, establishing Equivalence Values on a lifecycle basis. Rather, we intend to continue evaluating and updating the tools and assumptions associated with lifecycle analyses in a collaborative effort with stakeholders. This rulemaking makes no determination and should not be interpreted to make any determination regarding whether EPA has the legal authority under section 1501 of the Energy Act, as incorporated in section 211(o) of the Clean Air Act, to use lifecycle analysis in establishing Equivalence Values in general or Equivalence Values specifically related to greenhouse gas or carbon dioxide emissions. This section describes some of the comments we received on the use of lifecycle analyses and our responses.
Lifecycle analyses involve an examination of fossil fuel used, and emissions generated, at all stages of a renewable fuel's life. A typical lifecycle analysis examines production of the feedstock, its transport to a conversion facility, the conversion of the feedstock into renewable motor vehicle fuel, and the transport of the renewable fuel to the consumer. At each stage, every activity that consumes fossil fuels or results in emissions is quantified, and these energy consumption and emission estimates are then summed over all stages. By accounting for every activity associated with renewable fuels over their entire life, we can assess renewable fuels in terms of not just their impact within the transportation sector, but across all sectors and thus for the nation as a whole. In this way, lifecycle analyses provide a more complete picture of the potential impacts of different fuels or different fuel sources. While the use of energy content to establish Equivalence Values is an improvement over a simple gallon-for-gallon approach, a lifecycle basis would provide a further level of sophistication in assessing the net energy input and output of fuels and the emissions associated with the use of different fuels.
Supporters of the use of lifecycle analyses for setting the Equivalence Values of different renewable fuels pointed to several advantages of this approach. First, doing so could create an incentive for obligated parties to choose renewable fuels having a greater ability to reduce fossil fuel use or resulting emissions, since such renewable fuels would have higher Equivalence Values and thus greater value in terms of compliance with the RFS requirements. The preferential demand for renewable fuels having higher Equivalence Values could in turn spur additional growth in production of these renewable fuels. Second, using lifecycle analyses as the basis for Equivalence Values could orient the RFS program more explicitly towards reducing petroleum use, fossil fuel use or emissions.
However, the use of lifecycle analyses to establish the Equivalence Values for different renewable fuels also raises a number of issues, generally acknowledged by supporters of the use of lifecycle analyses. For instance, lifecycle analyses can be conducted using several different metrics, including total fossil fuel consumed, petroleum energy consumed, regulated pollutant emissions (e.g., VOC, NO
There is also no consensus on the approach to lifecycle analyses themselves. Although we have chosen to base our lifecycle analyses on Argonne National Laboratory's GREET model for the reasons described in Section IX, there are a variety of other lifecycle models and analyses available. The choice of model inputs and assumptions all have a bearing on the results of lifecycle analyses, and many of these assumptions remain the subject of debate among researchers. Lifecycle analyses must also contend with the fact that the inputs and assumptions generally represent industry-wide averages even though energy consumed and emissions generated vary widely from one facility or process to another.
There currently exists no organized, comprehensive dialogue among stakeholders about the appropriate tools and assumptions behind any lifecycle analyses. We will be initiating more comprehensive discussions about lifecycle analyses with stakeholders in the near future.
Another issue related to using lifecycle analyses as the basis for Equivalence Values pertains to the ultimate impact that the RFS program would have on petroleum use, fossil fuel use, regulated pollutant emissions, and/or emissions of GHGs. With a fixed volume of renewable fuel required under the RFS program, any renewable fuel with an Equivalence Value greater than 1.0 would necessarily mean that fewer actual gallons would be needed to meet the RFS standard. Thus, the advantage per gallon may be offset with fewer overall gallons, resulting in no overall additional benefit under the chosen metric for using fuels with higher Equivalence Values unless the RFS standard was simultaneously adjusted by Congress.
Based on comments received in response to our NPRM, we continue to believe that the current state of scientific inquiry surrounding lifecycle analyses is not sufficiently robust to warrant its use to set Equivalence Values in this final rule. Since renewable fuel use is expected to far exceed the standards being finalized today, a higher equivalence value for those renewables with greater lifecycle benefits will likely do little to stimulate their use. However, if in the future the RFS standard more closely matches renewable demand, this could be important. We are committed to continuing our investigations into lifecycle analyses.
The Act requires EPA to promulgate regulations designed to ensure that “gasoline sold or introduced into commerce in the United States (except in noncontiguous states or territories)” contains on an annual average basis, the applicable aggregate volumes of renewable fuels as prescribed in the Act.
Gasoline produced or imported for use in a noncontiguous state or U.S. territory
For purposes of this preamble, the various gasoline products (as described above) that are included in the volume of gasoline used to determine the renewable fuel obligation are collectively called “gasoline.”
The final rule excludes the volume of renewable fuels contained in gasoline from the volume of gasoline used to determine the renewable fuels obligation. In implementing the Act's renewable fuels requirement, our primary goal was to design a program that is simple, flexible and enforceable. If the program were to include renewable fuels in the volume of gasoline used to determine the renewable fuel obligation, then every blender that blends ethanol downstream from the refinery or importer would be subject to the renewable fuel obligation for the volume of ethanol that they blend. There are currently approximately 1,200 such ethanol blenders. Of these blenders, only those who blend ethanol into RBOB are regulated parties under current fuels regulations. Designating all of these ethanol blenders as obligated parties under the RFS program would greatly expand the number of regulated parties and increase the complexity of the RFS program beyond that which is necessary to carry out the renewable fuels mandate under the Act.
The Act provides that the renewable fuel obligation shall be “applicable to refiners, blenders, and importers, as appropriate.”
The NPRM was unclear with regard to whether obligated parties are to determine their renewable fuel obligation based on the gasoline production of all of their facilities in the aggregate, or each facility individually. As discussed above, EPA has discretion under the Energy Act to determine the renewable fuels obligation applicable to parties, “as appropriate.” We believe that allowing obligated parties to determine their obligation based on either their facilities in the aggregate or individually is appropriate, since allowing this flexibility will not affect compliance with the RFS. Although some commenters expressed concern that obligated parties with multiple facilities could gain an economic advantage over obligated parties with only a single facility if aggregate compliance is allowed, we do not believe that this will be the case given the unrestricted trading allowed under our program. We also believe that clarification in the regulations regarding the basis on which the obligation may be determined is a necessary and logical outgrowth of the proposal. As a result, the regulations have been modified in the final rule to clarify that the renewable fuels obligation may be determined based on the gasoline production of all of an obligated party's facilities in the aggregate, or each facility individually.
We received comment that EPA should clarify when obligated parties must include imported gasoline that is used as “gasoline treated as blendstock”, or GTAB, in the volume of gasoline used to determine the party's renewable fuel obligation. As stated in the preamble to the proposed rule, GTAB is to be treated as a blendstock with regard to the RFS rule. Where the GTAB is blended with other blendstock (other than only renewable fuel) to produce gasoline, the total volume of the gasoline blend, including the GTAB, is included in the volume of gasoline used to determine the renewable fuel obligation. Where the GTAB is blended with finished gasoline, only the GTAB volume is included in the volume of gasoline used to determine the renewable fuel obligation (since the finished gasoline will already be included in the RFS calculations of the refiner of that gasoline). For purposes of compliance demonstrations, the RFS rule treats GTAB in a manner that is consistent with the reformulated gasoline (RFG) and conventional gasoline (CG) regulations. Under the RFG/CG regulations, importers who designate imported gasoline as GTAB must be registered with EPA as both an importer and a refiner. The importer submits separate compliance reports to EPA, one in its capacity as an importer, and one in its capacity as a refiner. The GTAB is blended by the importer and included in the importer's compliance calculations in its capacity as a refiner of the GTAB, and is excluded from the importer's compliance calculations in its capacity as an importer. The RFS rule treats GTAB in a similar manner; i.e., the importer includes the GTAB in the volume of gasoline used to determine the renewable fuel obligation of the importer in its capacity as a refiner of the GTAB, and excludes the GTAB in the volume of gasoline used to
We received comment that EPA should clarify that the terms RBOB and CBOB include “blendstocks for oxygenate blending” that are designed to comply with state fuels requirements, such as CARBOB (California), AZRBOB (Arizona), and LVBOB (Las Vegas). As discussed in Section III.C.1, all gasoline, and all unfinished gasoline that becomes finished gasoline upon the addition of oxygenate, that is produced or imported for use in the contiguous United States is included in the volume of gasoline used to determine an obligated party's renewable fuels obligation. As such, any finished gasoline, or unfinished gasoline that becomes finished gasoline upon the addition of oxygenate, that is produced or imported to comply with state fuels programs must also be included in the volume of gasoline used to determine an obligated party's renewable fuels obligation. The regulations have been clarified in this regard.
Under the final rule, any person who meets the definition of refiner under the fuels regulations, which includes any blender who produces gasoline by combining blendstocks or blending blendstocks into finished gasoline, is subject to the renewable fuels obligation. Any person who brings gasoline into the 48 contiguous states from a foreign country or from an area that has not opted-in to the RFS program, or brings gasoline from a foreign country or an area that has not opted-in to the RFS program into an area that has opted-in to the RFS program, is considered an importer under the RFS program and is subject to the renewable fuels obligation. As noted above, a blender who only blends renewable fuels downstream from the refinery or importer is not subject to the renewable fuel obligation. Any person that is required to meet the renewable fuels obligation is called an “obligated party.” We generally refer to all of the obligated parties as refiners and importers, since the covered blenders are all refiners under the regulations.
A refiner or importer located in a noncontiguous state or U.S. territory is not subject to the renewable fuel obligation and thus is not an obligated party (unless the noncontiguous state or territory opts-in to the RFS program). A party located within the contiguous 48 states is an obligated party if it “imports” into the 48 states any gasoline produced or imported by a refiner or importer located in a noncontiguous state or territory.
We received comment that EPA should clarify how the RFS rule applies to transmix processors and blenders. Transmix processors and blenders are treated like any other blenders under the RFS rule. Transmix processors are parties that separate the gasoline portion of the transmix from the transmix and either sell the gasoline portion as finished gasoline or blend it with other components to produce gasoline. Transmix processors exclude the gasoline portion of the transmix from the volume that is used to determine the party's renewable fuel obligation, since the gasoline portion of the transmix would have been included in the volume used to determine the renewable fuels obligation of the refiner or importer of the gasoline. In calculating the volume used to determine its renewable fuel obligation, the transmix processor would include any blendstocks (other than renewable fuels) that are added to the gasoline separated from the transmix. Where the transmix processor combines the gasoline portion of the transmix with purchased finished gasoline, both the gasoline portion of the transmix and the finished gasoline would be excluded, since the finished gasoline would have been included in the volume used to determine the renewable fuels obligation of the refiner or importer of the finished gasoline. Transmix blenders are parties that blend small amounts of unprocessed transmix into gasoline. Transmix blenders are not obligated parties if they only blend transmix into finished gasoline. If the transmix blender adds blendstocks to the transmix, the transmix blender would be an obligated party with regard to the volume of blendstocks added. The regulations have been clarified with regard to how the RFS rule applies to transmix processors and blenders.
The Act provides an exemption from the RFS standard for small refineries during the first five years of the program. The Act defines small refinery as “a refinery for which the average aggregate daily crude oil throughput for a calendar year (as determined by dividing the aggregate throughput for the calendar year by the number of days in the calendar year) does not exceed 75,000 barrels.”
In addition to small refineries as defined in the Act, we proposed to extend this relief to refiners who, during 2004: (1) Produced gasoline at a refinery by processing crude oil through refinery processing units; (2) employed an average of no more than 1,500 people, including all employees of the small refiner, any parent company and its subsidiary companies; and (3) had a total average crude oil processing capability for all of the small refiner's refineries of 155,000 barrels per calendar day (bpcd). These size criteria were established in prior rulemakings and were the result of our analyses of small refiner impacts. Based on information currently available to us, we believe that there are only three gasoline refineries owned by small refiners that meet these criteria and that currently exceed the 75,000 bpcd crude oil processing capability defined by the Act.
We received comments supporting the proposed extension of the small refinery exemption to small refiners, and we also received comments opposing the proposed provision. Commenters that supported the provision generally stated that they believe that a small refiner exemption is necessary as those entities (i.e., companies) that would qualify as small refiners are generally at an economic disadvantage due to their company size—whereas the Act only recognizes facilities, based on the size of each location. These commenters also stated that they have concerns with the cost and the availability of credits under this program, and believe that provisions for small refiners are
As stated in the proposal, we believe that we have discretion in determining an appropriate lead-time for the start-up of this program, as well as discretion to determine the regulated refiners, blenders and importers, “as appropriate.” We continue to believe that some refiners, due to their size, generally face greater challenges compared to larger refiners. The Small Business Regulatory Enforcement Fairness Act (SBREFA) also recognizes this and requires agencies, during promulgation of new standards, to assess the potential impacts on small businesses (as defined by the Small Business Administration (SBA) at 13 CFR 121.201). For those instances where the Agency cannot certify that a rule will not have a significant economic impact on a substantial number of small entities, we are required to convene a SBREFA Panel. A SBREFA Panel process—which generally takes at least six months to complete—entails performing outreach with entities that meet the definition of a small business to develop ways to mitigate potential adverse economic impacts on small entities, in consultation with SBA and the Office of Management and Budget (OMB).
“Small refiners” have historically been recognized in EPA fuel regulations as those refiners who employ no more than 1,500 employees and have an average crude oil capacity of 155,000 bpcd. These refiners generally have greater difficulty in raising and securing capital for investing in capital improvements and in competing for engineering resources and projects. This rulemaking does not require that refiners make capital improvements, however there are still significant costs associated with meeting the standard. While we were not required to assess the impacts on small businesses under the Energy Policy Act, we are required to do so under SBREFA. Based on our own analysis and outreach with small refiners, our assessment is that this rule will not impose a significant adverse economic impact on small refiners if they are given the small refinery exemption. Further, as noted above, we believe that no more than three additional refiners that do not meet the Energy Policy Act's definition of a small refinery will qualify as small refiners for this rule. Therefore, we are finalizing the proposed provision that the small refinery exemption will be provided to qualified small refiners. This exemption does not mean that less renewable fuel will be used than is required in the Energy Policy Act; rather, it just means that small refiners will not be obligated to ensure that those volumes are attained during the period of their exemption.
We also proposed to allow foreign refiners to apply for a small refinery or small refiner exemption under the RFS program. We requested comment on the provision and related aspects, and we received some comments in which commenters stated that they believe that there is no reason to extend the small refinery exemption to these refiners. One commenter even stated that it believes that such an allowance would be unlawful. We proposed this provision for consistency with prior gasoline-related fuel programs (anti-dumping, MSAT, and gasoline sulfur) which allowed foreign refiners to receive such exemptions, and we are finalizing the provision in this action. Under this provision, foreign small refiners and foreign small refineries can apply for an exemption from the RFS standards such that importers would not count the small refiner or small refinery gasoline volumes towards the importer's renewable volume obligation. The Energy Policy Act does not prohibit EPA from granting this avenue of relief to foreign entities, and EPA believes it is consistent with the spirit of international trade agreements to provide it.
In the proposal we stated that applications for a small refinery exemption must be received by EPA by September 1, 2007 for the exemption to be effective in 2007 and subsequent calendar years. We proposed that the application should include documentation that the small refinery's average aggregate daily crude oil throughput for calendar year 2004 did not exceed 75,000 barrels; and that eligibility would be based on 2004 data (rather than 2005). Further, we proposed that the small refinery exemption would be effective 60 days after receipt of the application by EPA unless EPA notifies the applicant that the application was not approved or that additional documentation is required. We received comments on this provision in which commenters stated that requiring small refinery applications was inconsistent with the language set out in the Act. The commenters stated that small refineries should not be obligated parties in 2007 even if they do not submit a small refinery application by September 1, 2007. We agree with these statements, and believe that the Energy Policy Act did in fact intend to provide this exemption without the need for small refineries to submit applications. However, in order to ensure that this provision is not being misused, we believe that it is necessary for refiners to verify that their refineries meet the definition set out in the Act. Therefore, we are finalizing that the small refinery exemption will become active immediately upon the effective date of the rule. Refiners will only be required to send a letter to EPA verifying their status as a small refinery. We did not receive any comments on our proposal to base eligibility on 2004 data, nor did we receive comments on whether a multiple-year average should be used. We believe that eligibility should be based on 2004 data rather than on 2005 data, since it was the first full year prior to passage of the Energy Act. In addition, some refineries' production may have been affected by Hurricanes Katrina and Rita in 2005. We are thus finalizing our proposed approach to base eligibility on 2004 data.
As discussed above, we proposed that refiners that do not qualify for a small refinery exemption under the 75,000 bpcd criteria, but nevertheless meet the criteria of a small refiner may apply for small refiner status under the RFS rule. We proposed that the applications must be received by EPA by September 1, 2007 for the exemption to be effective in 2007 and subsequent calendar years (similar to the small refinery exemption). We also proposed that small refiner status would be determined based on documentation submitted in the application which demonstrates that the refiner met the criteria for small refiner status during the calendar year 2004 and that EPA would notify a refiner of approval or disapproval of small refiner status by letter.
The final rule provides that qualified small refiners receiving the small refinery exemption will also receive the exemption immediately upon the effective date of the rule. These refiners must also submit a verification letter showing that they meet the small refiner criteria. This letter will be similar to the small refiner applications required under other EPA fuel programs (and must contain all the required elements
The Act provides that the Secretary of Energy must conduct a study for EPA to determine whether compliance with the renewable fuels requirement would impose a disproportionate economic hardship on small refineries. If the study finds that compliance with the renewable fuels requirements would impose a disproportionate economic hardship on a particular small refinery, EPA is required to extend the small refinery's exemption for a period of not less than two additional years (i.e., to 2013). The Act also provides that a refiner with a small refinery may at any time petition EPA for an extension of the exemption for the reason of disproportionate economic hardship. In accordance with these provisions of the Act, we are finalizing the provision that refiners with small refineries may petition EPA for an extension of the small refinery exemption. As provided in the Act, EPA will act on the petition not later than 90 days after the date of receipt of the petition. Today's regulations do not provide a comparable opportunity for an extension of the small refinery exemption for small refiners. Therefore, all parties temporarily exempted from the RFS program on the basis of qualifying as a small refiner, rather than a small refinery, must comply with the program beginning January 1, 2011 (unless they waive their exemption prior to this date).
During the initial exemption period for small refineries and small refiners and any extended exemption periods for small refineries, the gasoline produced by exempted small refineries and refineries owned by approved small refiners will not be subject to the renewable fuel standard.
We proposed that the automatic exemption to 2011 and any small refinery extended exemptions may be waived upon notification to EPA; and we are finalizing this provision. Gasoline produced at a refinery which waives its exemption will be included in the RFS program and will be included in the gasoline used to determine the refiner's renewable fuel obligation. If a refiner waives the exemption for its small refinery or its exemption as a small refiner, the refiner will be able to separate and transfer RINs like any other obligated party. If a refiner does not waive the exemption, the refiner could still separate and transfer RINs, but only for the renewable fuel that the refiner itself blends into gasoline (i.e. the refinery operates as an oxygenate blender facility). Thus, exempt small refineries and small refiners who blend ethanol can separate RINs from batches without opting in to the program in the same manner that an oxygenate blender is allowed to do.
In recent rulemakings, we have included a general hardship exemption for parties that are able to demonstrate severe economic hardship in complying with the standard. We proposed not to include provisions for a general hardship exemption in the RFS program. Unlike most other fuels programs, the RFS program includes inherent flexibility since compliance with the renewable fuels standard is based on a nationwide trading program, without any per gallon requirements, and without any requirement that the refiner or importer produce the renewable fuel. By purchasing RINs, obligated parties will be able to fulfill their renewable fuel obligation without having to make capital investments that may otherwise be necessary in order to blend renewable fuels into gasoline. We believe that sufficient RINs will be available and at reasonable prices, given that EIA projects that far greater renewable fuels will be used than required. Given the flexibility provided in the RIN trading program, including the provisions for deficit carry-over, and the fact that the standard is proportional to the volume of gasoline actually produced or imported, we continue to believe a general hardship exemption is not warranted. As a result, the final rule does not contain provisions for a general hardship exemption.
In recent rulemakings, we have included a temporary hardship exemption based on unforeseen circumstances. We proposed not to include such an exemption in the RFS program. The need for such an exemption would primarily be based on the inability to comply with the renewable fuels standard due to a natural disaster, such as a hurricane. However, in the event of a natural disaster, we believe it is likely that the volume of gasoline produced by an obligated party would also drop, which would result in a reduction in the renewable fuel requirement. We, therefore, reasoned in the NPRM that unforeseen circumstances, such as a hurricane or other natural disaster, would not result in a party's inability to obtain sufficient RINs to comply with the applicable renewable fuels standard.
We received several comments regarding the inclusion of a temporary hardship exemption based on unforeseen circumstances. One commenter believes it would be of value to have a mechanism for selectively waiving or modifying the RFS downward on a temporary basis in the event of unforeseen circumstances such as significant drought affecting potential crop production. The commenter believes that crop shortages could have an impact on a national level, or a major disaster may impact logistics of renewable fuel distribution regionally, necessitating a more rapid response from EPA than is provided in the Energy Act. Another commenter believes that a temporary hardship exemption based on unforeseen circumstances should be included in the rule since it is impossible to predict how the RFS program will impact small refiners. Another commenter believes that, given the variety of potentially challenging unforeseen events during the last several years, it is not inconceivable that man-made or natural circumstances could adversely impact the RFS program. A natural disaster in the agricultural section, for example, may make it difficult to meet the renewable fuels mandate which, in turn, could drive the price of RINs high enough to disrupt the gasoline market. The commenter believes that a mechanism built into the program from the outset would provide a more flexible and less disruptive way to address unforeseen circumstances than the more time-consuming waiver process provided in the Energy Act.
Under other EPA fuels programs, compliance is based on a demonstration that the fuel meets certain component or emissions standards. Unforeseen circumstances, such as a natural disaster, may affect an individual refiner's or importer's ability to produce or import fuel that complies with the
Most of the concerns raised by the commenters relate to problems that would have a more regional or national effect, as compared to affecting one or a few individuals. In the event that unforeseen circumstances do occur which result in a shortage of renewable fuel and available RINs, we believe that Congress provided an adequate mechanism for addressing such situations in the Energy Act.
The Act provides that, upon the petition of a noncontiguous state or U.S. territory, EPA may apply the renewable fuels requirements to gasoline produced in or imported into that noncontiguous state or U.S. territory at the same time as, or any time after the promulgation of regulations establishing the RFS program.
Today's final rule will implement this provision of the Act by providing a process whereby the governor of a noncontiguous state or territory may petition EPA to have the state or territory included in the RFS program. The petition must be received by EPA on or before November 1 for the noncontiguous state or territory to be included in the RFS program in the next calendar year. A noncontiguous state or territory for which a petition is received after November 1 would not be included in the RFS program in the next calendar year, but would be included in the RFS program in the subsequent year. For example, if EPA receives a petition on September 1, 2007, the noncontiguous state or territory would be included in the RFS program beginning on January 1, 2008. If EPA receives a petition on December 1, 2007, the noncontiguous state or territory would be included in the RFS program beginning January 1, 2009. We believe that requiring petitions to be received by November 1 is necessary to allow EPA time to make any adjustments in the applicable standard. The method for calculating the renewable fuels standard to reflect the addition of a state or territory that has opted into the RFS program is discussed in Section III.A. Because today's regulations make EPA approval of an opt-in petition automatic if it is signed by the appropriate authority and properly delivered to EPA, EPA does not envision providing an opportunity to comment on an opt-in request, although we will provide notice in the publication of the standard for the following year.
We received several comments regarding when a noncontiguous state or territory should be able to opt-in to the RFS program. One commenter supported the approach in this final rule that EPA use the EIA Short-term Energy Outlook published each October to assist in determining the percentage standard and therefore a state can only opt-in beginning with the first full compliance period of 2008. Another commenter believed we should include a provision to allow noncontiguous states or territories to opt-in to the first compliance period which starts September 1, 2007. While we see the merits of allowing a noncontiguous state or territory to opt-in to the first compliance period, we intend to maintain the current approach and allow noncontiguous states and territories to opt-in beginning with the 2008 compliance year. The statute clearly states that the program may apply to noncontiguous states and territories (that have petitioned EPA) at any time after these regulations have been promulgated. Given the short period of time between publication of the final rule and the effective date of the program, the need for a state and regulated parties to discuss opting-in with knowledge of the final version of the rule, and the requirement for EPA to notify obligated parties with sufficient lead time to any change in the standard, EPA believes 2008 is the earliest practical date for an opt-in to be effective. In addition, EPA notes that none of the noncontiguous states or territories indicated a strong interest in opting-in for the remainder of the 2007 compliance period.
Where a noncontiguous state or territory opts-in to the RFS program, producers and importers of gasoline for that state or territory will be obligated parties subject to the renewable fuel requirements. All refiners and importers who produce or import gasoline for use in a state or territory that has opted-in to the RFS program will be required to comply with the renewable fuel standard and will be able to separate RINs from batches of renewable fuels in the same manner as other obligated parties.
Once a petition to opt-in to the RFS program is approved by EPA, the state or territory would remain in the RFS program and be treated as any of the 48 contiguous states. We received a comment asserting that once a state or
The Energy Act provides that EPA, in consultation with the U.S. Department of Agriculture (USDA) and the Department of Energy (DOE), may waive the renewable fuels requirements in whole or in part upon a petition by one or more states by reducing the national quantity of renewable fuel required under the Act.
If EPA, after public notice and opportunity for comment, approves a state's petition for a waiver of the RFS program, the Act stipulates that the national quantity of renewable fuel required (Table I.B-1) may be reduced in whole or in part. This reduction could reduce the percentage standard applicable to all obligated parties. However, there is no provision in the Act that would permit EPA to reduce or eliminate any obligations under the RFS program specifically for parties located within the state that petitioned for the waiver. Thus all refiners, importers, and blenders located in the state would still be obligated parties if they produce gasoline. In addition, an approval of a state's petition for a waiver may not have any impact on renewable fuel use in that state since it would not be a prohibition on the sale or consumption of renewable fuels in that state. In fact, the Act prohibits the regulations from restricting the geographic areas in which renewable fuels may be used.
Given that state petitions for a waiver of the RFS program appear unlikely to affect renewable fuel use in that state, we have not finalized regulations providing more specificity regarding the criteria for a waiver or the ramifications of Agency approval of such a waiver in terms of the level or applicability of the standard. However, states can still submit petitions to the Agency for a waiver of the RFS requirements under the provision in the Energy Act and such petitions will be addressed by EPA on a case-by-case basis.
We received several comments objecting to the decision to not propose regulations detailing the waiver process and our rationale for not doing so. One commenter stated that nothing in the statute prevents relief from being directed toward a state which has requested the waiver by reducing the renewable fuel obligation of refiners, blenders, and importers who market gasoline in the affected state. Contrary to the commenter's assertion, the statute states that, “[t]he Administrator * * * may waive the requirements * * * by reducing the national quantity of renewable fuel required”.
Another commenter stated that EPA should publish regulations outlining specific criteria that will be considered in reviewing a petition, so that the public would have a more meaningful opportunity to participate in the process. While EPA realizes that the criteria provided by the statute are quite general, the rationales of severe environmental or economic harm or inadequate domestic supply are sufficient for a basic framework upon which a petition can be built and evaluated. Each situation in which a waiver may be requested will be unique, and promulgating a list of more specific criteria in the abstract may be counter-productive. Communication between the petitioning state(s), EPA, DOE, USDA, and public and industry stakeholders should begin early in the process, well before a waiver request is submitted. This communication will supply these federal agencies with a knowledgeable background of the situation prompting the potential waiver request. The waiver request may even prove unnecessary after an initial investigation and analysis of the situation. If not, and if the state continues to believe that a valid basis for submission of a petition exists, federal agencies can instruct the state(s) as to what more detailed information is needed for waiver approval. Petitions will be published in the
A third commenter raised the point that there is no provision in the Act that would permit EPA to waive any obligations for specific entities in a state that has petitioned for a waiver, and in the case of an emergency, such as a natural disaster, specific relief may be warranted. The commenter is correct in the observation that EPA cannot waive obligations for specific entities or locations. However, the Act does authorize EPA to waive the obligations of the program as it applies to all obligated parties, in whole or in part, depending on the severity of the situation.
Under the Act, EPA is to establish a renewable fuel standard annually, expressed as a percentage of gasoline sold or introduced into commerce, that will ensure that overall a specified total national volume of renewable fuels will be used in gasoline in the U.S. The Act does not require each obligated party to necessarily do the blending themselves in order to comply with this obligation. Rather, under the credit trading program required by the Act, each obligated party is allowed to satisfy its obligations either through its own actions or through the transfer of credits from others who have more than satisfied their individual requirements.
This section describes our final compliance program. It is based on the use of unique renewable identification numbers (RINs) assigned to batches of renewable fuel by renewable fuel producers and importers. These RINs can then be sold or traded, and ultimately used by any obligated party to demonstrate compliance with the applicable standard. Excess RINs serve the function of the credits envisioned by the Act and also provide additional benefits, as described below. We believe that our approach is consistent with the language and intent of the Act and preserves the natural market forces and blending practices that will keep renewable fuel costs to a minimum.
Once renewable fuels are produced or imported, there is very high confidence that all but de minimus quantities will in fact be blended into gasoline or otherwise used as motor vehicle fuels, except for exports. Renewable fuels are not used for food, chemicals, or as feedstocks to other production processes. In fact the denaturant that must be added to ethanol is designed specifically to ensure that the ethanol is primarily used as motor vehicle fuel. In discussions with stakeholders prior to release of the NPRM, it became clear that other renewable fuels, including biodiesel and renewable fuels used in their neat (unblended) form, likewise are not used in appreciable quantities for anything other than motor vehicle fuel. Therefore if a refiner ensures that a certain volume of renewable fuel has been produced, in effect they have also ensured that this volume will be blended into gasoline or otherwise used as a motor vehicle fuel. Focusing on production of renewable fuel as a surrogate for use of such fuel has many benefits as far as streamlining the program and minimizing the influence that the program has on the operation of the market.
In order to implement a program that is based on production of a certain volume of renewable fuels, we are finalizing a system of volume accounting and tracking of renewable fuels. We are requiring that this system be based on the assignment of unique numbers to each batch of renewable fuel. These numbers are called Renewable Identification Numbers or RINs, and are assigned to each batch by the renewable fuel producer or importer.
The use of RINs allows the Agency to measure and track renewable fuel volumes starting at the point of their production rather than at the point when they are blended into conventional fuels. Although an alternative approach would be to measure renewable fuel volumes as they are blended into conventional gasoline or diesel, measuring renewable fuel volumes at the point of production provides more accurate measurements that can be easily verified. For instance, ethanol producers are already required to report their production volumes to EIA through Monthly Oxygenate Reports. These data provide an independent source for verifying volumes. The total number of batches and parties involved are also minimized in this approach. The total number of batches is smallest at the point of production, since batches are commonly split into smaller ones as they proceed through the distribution system to the place where they are blended into conventional fuel. The number of renewable fuel producers is also far smaller than the number of blenders. Currently there just over 100 ethanol plants and 85 biodiesel plants in the U.S., compared with approximately 1200 blenders
The assignment of RINs to batches of renewable fuel at the point of their production also allows those batches to be identified according to various categories important for compliance purposes. For instance, the RIN will contain a component that specifies whether a batch of ethanol was made from cellulosic feedstocks. This RIN component will be of particular importance for 2013 and beyond when the Act specifies a national volume requirement for cellulosic biomass ethanol. The RIN will also identify the Equivalence Value of the renewable fuel which will often only be known at the point of its production. Finally, the RIN will identify the year in which the batch was produced, a critical element in determining the applicable time period within which RINs are valid for compliance purposes.
Although production volumes of renewable fuels intended for blending into gasoline are a reasonably accurate surrogate for volumes ultimately blended into gasoline, changes can occur at various times throughout the year in the volumes of renewable fuel that are in storage. These stock changes involve the temporary storage of renewable fuel during times of excess and can affect the length of time between production and ultimate use. While there may be seasonal fluctuations in stocks due to seasonal demand, these stock changes always have a net change of zero over the long term since there is no economic benefit to stockpiling renewable fuels. As a result there is no need to account for stock changes in our program.
Exports of renewable fuel represent the only significant distribution pathway that could impair the use of production as a surrogate for renewable fuel blending into gasoline or other use as a motor vehicle fuel. However, our approach accounts for exports through an explicit requirement placed upon exporters (discussed in Section III.D.4 below). As a result, we are confident that our approach satisfies the statutory obligation that our regulations impose obligations on refiners and importers that will ensure that gasoline sold or introduced into commerce in the U.S. each year will contain the volumes of renewable fuel specified in the Act. By tracking the amount of renewable fuel produced or imported and subtracting the amount exported, we will have an accurate accounting of the renewable fuel actually consumed as motor vehicle fuel in the U.S. Exports of renewable fuel are discussed in more detail in Section III.D.4.
According to the Act, we must promulgate regulations that include provisions for a credit trading program. The credit trading program allows a refiner that overcomplied with its annual RVO to generate credits representing the excess renewable fuel. The Act stipulates that those credits can then be used within the ensuing 12 month period, or transferred to another refiner that had not blended sufficient renewable fuel into its gasoline to satisfy its RVO. In this way the credit trading program permits current blending practices to continue wherein
Our RIN-based program fulfills all the functions of a credit trading program and thus meets the Act's requirements. If at the end of a compliance period a party had more RINs than it needed to show compliance with its renewable volume obligation, these excess RINs would serve the function of credits and could be used or traded in the next compliance period. RINs can be transferred to another party in an identical fashion to a credit. However, our program provides additional flexibility in that it permits all RINs to be transferred between parties before they are deemed to be in excess of a party's annual RVO at the end of the year. This is because a RIN serves two functions: It is direct evidence of compliance and, after a compliance year is over, excess RINs serve the function of credits for overcompliance. Thus the RIN approach has the advantage of allowing real-time trading without having to wait until the end of the year to determine excess.
As in other motor vehicle fuels credit programs, we are also requiring that any renewable producer that generates RINs must use an independent auditor to conduct annual reviews of the party's renewable production, RIN generation, and RIN transactions. These reviews are called “attest engagements,” because the auditor is asked to attest to the validity of the regulated party's credit transactions. For example, the reformulated gasoline program requires attest engagements for refiners and importers, and downstream oxygenate blenders to verify the underlying documentation forming the basis of the required reports (40 CFR part 80, subpart F). In the case of RIN generation, the auditor is required to verify that the number of RINs generated matched the volume of renewable fuels produced, that any extra value RINs are appropriately generated, and that RIN numbers are properly transferred with the renewable fuel as required by the regulations.
If we had not implemented a RIN-based system for uniquely identifying, measuring, and tracking batches of renewable fuel, the RFS program would necessarily require that we measure renewable fuel volumes at the point in the distribution system where they are actually blended into conventional gasoline or diesel or used in their neat form as motor vehicle fuel. The NPRM described a number of significant problems that this approach would create, including the potential for double-counting, increasing the number of parties subject to enforcement provisions, and the loss of a distinction between cellulosic ethanol and other forms of ethanol. We concluded that a blender-based approach to tracking volumes of renewable fuel was inferior to our proposed program focusing on the point of production and importation. We did not receive any comments supporting a blender-based approach and, consistent with the rationale provided in the proposed rule, have decided not to implement it.
Each RIN is generated by the producer or importer of the renewable fuel and uniquely identifies not only a specific batch, but also every gallon in that batch. The RIN consists of a 38-character code having the following form:
In response to the NPRM, one commenter requested that the full RIN generation date, not just the year, be included in the RIN. We believe that this is unnecessary and would unduly lengthen the RIN. Compliance with the standard is determined on a calendar year basis, and the year of RIN generation is necessary in order to ensure that RINs are used for compliance purposes only in the calendar year generated or the following year. See Section III.D.3.b. The full RIN generation date, while a potentially useful piece of information in the context of potential enforcement activities, is not necessary as a component of the RIN since recordkeeping requirements contain this same information and can be consulted in the enforcement context.
The company and facility IDs are assigned by the EPA as part of the registration process as described in Section IV.B. Company IDs will be used primarily to determine compliance, while the inclusion of facility IDs allows the assignment of batch numbers unique to each facility. The use of both company and facility IDs is also consistent with our approach in other fuel programs. The batch number is chosen by the producer and includes five digits to allow for facilities that produce up to a hundred thousand batches per year. In the NPRM we proposed that batch numbers be sequential values starting with 00001 at the beginning of each year. Following release of the NPRM, some stakeholders expressed the desire to be able to align RIN batch numbers with numbers used in other aspects of their business. As a result, we have determined that the requirement that the batch numbers be sequential is not necessary so long as each batch number is unique within a given calendar year. Batches are described more fully in Section III.E.1.a.
The RR, D, and K codes together describe the nature of the renewable fuel and the RINs that are generated to represent it. The RR code simply represents the Equivalence Value for the renewable fuel, multiplied by 10 to eliminate the decimal place inherent in Equivalence Values. Equivalence Values form the basis for the total number of RINs that can be generated for a given volume of renewable fuel, and are described in Section III.B.4.
The D code identifies cellulosic biomass ethanol batches as such. Since the Act requires that a minimum of 250 million gallons of cellulosic biomass ethanol be consumed starting in 2013, obligated parties will need to be able to distinguish RINs representing cellulosic biomass ethanol from RINs representing other types of renewable fuel. This requirement is discussed in more detail in Section III.A.
In the NPRM, the K code served to distinguish between standard-value RINs and extra-value RINs, and it was placed in the middle of the RIN. As described more fully in Section III.E.1.a, our final rule eliminates the need for a distinction between standard-value RINs and extra-value RINs, but requires a distinction between RINs that must be transferred with a volume of renewable fuel (assigned RINs) and RINs that can be transferred without renewable fuel (separated RINs). Thus for the final rule we have changed the purpose of the K code. As described in Section III.E.2, we are requiring that RINs separated from volumes of renewable fuel be identified as such, by changing the K code from a value of 1 to a value of 2. Placing the K code at the beginning of the RIN
The RIN also contains two codes SSSSSSSS and EEEEEEEE that together identify the “RIN block” which demarcates the number of gallons of renewable fuel that the batch represents in the context of compliance. Depending on the Equivalence Value, this may not necessarily be the same as the actual number of gallons in the batch. The methodology for designating the SSSSSSSS and EEEEEEEE values is described in Section III.D.2.b below.
In the NPRM we assigned six digits to the RIN block codes to allow batches up to a million gallons in size. Based on comments received, we have decided to expand the number of digits to eight to accommodate batches up to 100 million gallons in size. Although it is highly unlikely that a single tank would hold this volume, we are adding a definition of “batch” to our final regulations that would allow this high volume to be counted as a single batch for the purposes of generating RINs.
In the NPRM we pointed out that “RIN” can refer to either the number representing an entire batch or the number representing one gallon of renewable fuel in the context of compliance. In order to make the distinction clear, we are defining the latter as a gallon-RIN, and a batch-RIN will represent multiple gallon-RINs. In the case of a gallon-RIN, the values of SSSSSSSS and EEEEEEEE will be identical. A batch-RIN, on the other hand, will generally have different values for SSSSSSSS and EEEEEEEE, representing the starting and ending values of a batch of renewable fuel. Examples of RINs are presented in the next section.
As described in Section III.E.1.a, we have eliminated the distinction between standard-value RINs and extra-value RINs for this final rule. Instead, all gallon-RINs must be assigned to batches of renewable fuel by the producer or importer. Consistent with the NPRM, each gallon-RIN will continue to represent one gallon of renewable fuel in the context of compliance.
Also consistent with the NPRM, we are requiring that RIN generation begin at the same time that the renewable fuel standard becomes applicable to obligated parties. Thus RINs must be generated for all renewable fuel produced or imported on or after September 1, 2007. Since many producers and importers will have renewable fuel in inventory at the start of the program that was produced prior to September 1, 2007, we are also allowing them to generate RINs for such renewable fuel. This provision ensures that every gallon that a producer or importer sells starting on September 1, 2007 can have an assigned RIN, and obligated parties that take ownership of renewable fuel directly from a producer or importer will have greater assurance of having access to RINs at the start of the program. Other volumes of ethanol in inventory in the distribution system on September 1, 2007 will continue to be sold and distributed without RINs.
In order to determine the number of gallon-RINs that must be generated and assigned to a batch by a producer or importer, the actual volume of the batch must be multiplied by the Equivalence Value to determine an applicable “RIN volume”:
When RINs are first assigned to a batch of renewable fuel by its producer or importer, the RIN block start for that batch will in general be 1 (i.e., SSSSSSSS will have a value of 00000001). The RIN block end value EEEEEEEE will be equal to the RIN volume calculated above. The batch-RIN then represents all the gallon-RINs assigned to the batch. Table III.D.2.b-1 provides some examples of the number of gallon-RINs that would be assigned to a batch under different circumstances.
The
In response to the NPRM, some obligated parties requested that fractional RINs be used for cases in which the Equivalence Value is less than 1.0. Under this approach, every gallon in a batch would still have an assigned gallon-RIN, but those gallon-RINs would represent only a fraction of a gallon for compliance purposes. The commenters also argued that our proposed system in which RINs are assigned to only a portion of a batch would be unworkable given the need to ensure that RINs remain assigned to batches as they travel through the distribution system.
We continue to believe that the most straightforward system calculates the number of gallon-RINs representing a batch as the product of the Equivalence Value and the actual volume of the batch. Then every gallon-RIN will have the capability of covering one gallon of an obligated party's RVO, and thus every gallon-RIN has the same value. This is true both for renewable fuels with Equivalence Values less than 1.0, and renewable fuels with Equivalence Values greater than 1.0. Also, as described in Section III.E.1, we have modified our approach to the distribution of RINs assigned to volumes of renewable fuel. As a result, the batch-splitting and batch-merging protocols have become largely irrelevant, and thus the transfer of renewable fuels having an
Following release of the NPRM, we also identified some cases in which the generation of RINs for a partially renewable fuel or blending component would result in double-counting of RINs generated. For instance, ethyl tertiary butyl ether (ETBE) is made from combining ethanol with isobutylene. The ethanol is generally from corn, and the isobutylene is generally from petroleum. The ETBE producer may purchase ethanol from another source, and that ethanol may already have RINs assigned to it. In such cases it would not be appropriate for the ETBE producer to generate additional RINs for the ETBE made from that ethanol. Even if the ETBE producer purchased ethanol without assigned RINs, our program design ensures that either RINs were generated for the ethanol and separated prior to purchase by the ETBE producer, or RINs were legitimately not assigned to the ethanol. The NPRM did not address the potential for generating RINs twice for the same renewable fuel in these cases. Therefore, we are finalizing a provision prohibiting a party from generating RINs for a partially renewable fuel or blending component that it produces if the renewable feedstock used to make the renewable fuel or blending component was acquired from another party. Any RINs acquired with the renewable feedstock (e.g. ethanol) must be assigned to the product made from that feedstock (e.g. ETBE). This approach is consistent with comments submitted by Lyondell Chemical Company.
Although in general every batch of renewable fuel produced or imported must have an assigned batch-RIN, there are several cases in which a RIN may not be assigned to a batch by a producer or importer. For instance, if the renewable fuel was consumed within the confines of the production facility where it was made, it would not be acquired by either an obligated party or a gasoline blender. In such cases, the RIN could not be separated from the batch and transferred separately since producers do not have this right. A RIN is assigned to renewable fuel when ownership of the renewable fuel is transferred to another party. Since no such transfer would occur in this case, no RIN should be generated.
A second case in which some renewable fuel would not have an assigned RIN would occur for small volume producers. We are allowing renewable fuel producers who produce less than 10,000 gallons in a year to avoid the requirement to generate RINs and assign them to batches. Such producers would not contribute meaningfully to the nationwide pool of renewable fuel, and we do not believe that the very small business operations involved should be subject to the burden of recordkeeping and reporting. Although two commenters disagreed that these small volume producers should be exempt from the requirement to generate RINs, they did not provide compelling evidence that the exemption would create a problem in the distribution system or provide an unfair advantage to small producers. As a result we are finalizing this provision as proposed. Note that if a small producer chooses to register as a renewable fuel producer under the RFS program, they will be subject to all the regulatory provisions that apply to all producers, including the requirement to assign RINs to batches.
In the NPRM we proposed that a renewable fuel producer which also operated as an exporter would not be required to generate and assign a RIN to any renewable fuel that it produced and exported. However, one commenter pointed out that this approach could lead to confusion regarding which gallons should have an assigned RIN and which should not, given the complex nature of tracking volumes of renewable fuel. As a result we have determined that this provision should be eliminated. Our final regulations require that producers assign RINs to all renewable fuel, regardless of whether it is exported. Exports of renewable fuel are discussed further in Section III.D.4.
Under our program, RINs form the basis of the volume accounting and tracking system that allows each obligated party to demonstrate that they have met their renewable fuel obligation each year. This section describes how the compliance process using RINs works. Our approach to the distribution and trading of RINs is covered separately in Section III.E below.
Under our program, each obligated party must determine its Renewable Volume Obligation (RVO) based on the applicable percentage standard and its annual gasoline volume as described in Section III.A.4. The RVO represents the volume of renewable fuel that the obligated party must ensure is used in the U.S. in a given calendar year. Since the nationwide renewable fuel volumes shown in Table I.B-1 are required by the Act to be consumed in whole calendar years, each obligated party must likewise calculate its RVO on an annual basis.
Since our program uses RINs as a measure of the amount of renewable fuel used as motor vehicle fuel that is sold or introduced into commerce within the U.S., obligated parties must meet their RVO through the accumulation of RINs. In so doing, they will effectively be causing the renewable fuel represented by the RINs to be consumed as motor vehicle fuel. Obligated parties are not required to physically blend the renewable fuel into gasoline or diesel fuel themselves. The accumulation of RINs is the means through which each obligated party shows compliance with its RVO and thus with the renewable fuel standard.
For each calendar year, each obligated party is required to submit a report to the Agency documenting the RINs it acquired and showing that the sum of all gallon-RINs acquired is equal to or greater than its RVO. This reporting is discussed in more detail in Section IV. In the context of demonstrating compliance, all gallon-RINs have the same compliance value. The Agency can then verify that the RINs used for compliance purposes are valid by simply comparing RINs reported by producers to RINs claimed by obligated parties. We can also verify simply that any given gallon-RIN was not double-counted, i.e., used by more than one obligated party for compliance purposes. In order to be able to identify the cause of any double-counting, however, additional information is needed on RIN transactions as discussed in Section IV.
If an obligated party has acquired more RINs than it needs to meet its RVO, then in general it can retain the excess RINs for use in complying with its RVO in the following year or transfer the excess RINs to another party. The conditions under which this is allowed are determined by the valid life of a RIN, described in more detail in Section III.D.3.b below. If, alternatively, an obligated party has not acquired sufficient RINs to meet its RVO, then under certain conditions it can carry a deficit into the next year. Deficit carryovers are discussed in more detail in Section III.D.3.d.
The regulations prohibit any party from creating or transferring invalid RINs. Invalid RINs cannot be used in demonstrating compliance regardless of
As in other motor vehicle fuel credit programs, the regulations address the consequences if an obligated party is found to have used invalid RINs to demonstrate compliance with its RVO. In this situation, the refiner or importer that used the invalid RINs will be required to deduct any invalid RINs from its compliance calculations. The refiner or importer will be liable for violating the standard if the remaining number of valid RINs is insufficient to meet its RVO, and the obligated party may be subject to additional monetary penalties if it used invalid RINs in its compliance demonstration. See Section V of this preamble for further discussion regarding liability for use of invalid RINs.
Just as for RIN generators, we are also requiring that obligated parties conduct attest engagements for the volume of gasoline they produce and the number of RINs procured to ensure compliance with their RVO. In most cases, this should amount to little more than is already required under existing EPA gasoline regulations. In the case of renewable fuel exporters, the attest engagement will verify the volume of renewable fuel exported and therefore the magnitude of their RVO. Attest engagement reports must be submitted to the party that commissioned the engagement and to EPA. See Section IV of this preamble for further discussion of the attest engagement requirements.
The Act requires that renewable fuel credits be valid for showing compliance for 12 months as of the date of generation. This section describes our interpretation of this provision in the context of our program wherein excess RINs fulfill the Act's requirements regarding credits.
As discussed in Section III.D.1.a, we interpret the Act such that credits would represent renewable fuel volumes in excess of what an obligated party needs to meet their annual compliance obligation. Given that the renewable fuel standard is an annual standard, obligated parties will determine compliance shortly after the end of the year, and credits would be identified at that time. Obligated parties will typically demonstrate compliance by submitting a compliance demonstration to EPA. Given the 12-month life of a credit as stated in the Act, we interpret this provision as meaning that credits would only be valid for compliance purposes for the following compliance year. Hence if a refiner or importer overcomplied with their 2007 obligation they would generate credits that could be used to show compliance with the 2008 compliance obligation, but the credits could not be used to show compliance for later years. Since RINs fulfill the role of credits, the statutory provisions regarding credits apply to RINs
The Act's limit on credit life helps balance the risks between the needs of renewable fuel producers and obligated parties. Producers are currently making investments in expanded production capacity on the expectation of a statutorily guaranteed minimum quantity demanded. Under the market conditions we are experiencing today that make ethanol use more economically attractive, the annual volume requirements in the RFS program will not drive consumption of renewable fuels. However, if the price of crude oil dropped significantly or the use of ethanol in gasoline became otherwise less economically attractive, obligated parties could use stockpiled credits to comply with the program requirements. As a result, demand for renewable fuel could fall well below the RFS program requirements, and many producers could end up with a stranded investment. The 12 month valid life limit for credits minimizes the potential for this type of result.
For obligated parties, the Act's 12 month valid life for credits provides a window within which parties who do not meet their renewable fuel obligation through their own physical use of renewable fuel can obtain credits from other parties who have excess. This critical aspect of the trading system allows the renewable fuels market to continue operating according to natural market forces, avoiding the possibility that every single refiner would need to purchase renewable fuel for blending into its own gasoline. But the 12 month life also provides a window within which banking and trading can be used to offset the negative effects of fluctuations in either supply of or demand for renewable fuels. For instance, if crude oil prices were to drop significantly and natural market demand for ethanol likewise fell, the RFS program would normally bring demand back up to the minimum required volumes shown in Table I.B-1. But in this circumstance, the use of ethanol in gasoline would be less economically attractive, since demand for ethanol would not be following price but rather the statutorily required minimum volumes. As a result, the price of credits as represented by RINs, and thus ethanol blends, could rise above the levels that would exist if no minimum required volumes existed. The 12 month valid life creates some flexibility in the market to help mitigate price fluctuations. The renewable fuels market could also experience a significant drop in supply if, for instance, a drought were to limit the production of the feedstocks needed to produce renewable fuel. Obligated parties could use banked credits to comply rather than carry a deficit into the next year.
In the context of our RIN-based program, we have been able to accomplish the same objective as the Act's 12 month life of credits by allowing RINs to be used to show compliance for the year in which the renewable fuel was produced and its associated RIN first generated or for the following year. RINs not used for compliance purposes in the year in which they were generated will by definition be in excess of the RINs an obligated party needed in that year, making excess RINs equivalent to the credits referred to in the Energy Act. Excess RINs are valid for compliance purposes in the year following the one in which they initially came into existence.
Thus we are requiring that every RIN be valid for the calendar-year compliance period in which it was generated or the following year. If a RIN was created in one year but was not used by an obligated party to meet its RVO for that year, the RIN can be used for compliance purposes in the next year (subject to certain provisions to address RIN rollover as discussed below). If, however, a RIN was created in one year and was not used for compliance purposes in that year or in the next year, it will expire. In response to the NPRM, this approach was supported by a number of obligated parties and their representative associations. These commenters agreed that allowing RINs to be used for the year generated or the following year was not only supported by the statutory language, but was also an element of program flexibility that would be critical for offsetting the negative effects of potential fluctuations in either supply of or demand for renewable fuels.
However, in response to our NPRM, other commenters said that the Energy Act's 12-month credit life provision should be interpreted as applying retrospectively, not prospectively. Under this approach, the 12-month timeframe in the Act would be interpreted to refer to the full calendar year within which a credit was generated. Under this alternative approach no RINs could be used for compliance purposes beyond the calendar year in which they originally came into existence. As discussed below, we do not believe that this approach is appropriate.
Commenters who supported the retrospective approach to the Act's 12-month credit life provision argued that the Energy Act could have been written to explicitly allow a valid life of multiple years if that had been Congress' intent. In response, the Act explicitly indicates that obligated parties may either use the credits they have generated or transfer them. For a party to be able to use credits generated, such credit use must necessarily occur in a compliance year other than the one in which the credit was generated. Thus we do not believe that a retrospective approach to the Act's 12-month credit life provision is consistent with the explicit credit provisions of the Act. In addition, we believe that an interpretation leading to a valid life of one year after the year in which the RIN was generated is most consistent with the program as a whole. In comparison to a single-year valid life for RINs, our approach provides some additional compliance flexibility to obligated parties as they make efforts to acquire sufficient RINs to meet their RVOs each year. This flexibility will have the effect of keeping fuel costs lower than they would otherwise be.
In the comments we received on the NPRM, one objection to our proposed approach was that the use of RINs generated in one compliance period to satisfy obligations in a subsequent compliance period could result in less renewable fuel used in a given year than is set forth in the statute. While this is true, we believe this approach is most consistent with the Act, as described above. The Act clearly set up a credit program with a credit life, meaning Congress intended parties to use credits in some cases instead of blending renewable fuel. The Act is best read to harmonize all of its provisions. In addition, we note that other provisions of the Act may lead to less renewable fuel use in a given year than the statutorily-prescribed volumes, but Congress adopted them and intended that they could be used. For instance, the deficit carryover provision allows any obligated party to fail to meet its RVO in one year if it meets the deficit and its RVO in the next year. If several obligated parties took advantage of this provision, it could result in the nationwide total volume obligation for a particular calendar year not being met. In a similar fashion, the statutory requirement that every gallon of cellulosic biomass ethanol be treated as 2.5 gallons for the purposes of compliance means that the annually required volumes of renewable fuel could be met in part by virtual, rather than actual, volumes. Finally, the calculation of the renewable fuel standard is based on projected nationwide gasoline volumes provided by EIA (see Section III.A). If the projected gasoline volume falls short of the actual gasoline volume in a given year, the standard will fail to create the demand for the full renewable fuel volume required by the Act for that year. The Act contains no provision for correcting for underestimated gasoline volumes. Additional responses to the issues raised by commenters on RIN life can be found in the S&A document.
As described in Section III.D.3.b above, RINs are valid for compliance purposes for the calendar year in which they are generated or the following year. We believe that this approach is most consistent with the Act's prescription that credits be valid for compliance purposes for 12 months as of the date of generation. Our approach is intended to address both the risk taken by producers expecting a guaranteed demand to cover their expanded production capacity investments and the risk taken by obligated parties who need a guaranteed supply in order to meet their regulatory obligations under this program.
However, the use of previous year RINs to meet current year compliance obligations does create an opportunity for effectively circumventing the valid life limit for RINs. This can occur in situations wherein the total number of RINs generated each year for a number of years in a row exceeds the number of RINs required under the RFS program for those years. The excess RINs generated in one year could be used to show compliance in the next year, leading to the generation of new excess RINs in the next year, causing the total number of excess RINs in the market to accumulate over multiple years despite the limit on RIN life. The NPRM included examples of how this “rollover” might occur. The rollover issue would in some circumstances essentially make the applicable valid life for RINs virtually meaningless in practice.
RIN rollover also undermines the ability of a limit on credit life to guarantee a market for renewable fuels. As described in Section III.D.3.b, if the natural market demand for ethanol was higher than the volumes required under the RFS program for several years in a row, as may occur in practice, obligated parties could amass RINs that, in the extreme, could be used entirely in lieu of actually demanding ethanol in some subsequent year.
As described in the NPRM, we believe that the rollover issue must be addressed. The Act's provision regarding the valid life of credits is clearly intended to obtain the benefits associated with a limited credit life. Any program structure in which some RINs effectively have an infinite life, regardless of the technical life of individual RINs, does not appropriately achieve the benefits expected from the Act's provision regarding the 12-month life of credits. The authority to establish a credit program and to implement a limited life for credits includes the authority to limit actions that have the practical effect of circumventing this limited credit life.
To be consistent with the Act, we believe that the rollover issue should be addressed in our regulations. However, we also believe that the limits to preclude such unhindered rollovers should not preclude all previous-year RINs from being used for current-year compliance. To accomplish this, we must restrict the number of previous-year RINs that can be used for current year compliance. To this end, we proposed a 20 percent cap on the amount of an obligated party's Renewable Volume Obligation (RVO) that can be met using previous-year RINs. After review of the comments we received on the NPRM, we have decided to finalize this provision. Thus each obligated party will be required to use current-year RINs to meet at least 80 percent of its RVO, with a maximum of 20 percent being derived from previous-year RINs. Any previous-year RINs that an obligated party may have that are in excess of the 20 percent cap can be traded to other obligated parties that need them. If the previous-year RINs in excess of the 20 percent cap are not used by any obligated party for compliance, they will expire. The net result will be that, for the market as a whole, no more than 20 percent of a given year's renewable fuel standard can be met with RINs from the previous year.
As described in the NPRM, we believe that the 20 percent cap provides the
Some NPRM commenters did not perceive a problem with the RIN rollover issue and argued for no rollover cap or at least for a more flexible one. They pointed to the need for maximum flexibility in responding to fluctuations in the market, and they were primarily concerned about potential supply problems. For instance, if a drought were to reduce the availability of corn for ethanol production, there may simply not be sufficient RINs available for compliance purposes. A drought situation actually occurred in 1996, and as a result 1996 ethanol production was 21% less than it had been in 1995. In 1997, production had not yet returned to the 1995 levels. Moreover, there is no guarantee that future droughts, should they occur, would result in a reduction in ethanol production of only 21 percent. As a result, in the NPRM we requested comment on whether a higher cap, such as 30 percent, would be more appropriate. A number of refiners and refinery associations commented that 30 percent would indeed provide them with the additional flexibility they would need in the case of a significant market disruption. Some requested a cap of 40 percent or even no cap at all. These parties also expressed concern that, although the Agency has the authority to waive the required renewable fuel volumes in whole or in part in the event of inadequate domestic supply, this can occur only on petition by one or more states and then only after consultation with both the Department of Agriculture and the Department of Energy. Some obligated parties expressed concern that such a waiver would not occur in a timely fashion. The availability of excess previous-year RINs would thus provide compliance certainty in the event that the supply of current-year RINs falls below the RFS program requirements and the Agency does not waive any portion of the program requirements.
In contrast to obligated parties, renewable fuel producers provided comments on the NPRM indicating that 10 percent would be more appropriate. They argued that a 10 percent cap was closer to their preferred approach to RIN life in which the Act's 12-month life of a credit is interpreted as allowing RINs to be used for compliance purposes only in the year in which they are generated.
We continue to believe that a cap set at 20 percent is appropriate, and the comments submitted in response to the NPRM did not provide compelling evidence to the contrary. The level of 20 percent is consistent with past ethanol market fluctuations. As described above, the largest single-year drop in ethanol supply occurred in 1996 and resulted in 21% less ethanol being produced than in 1995. While future supply shortfalls may be larger or smaller, the circumstances of 1996 provide one example of their potential magnitude.
We believe that a cap of 20 percent is a reasonable way to limit RIN rollover and provide some assurances to renewable fuel producers regarding demand for renewable fuel. A cap of 20 percent also ensures that many previous-year RINs can still be used for current year compliance, providing some flexibility in the event of market disruptions.
Given the competing needs expressed by renewable fuel producers and refiners, a rollover cap of 20 percent also balances the risk taken by producers of renewable fuels expecting a guaranteed quantity demanded to cover their production capacity investments and the risk taken by obligated parties who need a guaranteed supply in order to meet their regulatory obligations under this program. We are therefore finalizing a rollover cap of 20 percent.
In the NPRM we also considered an alternative approach whereby we would set the cap annually based on the actual excess renewable fuel production. We did not propose this approach, and commenters did not support it. We have determined that fixing the cap at 20 percent both provides certainty to the RIN market and ensures that some minimum level of flexibility exists for individual obligated parties even in a market without excess RINs.
We also requested comment on whether the Agency should adopt a provision allowing the cap to be raised in the event that supply shortfalls overwhelmed the 20 percent cap. Under this conditional provision, the Agency would monitor standard indicators of agricultural production and renewable fuel supply to determine if sufficient volumes of renewable can be produced to meet the RFS program requirements in a given year. Prior to the end of a compliance period, if the Agency determined that a supply shortfall was imminent, it could raise the cap to permit a greater number of previous-year RINs to be used for current-year compliance. Although this approach would not change the required volumes, it could create some additional temporary flexibility. However, we did not propose this provision, and commenters did not address it. We do not believe it is necessary, and thus we have not finalized it.
Finally, the cap is designed to prevent the rollover of RINs generated two years ago from being used for compliance purposes in the current year. No RINs were generated in 2006 when the default standard of 2.78 percent was in effect on a collective basis, so the first year in which RINs will be generated is 2007. Consequently, the first year in which there could be rollover would be 2009. Therefore, we proposed that the cap would not be effective until compliance year 2009. Two commenters pointed out that this approach could under some scenarios lead to a situation in which more than 20 percent of the RINs used for compliance purposes in 2008 were actually generated in the previous year, 2007. EPA believes that implementing the rollover cap in 2008 would, indeed, prevent the initiation of an excess buildup of past RINs. In addition, it would simplify the regulations, since there would be no need for an exception from the RIN cap for 2008. Consequently we are finalizing the 20 percent cap to apply to all years, including 2008.
The Energy Act also contains a provision allowing an obligated party to carry a deficit forward from one year into the next if it cannot comply with its RVO. However, deficits cannot be carried over two years in a row.
Deficit carryovers are measured in gallons of renewable fuel, just as for RINs and RVOs. If an obligated party does not acquire sufficient RINs to meet its RVO in a given year, the deficit is calculated by subtracting the total number of RINs an obligated party has acquired from its RVO. There are no volume penalties, discounts, or other factors included when calculating a
If an obligated party does not acquire sufficient RINs to meet its RVO in year i-1, the obligated party must procure sufficient RINs to cover the full RVO for year i including the deficit. There are no provisions allowing for another year of carryover. If the obligated party does not acquire sufficient RINs to meet its RVO for that year plus the deficit carryover from the previous year, it will be in noncompliance.
The Act indicates that deficit carryovers are to occur due to “inability” to generate or purchase sufficient credits. We believe that obligated parties will make a determined effort to satisfy their RVO on an annual basis and that a deficit will demonstrate that they were unable to do so. Thus, we did not propose that any particular demonstration of “inability” be a prerequisite to the ability of obligated parties to carry deficits forward. However, one commenter requested that we should establish some sort of standard or threshold that obligated parties must meet before they would be allowed to use the deficit carryover provision. Although the commenter provided no suggestions regarding how such a threshold could be established, he indicated that in the absence of such a threshold obligated parties could potentially use the deficit carryover provision to undermine the amount of actual renewable fuel used in a given year.
We agree that the deficit carryover provision could result in less renewable fuel being consumed in a given year than is required by the Act, especially if several obligated parties took advantage of it at the same time. However, in any given year some parties may be making up deficits from a prior year, while other parties might be generating deficits. This fact will tend to reduce the net effect in any given year, and regardless, the deficit in demand in one year will by regulatory requirement be made up in the following year. Finally, any threshold we could set to demonstrate an obligated party's inability to generate or purchase sufficient credits would likely require a comprehensive investigation of their opportunities to acquire RINs. Such investigations would consume Agency resources that would be better spent, in terms of ensuring that the goals of the Act are met, on other compliance enforcement matters. Therefore, we have not set any thresholds in the final rule.
As described in Section III.D.2.a, we believe that U.S. consumption of renewable fuel as motor vehicle fuel can be measured with considerable accuracy through the tracking of renewable fuel production and importing records. This is the basis for our RIN-based system of compliance. However, exports of renewable fuel must be accounted for under this approach. For instance, if a gallon of ethanol is produced in the U.S. but consumed outside of the U.S., the RIN associated with that gallon is not valid for RFS compliance purposes since the RFS program is intended to require a specific volume of renewable fuel to be consumed in the U.S. Exports of renewable fuel currently represent about 5 percent of U.S. production, though the exact value varies each year.
To ensure that renewable fuels exported from the U.S. cannot be used by an obligated party for RFS compliance purposes, the RINs associated with that exported renewable fuel must be removed from circulation. For this final rule we have concluded that it should be the exporter's responsibility to account for exported renewable fuel in our RIN-based program. We are therefore requiring that an RVO be assigned to each exporter that is equal to the annual volume of renewable fuel it exported. Just as for obligated parties, then, the exporter is required to acquire sufficient gallon-RINs to meet its RVO. If the exporter purchases renewable fuel directly from a producer, that renewable fuel will come with associated gallon-RINs which can then be applied to its RVO under our program. In this circumstance, the exporter will not need to acquire RINs from any other source. If, however, the exporter receives renewable fuel without the associated RINs, it will need to acquire RINs from some other source in order to meet its RVO.
In the NPRM we presented an alternative approach which would have increased the obligation placed on refiners and importers of gasoline based on the volume of renewable fuel exported. One commenter supported this alternative approach, explaining that the proposed approach of requiring the exporter to acquire sufficient RINs to offset an RVO equal to the exported volume would place a significant recordkeeping burden on exporters. This commenter also expressed concern that exporters would receive no value in return for compliance with an RVO. We do not believe that these are compelling reasons to place the burden for exported renewable fuel on obligated parties. Not only would this alternative approach have required an estimate of the volume of renewable fuel exported in the next year, but would also mean that every obligated party would share in accumulating RINs to cover the activities of other parties not under their control.
In the NPRM we pointed out that in specific circumstances involving exports of renewable fuels, the need for RINs might not be necessary. For instance, if the exporter was wholly owned by a renewable fuel producer, there would be no need to generate RINs for the exported product. We therefore proposed to allow exported product to be excluded from the exporter's RVO if the exporter was also the producer and no RINs were generated for that product. However, one commenter pointed out that this approach could lead to confusion regarding which gallons should have an assigned RIN and which should not, given the complex nature of tracking volumes of renewable fuel. As a result we have determined that this provision should be eliminated. Our final regulations require producers to assign RINs to all renewable fuel, regardless of whether it is exported. In this case the renewable producer would merely use these RINs to cover its obligation as an exporter.
As described in Section III.D.2, there are cases in which there is not a one-to-one correspondence between gallons in a batch of renewable fuel and the gallon-RINs generated for that batch. If the RVO assigned to the exporter were based strictly on the actual volume of the exported product, it would not necessarily capture all the gallon-RINs which were generated for that exported volume. Thus we are requiring that the RVO assigned to an exporter be based not on the actual volume of renewable fuel exported, but rather on a volume adjusted by the Equivalence Value assigned to each batch. The Equivalence Value is represented by the RR code within the RIN as described in Section III.D.2.a. Thus the exporter must multiply the actual volume of a batch by
In cases wherein an exporter obtains a batch of renewable fuel whose RIN has already been separated by an obligated party or blender, the exporter may not know the Equivalence Value. We are requiring that for such cases the exporter use the equivalence value applicable to that type of renewable fuel (e.g., 1.5 for biodiesel). However, in the case of ethanol, the same product could have been produced as corn ethanol or cellulosic ethanol. Thus, in the case of ethanol, if the exporter does not know the equivalence value we are requiring that the exporter use the actual volume of the batch to calculate its RVO. This will introduce some small error into the calculation of the RVO for cases in which the ethanol had in fact been assigned an Equivalence Value of 2.5. However, we believe that the potential impact of this on the overall program will be exceedingly small.
The primary means through which the Agency will verify an obligated party's compliance with its RVO will be the annual compliance demonstration reports. These reports will include a variety of information required for compliance and enforcement, including the demonstration of compliance with the previous calendar year's RVO, a list of all transactions involving RINs, and the tabulation of the total number of RINs owned, used for compliance, transferred, retired and expired. Reporting requirements for obligated and non-obligated parties are covered in detail in Section IV.
In its annual reports, an obligated party will be required to include a list of all RINs held as of the reporting date, divided into a number of categories. For instance, a distinction must be made between current-year RINs and previous-year RINs as follows:
The report must also indicate which RINs have been used for compliance with the RVO including any potential deficit, which current-year RINs have not been used for compliance and are therefore valid for compliance the next year, and which previous-year RINs have not been used for compliance and therefore expire. The report must also include a demonstration that the obligated party had not exceeded the 20 percent cap to address RIN rollover, as described in Section III.D.3.c.
In order to verify compliance for each obligated party, the primary Agency activity will involve the validation of RINs. The Agency will perform the following four basic elements of RIN validation:
(1) RINs used by an obligated party to comply with its RVO will be checked to ensure that they are within their two-year valid life. The RIN itself will contain the year of generation, so this check involves only an examination of the listed RINs.
(2) All RINs owned by an obligated party will be cross-checked with reports from renewable fuel producers to verify that each RIN had in fact been generated.
(3) All RINs used by an obligated party for compliance purposes will be cross-checked with annual reports from other obligated parties to ensure that no two parties used the same RIN to comply.
(4) Previous-year RINs used for compliance purposes will be checked to ensure that they do not exceed 20 percent of the obligated party's RVO.
In cases where a RIN is highlighted under suspicion of being invalid, the Agency will then need to take additional steps to resolve the issue. In general this will involve a review of RIN transfer records submitted quarterly to the Agency by all parties in the distribution system that held the RINs. RIN transfers will be recorded through EPA's Central Data Exchange as described in Section IV. These RIN transfer records will permit the Agency to identify all transaction(s) involving the RINs in question. The Agency can then contact liable parties and take appropriate steps to formally invalidate a RIN improperly claimed by a particular party. Additional details of the liabilities and prohibitions attributed to parties in the distribution system are discussed in Section V.
Under our final program structure, a Renewable Identification Number (RIN) must (with certain exceptions) be generated for all renewable fuel produced or imported into the U.S., and RINs must be acquired by obligated parties for use in demonstrating compliance with the RFS requirements. However, as described in the NPRM, there are a variety of ways in which RINs could theoretically be transferred from the point of generation by renewable fuel producers to the obligated parties that need them.
EPA's final program was developed in light of the somewhat unique aspects of the RFS program. As discussed earlier, under this program the refiners and importers of gasoline are the parties obligated to comply with the renewable fuel requirements. At the same time, refiners and importers do not generally produce or blend renewable fuels at their facilities and so are dependent on the actions of others for the means of compliance. Unlike EPA's other fuel programs, the actions needed for compliance largely center on the production, distribution, and use of a product by parties other than refiners and importers. In this context, we believe that the RIN transfer mechanism should focus primarily on facilitating compliance by refiners and importers and doing so in a way that imposes minimum burden on other parties and minimum disruption of current mechanisms for distribution of renewable fuels.
Our final program does this by relying on the current market structure for ethanol distribution and use and avoiding the need for creation of new mechanisms for RIN distribution that are separate and apart from this current structure. Our program basically requires RINs to be transferred with renewable fuel until the point at which the renewable fuel is purchased by an obligated party or is blended into gasoline or diesel fuel by a blender. This approach allows the RIN to be incorporated into the current market structure for sale and distribution of renewable fuel, and avoids requiring refiners to develop and use wholly new market mechanisms. While the development of new market mechanisms to distribute RINs is not precluded under our program, it is also not required.
In the NPRM the Agency also evaluated several options for distributing RINs other than the option incorporated into today's rule. We are not finalizing these alternatives because they tend to require the development of new market mechanisms, as compared to relying on the current market structure for distribution of ethanol, and they are less focused on facilitating compliance for the obligated parties.
We are requiring that RINs be transferred with volumes of renewable fuel as they move through the distribution system, until ownership of those volumes is assumed by an obligated party, exporter, or a party that converts the renewable fuel into motor vehicle fuel. At such time, RINs can be
The initial generation of RINs and their assignment to batches of renewable fuel will be the sole responsibility of renewable fuel producers and renewable fuel importers. As described in Section III.D.1, volumes of renewable fuel can be measured most accurately and be more readily verified at these originating locations.
The final rule defines a batch of renewable fuel as a volume that has been assigned a unique batch-RIN. This simple and flexible definition of a batch allows renewable fuel producers and importers to construct each batch-RIN based on the particular circumstances associated with the batch. In this context, a batch is not confined to the volume that can be held in a tank, but instead can include a significantly larger volume. However, we are placing two limits on the volumes of renewable fuel that are identified as a single batch. First, the RIN contains only enough digits to permit the assignment of 99,999,999 gallon-RINs to a single batch. For corn-ethanol with an Equivalence Value of 1.0, this means that a single batch can be comprised of up to 99,999,999 gallons of ethanol. In contrast, for biodiesel with an Equivalence Value of 1.5, a single batch can contain up to 66,666,666 gallons of biodiesel. Second, in order to provide more clarity in the event that an investigation of a party's volume and RIN generation records is conducted, we are also limiting a batch to the maximum volume that is produced or imported by the renewable fuel producer or importer within a calendar month. Within these two limits, producers and importers can define batches of renewable fuel according to their own discretion and practices, including using individual tankfulls to represent each batch. These parties must designate a unique serial number for each batch (RIN code BBBBB) and specify its Equivalence Value. The batch-RIN will identify all the gallon-RINs assigned to the batch. See Section III.D.2.a for details on the format for RINs.
In the NPRM, we proposed different approaches to the assignment of standard-value RINs and extra-value RINs. Under the proposal, extra-value RINs could be generated by the renewable fuel producer in cases where the renewable fuel in question had an Equivalence Value greater than 1.0. We proposed that all standard-value RINs must be assigned to volumes of renewable fuel, but that producers should have the option of whether to assign extra-value RINs to batches. We took this approach in part out of concern that the assignment of extra-value RINs to volumes would mean that the number of gallon-RINs assigned to a batch could be greater than the number of gallons in that batch. This was of particular concern for ethanol, since a tank could contain both corn-ethanol and cellulosic ethanol. When volume was withdrawn from the tank, it would have been unclear whether the volume should be assigned the extra-value RINs or not. In the process of designing the proposed program structure to accommodate such situations, however, the program became more complicated than it needed to be.
In response to the NPRM, some commenters requested that extra-value RINs be treated just like standard-value RINs. Specifically, some obligated parties, as well as gasoline marketers and distributors, argued that all RINs, be they standard-value or extra-value, should be required to travel with volumes of renewable fuel so that they will all be equally available to the obligated parties that need them for compliance. These commenters expressed concern that some producers may not release extra-value RINs, if given the choice, in an effort to drive up demand for renewable fuel.
After further consideration, we have determined that in most cases there is no need to treat extra-value RINs differently from standard-value RINs in terms of whether each should be assigned to batches of renewable fuel by the producer or importer. Therefore, for most renewable fuels we are finalizing a requirement that all RINs be assigned to batches of renewable fuel by the producer or importer. Since each renewable fuel with a different Equivalence Value is a distinct fuel, producers and importers will still receive the added value of extra-value RINs that are assigned to volumes of renewable fuel if those volumes are priced appropriately in comparison to other renewable fuels with different Equivalence Values. The only exception to this is cellulosic biomass and waste-derived ethanol. Producers of such ethanol may have difficulty marketing their product at prices different than that for corn ethanol given the fungible distribution system for ethanol. The added value of the extra-value RINs may not be reflected in the price and as a result the producer may not receive any economic benefit from them. Therefore, for the case of cellulosic biomass and waste-derived ethanol we are maintaining the ability of the producer, should they so choose, to retain the extra value and not assign these RINs to the renewable fuel that they represent. In such cases, the producer of the cellulosic biomass or waste-derived ethanol would be required to change the K code from 1 to 2 in order to designate these extra RINs as separated RINs.
This approach is also consistent with one of the primary motivations for the approach described in our NPRM, namely that each gallon-RIN be allowed to have a value of 1.0 to facilitate trading. Even though different renewable fuels will have different Equivalence Values and therefore different numbers of gallon-RINs per gallon, each gallon-RIN will still count as one gallon of renewable fuel for RFS compliance purposes.
However, the distinction between standard-value RINs and extra-value RINs is no longer necessary. The total number of gallon-RINs that can be generated for a given batch of renewable fuel will be determined directly by its Equivalence Value as described in Section III.D.2.b, and all such gallon-RINs will be summarized in a single batch-RIN assigned to a batch. In cases where the Equivalence Value is greater than 1.0, there will be more gallon-RINs assigned to a batch of renewable fuel than gallons in that batch. Once again, in the context of the changes we are making to the RIN distribution program structure as described in Section III.E.1.b below, we do not believe that this will in any way complicate the process of distributing RINs with renewable fuel. For the specific case of cellulosic biomass or waste-derived ethanol with an Equivalence Value of 2.5, producers will be required to assign only one gallon-RIN to each gallon of ethanol, each of which has a K code value of 1. The additional 1.5 gallon-RINs that can be generated for each gallon can remain unassigned, and thus be assigned a K code value of 2.
In addition to cases where the Equivalence Value is greater than 1.0, there are several other cases in which the gallon-RINs assigned to a batch will not exactly correspond to the number of gallons in that batch. First, if a renewable fuel has an Equivalence Value less than 1.0, then there will be fewer gallon-RINs than gallons in the batch. Such potential circumstances are described in Section III.D.2.c. RINs may also not correspond exactly to gallons if the density of the batch changes due to changes in temperature. For instance,
Consistent with the NPRM, we are requiring that RIN generation begin at the same time that the renewable fuel standard becomes applicable to obligated parties. Thus RINs must be generated for all renewable fuel produced or imported on or after September 1, 2007. Since many producers and importers will have renewable fuel in inventory at the start of the program that was produced prior to September 1, 2007, we are also allowing them to generate RINs for any renewable fuel that they own on September 1, 2007. This provision ensures that every gallon that a producer or importer sells starting on September 1, 2007 can have an assigned RIN, and obligated parties that take ownership of renewable fuel directly from a producer or importer will have greater assurance of receiving RINs at the start of the program. Since RINs are not assigned to volumes until those volumes are transferred to another party, this approach also provides producers and importers of renewable fuel the flexibility to determine which of the volumes they own on September 1, 2007 constitute production as of the start of the program.
Although a RIN is generated when renewable fuel is produced or imported, we do not define the point of production. However, the RIN must be assigned to a batch no later than the point in time when ownership of the batch is transferred from the producer or importer to another party. If ownership of the batch is retained by the producer or importer after the batch leaves the originating facility, the RIN need not be transferred along with the batch on product transfer documents identifying transfer of custody.
The means through which RINs are transferred with volumes of renewable fuel will in some respects be left to the discretion of the renewable fuel producer or importer. The primary requirement would be that the RIN transfer be recorded on a product transfer document (PTD). The PTD can be included in any form of standard documentation that is already associated with or used to identify title to the volume or can be a separate document as described below. In many cases an invoice could serve this purpose. As in other fuels programs, we believe the PTD requirement can be met by including the required information generated and transferred in the normal course of business.
RINs are transferable in the context of the RFS program and initially must be transferred along with ownership of a volume of renewable fuel. The approach that a producer or importer takes to the transfer or sale of RINs and volumes would be at their discretion, under the condition that the RIN and volume be transferred or sold on the same day and to the same party. Based on comments received, we are also permitting the transfer of RINs to be done in a separate PTD from the PTD used to transfer ownership of the volume of renewable fuel. This will provide some additional flexibility to parties who take ownership of renewable fuel with assigned RINs, permitting IT systems managing RIN transfers to be more easily incorporated into existing business management systems. Thus a party may use two separate PTDs, one for the volume and another for the RINs. However, transfer of the RINs must occur on the same day that transfer of the volume occurred, and the two PTDs must contain sufficient information to uniquely cross-reference them. In many cases an electronic transfer will suffice if sufficient information about the transfer is recorded. In the case of such parallel PTDs, we are also requiring that the PTD transferring ownership of the volume must indicate whether RINs are being transferred and the number of gallon-RINs being transferred, though it need not list the actual RINs.
As described in Section III.E.1.b below, while assigned RINs must always be transferred to another party with a volume of renewable fuel, we are allowing any party that received assigned RINs with renewable fuel to thereafter transfer anywhere from zero to 2.5 gallon-RINs with each gallon of renewable fuel. This provision provides the flexibility to transfer more assigned RINs with some volumes and less assigned RINs with other volumes depending on the business circumstances of the transaction and the number of RINs that the seller has available. However, for producers and importers of renewable fuel, this level of flexibility could contribute to short-term hoarding that was the primary concern expressed by obligated parties during development of the proposed program. Therefore we are also finalizing a provision that requires producers and importers to transfer assigned gallon-RINs with gallons such that the ratio of assigned gallon-RINs to gallons is equal to the equivalence value for the renewable fuel. Since this is not possible for exempt small volume producers, or when a producer or importer obtains renewable fuel from another party without assigned RINs, exceptions are made in these cases.
We received comment that EPA should require a purchaser of imported gasoline who subsequently blends renewable fuel into the imported gasoline to transfer the RINs associated with the renewable fuel back to the importer of the gasoline. The commenter suggested that this requirement would ensure that the importer of the gasoline obtains all the RINs associated with the renewable fuel blended into that gasoline in cases where the importer has a long-term contractual agreement with the party that purchases the gasoline and adds the renewable fuel. However, we do not believe that such a provision is warranted. The RFS program places the renewable fuels obligation on parties based on ownership of the gasoline at the refiner or importer level. We believe this approach is the most effective way to implement and enforce the renewable fuels requirement. We also believe it is appropriate to allow parties who add the renewable fuel to gasoline, including blenders, to separate RINs from the renewable fuel volume and to have the right to sell those RINs to any party. Individual parties may agree that,
The NPRM did not specify whether RINs should be generated for and assigned to renewable fuel that is already contained in imported gasoline (for example, a blend of 10 percent ethanol and 90 percent gasoline). Since the renewable fuel contained in imported gasoline is part of the total volume of renewable fuel in gasoline sold or introduced into commerce in the U.S., we believe it is appropriate to treat it as any other imported renewable fuel. Thus, we believe it would be appropriate for importers to assign RINs to renewable fuel contained in imported gasoline. However, the volume of renewable fuel contained in imported gasoline is very small in comparison to the volume requirements of the RFS program. If an importer of gasoline containing renewable fuel imports less than 10,000 gallons per year of renewable fuel, then that party is not required to generate RINs. But a small volume importer that chooses to generate and assign RINs to any volume of renewable fuel in imported gasoline is required to fulfill all of the requirements that apply to renewable fuel importers under the RFS rule, in addition to all of the requirements that apply to gasoline importers as obligated parties. An importer that assigns RINs to the renewable fuel in imported gasoline may separate the RINs from the renewable fuel, since the renewable fuel has been blended into gasoline.
Regardless of a small volume importer's decision to generate and assign RINs to renewable fuel contained in imported gasoline, an importer that imports any gasoline containing renewable fuel must include the gasoline portion of the imported product in the volume used to determine the importer's renewable fuel obligation (and exclude the renewable fuel portion of the batch). RINs must be assigned to imported renewable fuels that are not contained in gasoline at the time of importation, unless less than 10,000 gallons of renewable fuel are imported per year.
Volumes of renewable fuel can be transferred between many different types of parties as they make their way from the production or import facilities where they originated to the places where they are blended into conventional gasoline or diesel. Some of these parties take custody but not ownership of these volumes, storing and transmitting them on behalf of those who retain ownership. Other parties take ownership but not custody, such as a refiner who purchases ethanol and has it delivered directly to a blending facility. Thus prior to blending, each volume of renewable fuel can be owned or held by any number of parties including marketers, distributors, terminal operators, and refiners.
In the NPRM, we proposed that in general all parties that assume ownership of any volume of renewable fuel would be required to transfer all RINs assigned to that volume to another party to whom ownership of the volume is being transferred. The only exceptions to the requirement that RINs be transferred with volumes would be for parties who are obligated to meet the renewable fuel standard and parties who convert the renewable fuel into motor vehicle fuel. Commenters overwhelmingly supported this approach to the distribution of RINs assigned to volumes of renewable fuel, and as a result we are adopting this approach in our final program. In this context, we are also clarifying that parties taking custody of a volume of renewable fuel but not ownership of that volume would have no responsibilities with regard to the transfer of RINs.
However, in response to the NPRM, several stakeholders apprised us of certain aspects of our proposed program that would limit the intended fungibility of RINs assigned to volumes of renewable fuel. While the goal of our proposed program was to permit RINs to be interchangeable with one another and to permit one assigned RIN to be exchanged with another RIN, our proposed regulations did not sufficiently capture this level of fungibility. Instead, the proposed regulations effectively required that a specific RIN assigned to a specific gallon of renewable fuel must remain assigned to that specific gallon as it travels through the distribution system. This approach was taken in order to accommodate the legitimate existence of some volumes of renewable fuel without assigned RINs, and some assigned RINs that have no corresponding volume. These situations can occur in the distribution system for several reasons, such as the following:
• RINs can be separated from renewable fuel by obligated parties or blenders, and the renewable fuel re-introduced into the distribution system.
• Small volume producers are exempt from generating and assigning RINs to their product.
• At the start of the program, some parties may have renewable fuel in their inventories that have not been assigned a RIN.
• Batches of renewable fuels with Equivalence Values less than 1.0 will have fewer gallon-RINs than gallons.
• Batch volumes can swell or shrink due to temperature changes.
• Batch volumes can shrink due to evaporation, spillage, leakage, or accidents.
• Volume metering imprecision.
Indeed, if the program could be designed such that every gallon in the distribution system always had an assigned RIN, the complete fungibility of RINs would be straightforward. However, this is not the case.
In order to make assigned RINs more fungible, we are finalizing a modified version of our proposed approach. Consistent with the NPRM, no party will be permitted to change a RIN assigned to a volume of renewable fuel into an unassigned (separated) RIN except for those parties explicitly given the right to do so (for example, obligated parties and oxygenate blenders). Also consistent with the NPRM, any party not authorized to separate an assigned RIN that takes ownership of a RIN assigned to a volume of renewable fuel cannot transfer ownership of that RIN to another party without simultaneously transferring an appropriate volume of renewable fuel.
However our final regulations allow any party to transfer a volume of renewable fuel without assigned RINs, or with a different number of assigned RINs than were received with the renewable fuel, as long as the number of assigned gallon-RINs held by that party at the end of a quarter is no higher than the number of gallons it owns at the end of the quarter. This will provide parties with the flexibility to decide which RINs are transferred with which volumes, and to transfer some volumes without RINs if the party took ownership of some volumes without assigned RINs. Our final regulations require only that the number of gallon-RINs held by a party at the end of a quarter be no higher than the number of gallons held by that party, adjusted by their Equivalence Value. Aside from spillage, evaporation, or volume metering imprecision, the only way that the number of gallon-RINs that are held by a party could be higher than the number of gallons held (adjusted for their Equivalence Value) is if that party transferred some volume without RINs. In such a case the excess RINs held
While this approach creates more flexibility for parties that hold assigned RINs, it requires three additional changes to the proposed regulations. First, we are requiring parties that hold assigned RINs to also report the volumes of renewable fuel held at the end of each quarter. While the NPRM did not propose that volumes held be reported, we believe that the additional burden on parties holding assigned RINs will be minimal. The NPRM proposed that the recordkeeping requirements include information on all renewable fuel volumes transferred, so under the proposal parties holding assigned RINs would in general already have the information available. In addition, we are not requiring that all volumes held at any time during the quarter be reported, nor are we requiring that all volumes transferred be reported. Rather, parties will be required only to report the total volume of renewable fuel and the total number of gallon-RINs held on the last day of a quarter, in addition to other information regarding RINs held and transferred.
Second, our modified approach requires that we distinguish between RINs assigned to renewable fuel and RINs that have already been separated from renewable fuel, since only assigned RINs would be subject to the end-of-quarter comparison of RINs held and volumes held. We have chosen to use the K code in the RIN for this purpose, since it no longer serves the purpose of distinguishing between standard-value and extra-value RINs. The K code has also been moved to the beginning of the RIN to make its value more prominent. RINs assigned to renewable fuel must have a K code of 1. Parties who legally separate a RIN from renewable fuel must change the K code for that RIN to a value of 2. The RIN then formally becomes an unassigned RIN that can be transferred independent of renewable fuel volumes. The end-of-quarter comparisons between RINs held and volumes held apply only to RINs with a K value of 1.
Third, we are requiring quarterly reporting in addition to annual reports for RINs held and transferred. In the NPRM we took comment on requiring quarterly reporting for various reasons. We received both comments supporting and opposing quarterly reporting. As discussed further in Section IV, we are requiring quarterly reporting in this final rule. Under our modified program structure, quarterly reporting will be necessary to ensure that RINs are available for obligated parties' annual compliance. Quarterly reports will provide us with the ability to monitor the activities of marketers and distributors in real time to ensure that they are transferring RINs with renewable fuel, and to address potential violations as soon as they arise.
As discussed in Section III.E.1.a above, we are requiring that producers and importers of renewable fuel assign all RINs to volumes of renewable fuel, consistent with our proposed approach to standard-value RINs. As a result, downstream parties can legitimately hold more gallon-RINs than gallons if some of the renewable fuel has an Equivalence Value greater than 1.0. In the context of our modified approach to RIN distribution, this fact must be taken into account in the end-of-quarter comparison of gallon-RINs held and gallons held. Thus the following equation must be satisfied at the end of each quarter by each party that has taken ownership of any assigned RINs:
Under our fungible distribution system, the RINs received with a volume of renewable fuel may not be the RINs originally generated to represent that particular volume. Thus the Equivalence Value for a volume of renewable fuel cannot be based on the RR code of associated RINs, but instead should be determined from the composition of the renewable fuel. If the Equivalence Value for a volume of renewable fuel cannot be determined from its composition, it should be assumed to be 1.0. However, in the specific case of ethanol the owner may not know if a volume can be categorized as cellulosic biomass ethanol or waste-derived ethanol. Thus for volumes of ethanol held at the end of a quarter, the Equivalence Value should be assumed to be 2.5 to ensure that a party can legitimately hold more RINs than gallons.
The above equation ensures that the total number of gallon-RINs that can be held by a party at the end of a quarter is no greater than the number of gallon-RINs he could have received given the volume of renewable fuel that he owns. Parties that do not satisfy the above equation are deemed to be in violation of the prohibition against separating RINs from volumes.
Under our modified approach to RIN distribution, it might be possible for a party who owns volumes of renewable fuel with assigned RINs to hold onto all the RINs until near the end of a quarter while selling volume without RINs. Then, in order to comply with the above equation, the party could transfer all assigned RINs with a single volume of renewable fuel prior to the last day of the quarter. This approach would amount to short-term hoarding. To prevent it, we are also placing a cap on the maximum number of gallon-RINs that can be transferred with any gallon of renewable fuel. The cap is dictated by the maximum number of gallon-RINs that a party could receive with a volume of renewable fuel, which is 2.5 in the case of cellulosic biomass ethanol or waste-derived ethanol. For a party that took ownership of these types of renewable fuel, we must allow them to transfer up to 2.5 gallon-RINs with each gallon.
We are also aware that there are situations in which the volume transferred to another party might be smaller than the volume originally received. This could occur due to fuel evaporation, spillage, leakage, or volume metering imprecision, and would have the effect of raising the ratio of gallon-RINs held to gallons held. For spillage/leakage involving significant volumes, we have developed a mechanism for formally retiring the RINs associated with the lost volume. See Section IV. Smaller volume losses can be accommodated by a RIN transfer cap of 2.5, which would in general allow RINs associated with lost volume to be transferred with remaining volume. In the rare case that a party takes ownership of only cellulosic biomass ethanol or waste-derived ethanol and experiences some small volume loss, he can take ownership of a small volume of some other form of renewable fuel with an Equivalence Value less than 2.5. This will permit him to transfer RINs associated with lost volume to another party while still meeting the RIN transfer cap of 2.5.
Our program is designed to allow RIN transfer and documentation to occur as part of normal business practices in the context of renewable fuel distribution. Thus the incremental costs of transferring RINs with volumes is expected to be minimal. Marketers and distributors must simply add the RIN to product transfer documents such as
Finally, the final rule also provides that a foreign entity may apply to EPA for approval to own RINs. As an approved foreign RIN owner, the foreign entity will be able to obtain, sell, transfer and hold both assigned and separated RINs. An approved foreign RIN owner will be required to comply with all requirements that apply to domestic RIN owners under the RFS rule. In addition, similar to other fuels programs, an approved foreign RIN owner will be required to comply with additional requirements designed to ensure that enforcement of the RFS regulations at the foreign RIN owner's place of business will not be compromised.
In the RIN distribution approach proposed in the NPRM, RINs assigned to a given volume of renewable fuel remained assigned to that volume as it moved through the distribution system. In that context, batch splits and batch mergers required special treatment. We discussed the need for protocols to ensure that RINs assigned to parent batches were appropriately distributed among daughter batches, and that RINs assigned to batches that were merged were all re-assigned to the new combined batch. The proposed regulations included some restrictions on how parent batch RINs were to be apportioned to daughter batches during splits, but fell short of prescribing a detailed batch split protocol. Nevertheless, commenters by and large did not address these protocols in their comments.
The need for protocols for batch splits and batch mergers was directly related to the NPRM's approach to the distribution of RINs with volumes of renewable fuel. As described in Section III.E.1.b above, we are modifying our approach to permit assigned RINs to be more fungible. As a result, there is no need for the regulations to specify any batch splitting or batch merging protocols.
Under our final regulations, parties taking ownership of volumes of renewable fuel with assigned RINs will simply retain an inventory of all assigned RINs owned. As volumes of renewable fuel are then transferred to other parties, an appropriate number of gallon-RINs are withdrawn from the party's inventory and transferred along with the renewable fuel. There is no need for the party to determine which RINs were originally assigned to the volume being transferred. For parties handling both ethanol and biodiesel, it would be reasonable to transfer RINs with volumes in a manner consistent with the Equivalence Value of the renewable fuel, but this would not be required under our final regulations in which the number of assigned gallon-RINs transferred with each gallon of renewable fuel can be anywhere between zero and 2.5. In addition, volumes of renewable fuel can be split or merged any number of times while remaining under the ownership of a single party, with no impact on RINs. It is only when ownership of a volume of renewable is transferred to another party that an appropriate number of gallon-RINs need to be withdrawn from the party's inventory and assigned to the transferred volume, subject to the flexibility associated with the quarterly average as discussed above.
Separation of a RIN from a volume of renewable fuel means that the RIN is no longer included on the PTD and can be traded independently from the volume to which it had originally been assigned. In general commenters supported our proposed approach of limiting the parties that can separate a RIN from a batch, and the associated conditions under which separation can occur.
In designing the regulatory program, we structured it around facilitating compliance by obligated parties with their renewable fuel obligation, with the intention of giving obligated parties the power to market the renewable fuel separately from the RIN originally assigned to it. Our final program therefore requires a refiner or importer to separate the RIN from renewable fuel as soon as he assumes ownership of that renewable fuel. In the case of ethanol blended into gasoline at low concentrations (≤ 10 volume percent), stakeholders have informed us that a large volume of the ethanol is purchased by refiners directly from ethanol producers, and is then passed to blenders who carry out the blending with gasoline. Therefore, in many cases RINs assigned to renewable fuel will pass directly from the producers who generated them to the obligated parties who need them.
However, significant volumes of ethanol are also blended into gasoline without first being purchased by a refiner. In some cases, the blender itself purchases the ethanol. In other cases, a downstream customer purchases the ethanol and contracts with the blender to carry out the blending. Regardless, the ethanol may never be held or owned by an obligated party before it is blended into gasoline. Thus we are also requiring a blender to separate the RIN from the renewable fuel if he takes ownership of the renewable fuel and actually blends it into gasoline (or, in the case of biodiesel, into diesel fuel). This would only apply to volumes where the RIN had not already been separated by an obligated party. Since blenders will in general not be obligated parties under our program, blenders who separate RINs from renewable fuel will have no need to hold onto those RINs and thus can transfer them to an obligated party for compliance purposes or to any other party.
There may be occasions in which a retailer downstream of a blender actually owns the volume of renewable fuel when it is blended into gasoline or diesel. In such cases the blender will have custody but not ownership of the renewable fuel. In today's final rule we are requiring the RIN to be separated from the volume of renewable fuel when that volume is blended into gasoline, but the RIN can only be separated by the party that owns that volume of renewable fuel at the time of blending. In the case of a blender and a downstream customer who might both lay claim to the right to separate any assigned RINs (for instance, if transfer of ownership occurred simultaneous with blending), these two parties would need to come to agreement between themselves regarding which party will own the separated RINs.
As described in Section III.B, many different types of renewable fuel can be used to meet the RFS volume obligations placed upon refineries and importers. Currently, ethanol is the most prominent renewable fuel and is most commonly used as a low level blend in gasoline at concentrations of 10 volume percent or less. However, some renewable fuels can be used in neat form (i.e. not blended with conventional gasoline or diesel). The two RIN separation situations described above would capture any renewable fuel for which ownership is assumed by an obligated party or a party that blends the renewable fuel into gasoline or diesel. However, renewable fuels which are used in their neat (unblended) form as motor vehicle fuel would not be captured. This would include such renewable fuels as neat biodiesel (B100) or renewable diesel, methanol for use in a dedicated methanol vehicle or biogas for use in a CNG vehicle.
Under our final program, producers and importers must assign a RIN to all renewable fuels produced or imported, including neat renewable fuels. To avoid the possibility that the RIN assigned to neat renewable fuel would never become available to an obligated
As discussed above, under our final rule, obligated parties must separate RINs from volumes of renewable fuel. This applies to all volumes of renewable fuel that an obligated party owns. The requirement to separate a RIN from the renewable fuel is intended to apply to refiners, blenders and importers for whom the production or importation of gasoline is a significant part of their overall business operations. Parties that are predominately renewable fuel producers or importers, but which must be designated as obligated parties due to the production or importation of a small amount of gasoline, should not be able to separate RINs from all renewable fuels that they own. For example, we believe it would be inappropriate to permit an ethanol producer to separate RINs from all volumes that they own simply because the producer imported, for example, a single truckload of gasoline from Canada or Mexico. As a result, the final rule prohibits obligated parties from separating RINs from volumes of renewable fuel that they produce or import that are in excess of their RVO. However, obligated parties must separate any RINs from volumes of renewable fuel that they own if that volume was produced or imported by another party.
As described in Section III.B.2, RINs can be generated for renewable fuels made from renewable crude which is treated as if it were a petroleum-derived crude oil or derivative, and is used as a feedstock in a traditional refinery processing unit. Whether the renewable crude is coprocessed with petroleum derivatives or is processed in a facility or unit dedicated to the renewable crude, the final product is generally a motor vehicle fuel. In such cases the refinery will have the responsibility of generating RINs for the renewable fuel produced. But since renewable crude is generally processed in a traditional refinery, the refiner will be an obligated party and can therefore immediately separate those RINs from the renewable fuel and transfer them to another party. As described in III.E.1.a above, cellulosic and waste-derived ethanol producers will also be permitted to separate the RINs associated with the extra 1.5 value of their ethanol production.
Once a RIN is separated from a volume of renewable fuel, the PTD associated with that volume can no longer list the RIN. However, in the NPRM we requested comment on whether PTDs should include some notation indicating that the assigned RIN has been removed to avoid concerns about whether RINs assigned to batches have not been appropriately transferred with the batch. One refiner commented that the addition of such a note on a PTD would represent an unnecessary burden, while two commenters representing fuel distribution operations indicated that such a notation would be useful. Based on comments we received, we have determined that such notation on PTDs would not only be useful to parties receiving volumes of renewable fuel, but would also be an important element of our RIN distribution requirements under our modified approach. The requirement will ensure that parties who take ownership of renewable fuel without assigned RINs will know that RINs were originally assigned but subsequently removed. We also believe that such a requirement would be of minimal burden to parties that have separated a RIN from a volume of renewable fuel.
As described in Section III.E.1.b, we have modified the RIN transfer requirements for the final rule to make RINs more fungible and to provide more flexibility to distributors while still requiring RINs to be transferred with volumes of renewable fuel. However, our modified approach requires that we distinguish between RINs assigned to renewable fuel and RINs that have already been separated from renewable fuel. Our final rule thus requires that parties who separate a RIN from renewable fuel must change the K code for that RIN to a value of 2. The RIN then becomes an unassigned RIN that can be transferred independent of renewable fuel volumes.
In the NPRM we also provided a discussion of the unique circumstances regarding biodiesel (mono alkyl esters)
A number of commenters expressed concern that the 80 volume percent limit put biodiesel at odds with the RIN separation criteria applicable to other renewable fuels, including neat fuels. Upon further consideration, we have determined that the 80 volume percent limit remains a valid means for ensuring that the separation of RINs from biodiesel is consistent with its common use at low blend levels just as for ethanol, and that RINs are generally separated at the point in time when the biodiesel can be deemed to be motor vehicle fuel. However, based on comments received, we are changing the treatment of biodiesel for the final rule in two ways.
First, obligated parties are required to separate RINs from volumes of biodiesel at the point when they gain ownership of the biodiesel, not when they blend biodiesel with conventional diesel fuel. This approach is consistent with our treatment of the RIN separation
Second, we have determined that a biodiesel producer should be allowed to separate a RIN from a volume of biodiesel that it produces if it designates the volume of biodiesel specifically for use as motor vehicle fuel in its neat form, and the neat biodiesel is in fact used as motor vehicle fuel. In general this demonstration would require that the producer track the volume of biodiesel to the point of its final use. However, this approach to the treatment of neat biodiesel is consistent with how we are treating other renewable fuels used in their neat form.
In the NPRM, we proposed that RINs become freely transferable once they are separated from a batch of renewable fuel. Each RIN could be held by any party and transferred between parties any number of times. We argued that the unique features of the RFS program warranted more open trading than in past fuel credit programs. In particular, RINs are generated by parties other than obligated parties, and many nonobligated parties will own RINs (for example, oxygenate blenders who have the right to separate RINs from volumes). While recognizing that limiting trading to and between obligated parties might help obligated parties to maintain control of those RINs being traded, such an approach could have the unintended effect of limiting the number of RINs that non-obligated parties contribute to the RIN market. The RFS program must work efficiently not only for a limited number of obligated parties, but a number of non-obligated parties as well.
There was disagreement among commenters about whether an open RIN market was appropriate. Several parties supported our proposed approach, saying that unlimited trading among all interested parties would increase liquidity and transparency in the RIN market. They also argued that increasing the number of participants would facilitate the acquisition of RINs by obligated parties and promote economic efficiency.
However, some commenters disagreed, arguing instead that an open market does not necessarily make the market any more fluid and free. They pointed to past credit programs in which only refiners and importers have been allowed to transfer credits, and argued that the success of those programs should compel the Agency to use those past credit program structures as the model for the RFS program.
We continue to believe that there is a need to provide for more open trading in the RFS program and that this need warrants a unique approach for this rule. First, unlike other programs where credits generally represent overcompliance with an applicable standard and are thus supplemental to the means of compliance, under the RFS program RINs are the fundamental unit for compliance. There will be many more RINs in the RFS program than credits in other programs, and the trading structure must maximize the fluidity of those RINs. A wider RIN market will make it easier for obligated parties to get access to RINs.
Second, obligated parties are typically not the ones producing the renewable fuels and generating the RINs, nor blending the renewable fuels into gasoline, so there is a need for trades to occur between obligated parties and non-obligated parties. If we prohibited everyone except obligated parties from holding RINs after they have been separated from a batch, non-obligated parties seeking avenues for releasing their RINs would only be able to release them to obligated parties. Having fewer avenues through which they could market their RINs, some non-obligated parties might opt not to transfer their RINs at all rather than participate in the RIN market with the attendant recordkeeping requirements. Furthermore, a potentially large number of oxygenate blenders, many of which will be small businesses, will be looking for ways to market their RINs. Allowing other parties, including brokers, to own and transfer RINs may create a more fluid and free market that would increase the venues for RINs to be acquired by the obligated parties that need them. Limiting RIN trading to and among obligated parties could make it more difficult for RINs to eventually be transferred to the obligated parties that need them.
Some commenters argued that limiting the RIN trading market to and among obligated parties would make the program more enforceable, since there would be fewer parties to track and the sources of RINs would be more reliable. While this may be directionally true, we believe the RFS program will remain sufficiently enforceable under an open RIN market, and as discussed above, the greater need for market fluidity for this program warrants the change. The RIN number, along with the associated electronic reporting mechanism, will provide us the ability to verify the validity of RINs and the source of any invalid RINs. Since all RINs generated, traded, and used for compliance would be recorded electronically in an Agency database, these types of investigations should be straightforward. The number of RIN trades, and the parties between whom the RINs are being traded, will only have the effect of increasing the size of the database.
Some commenters were concerned that an open RIN market could lead to price volatility and potentially higher prices as non-obligated speculators enter the market expressly to profit from the sale of RINs. According to commenters, these speculators would hold an unfair advantage over obligated parties that must purchase credits for compliance since speculators can hold onto RINs indefinitely, driving up their price. However, by expanding the number of parties that can hold RINs, we minimize the potential for any one party to exercise market power, and thus we do not believe that such activity on the part of speculators is likely to substantively affect the availability of RINs or their price. Moreover, we do not believe that a given party will hold a RIN indefinitely simply to increase profit because RINs have a limited life and new RINs will be generated and will enter the market continuously.
Based on our review of the comments received, we did not find compelling evidence that an open market for RINs would create particular difficulties for obligated parties seeking RINs or would limit the enforceability of the program. As a result we are finalizing a RIN trading program that permits any party to hold RINs and for RINs to be traded any number of times.
As with other credit-trading programs, the business details of RIN transactions, such as the conditions of a sale or any other transfer, RIN price, role of mediators, etc. will be at the discretion of the parties involved. The Agency is concerned only with information such as who holds a given RIN at any given moment, when transfers of RINs occur, who the party to the transfers are, and ultimately which obligated party relies on a given RIN for compliance purposes. This type of information will therefore be the subject of various recordkeeping and reporting requirements as described in Section IV, and these requirements will generally apply regardless of whether a RIN has been separated from a batch.
The means through which RIN trades occur will also be at the discretion of the parties involved. For instance, parties with RINs can create open auctions, contract directly with those
In order to provide public information that could be helpful in managing and trading RINs as well as understanding how the program is operating, we intend to publish a report each year that summarizes information submitted to us through the quarterly and annual reports required as part of our enforcement efforts (see Section IV). Annual summary reports published by EPA may include such information as the number of RINs generated in each month or in each state, the average number of trades that RINs undergo before being used for compliance purposes, or the frequency of deficit carryovers. However, we will not publish information identifying specific parties.
In the NPRM, we also described several alternative approaches to the proposed trading and compliance program that were offered by stakeholders. Most of these alternatives recognized the value of a RIN-based system of compliance, but they differed in terms of which parties would be allowed to separate a RIN from a batch and the means through which the RINs would be transferred to obligated parties. We invited comment on all of these alternatives in the NPRM, but received very few. Based on those comments we did receive, we do not believe that any of these alternative approaches should be implemented at this time. In general our responses to comments on the alternatives can be found in the Summary and Analysis of Comments document in the docket, but we have addressed one particular subject area below.
In the NPRM, we described an alternative approach to RIN distribution in which obligated parties would only be able to separate a RIN from a batch of renewable fuel at the point in time when blending actually occurs. In contrast, the approach we are finalizing today requires an obligated party to separate a RIN from a batch as soon as it gains ownership of that batch. Our final program design is based on the expectation that all but a negligible quantity of renewable fuels will eventually be consumed as motor vehicle fuel, primarily through blending with gasoline or diesel. See further discussion in Section III.D. As a result, we do not believe that it is necessary to verify that blending has actually occurred in order to provide a program that adequately ensures it occurs. The American Petroleum Institute agreed that tracking renewable fuels to the point of blending would represent an unnecessary burden and added that such a requirement could preclude many obligated parties from taking direct steps to obtain RINs to meet their obligations.
The Renewable Fuels Association, however, argued that allowing obligated parties to separate RINs from batches before blending occurred could give rise to RIN hoarding, fraud, and confusion. Most importantly, they noted, the alternative approach would provide direct verification of blending. For the reasons described in Section III.D, we do not believe that a compliance system requiring verification of blending is necessary, given that, with the exception of exports, essentially all renewable fuel produced in the U.S. is used as motor vehicle fuel in the U.S. This is a foundational principle of the use of a RIN-based program design that enjoyed widespread support among stakeholders and widespread recognition that it accurately describes real world practices.
If verification of blending were required before a RIN could be separated from a batch, both obligated parties and blenders would be subject to additional recordkeeping and paperwork burdens. The Agency would be compelled to enforce activities at the blender level, adding about 1200 parties to the list of those subject to enforcement under our final program. Although we agree that the reformulated gasoline program could act as a model from which to construct such a recordkeeping and enforcement system, we continue to believe that such a system would be both unnecessary and burdensome.
The Renewable Fuels Association also argued that our proposed program would result in confusion in the distribution system, since there would be renewable fuel both with and without RINs. However, there are many other reasons that this situation could arise, and none is expected to negatively impact the distribution of renewable fuels or the business agreements developed by parties transferring renewable fuels. For instance, we are exempting small volume producers from generating RINs, renewable fuels with equivalence values less than 1.0 may have fewer RINs than gallons, and volume swell and metering discrepancies can all contribute to situations in which batches legitimately do not have assigned RINs corresponding to their actual volumes. Parties that sell such batches could choose to price such product differently from product that has assigned RINs with a one-to-one correspondence to product volume. We are also requiring that PTDs associated with transfers of volume include notation indicating whether RINs are being simultaneously transferred to address these types of situations.
Another commenter argued that the alternative approach could limit the potential for one refiner to purchase large volumes of renewable fuel with the intent of separating the RINs and exercising market power in the RIN market. However, the commenter did not provide any information regarding how such market power could be exercised by one refiner in a system where unassigned RINs can be transferred freely between parties any number of times, and access to those RINs is not limited geographically in any way. In addition, RINs that have been separated from their assigned batches by oxygenate blenders represent an additional safety valve in the RIN market, providing additional assurances that no one refiner could exercise market power in the RIN market.
Commenters supporting a requirement that RINs be separated only at the point of blending offered no other arguments that hoarding or fraud could actually occur under our proposed approach. Therefore, we are finalizing an approach that requires obligated parties to separate RINs from batches at the point of ownership.
Registration, recordkeeping and reporting are necessary to track compliance with the renewable fuels standard and transactions involving RINs. This summarizes these requirements. Our estimates as to the burden associated with registration, recordkeeping and reporting are contained in this
Obligated parties (including refiners and importers), exporters of renewable fuels, producers and importers of renewable fuels, and any party who owns RINs must register with EPA. Any party may own RINs including, but not limited to, the above-named parties and marketers, blenders, terminal operators, jobbers, and brokers. Owning RINs, and engaging in any activities regarding RINs, is prohibited as of September 1, 2007 unless the party has registered and received EPA company and facility identification numbers.
Most refiners and importers and many biodiesel producers are already registered with us under various regulations in 40 CFR part 80 related to reformulated (RFG) and conventional gasoline or diesel fuel. Parties who are already registered will not have to take any action to register under the RFS program, because their existing registration will be applied to the RFS program as well.
Registration is a simple process. We will use the same basic forms for RFS program registration that we use under the reformulated gasoline (RFG) and anti-dumping program. You may download our registration forms at
Upon receipt of a completed registration form, we will provide you with a unique 4-digit company identification number and a unique 5-digit facility identification number. These numbers will appear in compliance reports and, in the case of renewable fuel producers and importers, they will be incorporated in the unique RINs they generate for each batch of renewable fuel. Timely registration is important because you cannot generate or handle transactions involving RINs until you have registered and received your registration numbers from us. It is advisable to register as soon as possible if you believe you will be engaged in activities that may require registration under the RFS program. Registration can occur any time following signature of this final rule.
If you are already registered under another fuels program, such as RFG and anti-dumping or diesel sulfur, then you do not have to register again. You will use the same company and facility identification number you are currently using for RFS reporting. Parties in this situation may contact the Agency for confirmation or clarification of the appropriate registration numbers to use. As noted above, registrations never expire, but you are responsible for keeping the information we have up to date. If you have previously registered with us but have not had to report until now, then you may wish to contact the person listed on our renewable fuels Web page (
Small volume domestic producers of renewable fuels are those who produce less than 10,000 gallons per year or who import less than 10,000 gallons per year. These parties are not required to register if they do not wish to generate RINs. If a small volume domestic producer of renewable fuels wishes to generate RINs, then that party must register and comply with all recordkeeping and reporting requirements.
Obligated parties, exporters of renewable fuel, producers and importers of renewable fuel, and any party who owns either assigned or unassigned RINs such as marketers or brokers must submit periodic reports to us covering RIN generation, RIN use, and RIN transactions.
There are four basic reports under the RFS program. The first report is an annual compliance demonstration report that is required to be submitted by obligated parties and exporters of renewable fuel. This report provides the RFS compliance demonstration and is required to be submitted on an annual basis. It is focused on calculating the RVO, indicating RINs used for compliance, and determining any deficit carried over.
The second report is a quarterly RIN generation report that is required to be submitted by producers and importers of renewable fuel. This report is focused on providing information on all batches of renewable fuel produced and imported and all RINs generated.
The third report is a RIN transaction report that is required to be submitted by any party that owns RINs, including RIN marketers and brokers, as well as obligated parties, exporters, and renewable fuel producers and importers. This report is focused on providing information on individual RIN purchases, RIN sales, retired RINs, and expired RINs.
The fourth report is a quarterly gallon-RIN activity report that also is required to be submitted by
The following table summarizes the information to be submitted in each type of report by the type of regulated party:
In the proposed rule, we had requested comment on whether reporting should be annual or quarterly. After consideration of comments received, we have determined that each RIN transaction report must be submitted by the end of the quarter in which the transaction occurred, and the gallon-RIN activity report should be submitted quarterly. Quarterly reporting is better because it provides us with the information necessary to confirm the validity and legitimacy of RINs prior to their use in compliance. Additionally, quarterly reporting enables EPA to enforce the RIN/inventory balance requirements for producers and marketers of renewable fuels.
The annual compliance demonstration for obligated parties must be submitted by February 28th for the prior calendar year. For the RIN transaction and quarterly gallon-RIN activity reports, the following schedule applies to all reporting parties:
In the first year of the RFS program only, obligated parties and exporters are given an extra quarter to submit their list of RINs used to demonstrate compliance. This information must be reported by May 31, 2008 for calendar year 2007. All other reporting follows the schedule indicated above.
We will use a simplified and secure method of reporting via the Agency's Central Data Exchange (CDX). CDX permits us to accept reports that are electronically signed and certified by the submitter in a secure and robustly encrypted fashion. Using CDX will eliminate the need for wet ink signatures and will reduce the reporting burden on regulated parties. Guidance for reporting will be issued before implementation and will contain specific instructions and formats consistent with provisions in this final rule. The guidance will be posted on our renewable fuels Web page:
We will accept electronic reports generated in virtually all commercially available spreadsheet programs and will even permit parties to submit reports in comma delimited text, which can be generated with a variety of basic software packages.
CDX will confirm delivery of your report. As described below with regard to recordkeeping, you must retain copies of all items submitted to us for five (5) years.
In order to permit maximum flexibility in meeting the RFS program requirements, we must track activities involving the creation and use of RINs, as well as any transactions such as purchase or sale of RINs. Reports will be imported into a compliance database managed by EPA's Office of Transportation and Air Quality and will be reviewed for completeness and for potential violations. It is important to keep your company contact updated (this is an item on the registration form), because we may need to speak to that person about any problems with a report submitted. Potential violations will be referred to EPA enforcement personnel.
You may claim information submitted to us as confidential business information (CBI). Please be sure to follow all reporting guidance and clearly mark the information you claim as proprietary. We will treat information covered by such a claim in accordance with the regulations at 40 CFR part 2 and other Agency procedures for handling proprietary information.
Since spills can happen whenever renewable fuel with assigned RINs is held, owners have two options if the spill causes their organization to be out of compliance. The owners of the spilled fuel may either retire RINs lost in reported spills or purchase and sell a volume of renewable fuel equal to the reported volume and not associated with RINs in order to meet compliance. Reportable spills for the purposes of this rule refers to spills of renewable fuel with assigned RINs and a requirement by a federal, state, or local authority to report said spills. The party that owns the spilled renewable fuel must retire a number of gallon-RINs corresponding to the volume of spilled renewable fuel multiplied by its equivalence value. If the equivalence value for the spilled volume may be determined based on its composition, then the appropriate equivalence value shall be used. If the equivalence value for the spilled volume cannot be determined, the equivalence value is 1.0. In the case that the fuel must be reported in pounds rather than gallons, the party that reported the spill should use the best available conversion for converting the volume into gallons. In the event that volume is spilled in transport, the owner of the RINs will need to request a copy of the spill report from the party that reported the spill.
The recordkeeping requirements for obligated parties and exporters of renewable fuels support the enforcement of the use of RINs for compliance purposes. Records kept by parties are central to tracking individual RINs through the fungible distribution system after those RINs are assigned to batches of renewable fuel. Parties use invoices or other types of product transfer documentation, which are customarily generated and issued in the course of business and which are familiar to parties who transfer or receive fuel. Parties are afforded significant freedom with regard to the form these documents take, although they must travel in some manner (on paper or electronically) with the volume of renewable fuel being transferred. On each occasion any person transfers ownership of renewable fuels subject to this regulation, that transferor must provide the transferee with documents identifying the renewable fuel and containing the identifying information that includes: The name and address of the transferor and transferee, the EPA-issued company identification number of the transferor and transferee, the volume of renewable fuel that is being transferred, the date of transfer, and each associated RIN. These types of documents must be used by all parties in the distribution chain down to the point where the renewable fuel is blended into conventional gasoline or diesel.
Except for transfers to truck carriers, retailers or wholesale purchaser-consumers, product codes may be used to convey the information required, as long as the codes are clearly understood by each transferee. However, the RIN must always appear in its entirety before it is separated from a batch, since it is a unique identification number that cannot be summarized by a shorter code.
Parties must keep copies of all records for a period of not less than five (5) years. In addition to documentation related to transfers, parties must keep information related to the sale, purchase, brokering and trading of RINs and copies of any reports they submit to us for compliance reports. For example, if a volume of fuel and its associated RINs are reported to us as lost due to spillage, documentation related to that spill must be retained for the five year period. Upon request, parties are responsible for providing records to the Administrator or the Administrator's authorized representative.
In addition to the records applicable to all ethanol producers, producers of cellulosic biomass or waste-derived ethanol must keep records of fuel use in order to ensure compliance with, and enforcement of, the definitions of these types of renewable fuel. Producers of cellulosic biomass or waste-derived ethanol must keep records of volume and types of all feedstocks purchased to ensure compliance with, and enforcement of, the feedstock aspect of the definitions of cellulosic biomass and waste-derived ethanol. In addition, producers of cellulosic biomass or waste-derived ethanol are required to arrange for an independent third party to review the ethanol producer's records and verify that the facility is, in fact, a cellulosic biomass or waste-derived ethanol production facility and that the ethanol producer is producing cellulosic biomass or waste-derived ethanol. The independent third party must be a licensed Professional Engineer (P.E.) in the chemical engineering field. Domestic ethanol producers are not required obtain prior approval of the independent third party P.E. or submit the engineering verification to EPA, however, the ethanol producer and the P.E. are required to keep records related to the required engineering verification and to produce them upon request of the Administrator or the Administrator's authorized representative.
A foreign ethanol producer may apply to us to have its cellulosic biomass or waste-derived ethanol treated in the same manner as domestic cellulosic biomass or waste-derived ethanol under the RFS program. A foreign ethanol producer with an approved application will be required to comply with all of the requirements that apply to domestic ethanol producers, including registration, recordkeeping, reporting,
The provisions for foreign ethanol producers are optional and are available only to foreign producers of cellulosic biomass or waste-derived ethanol. Ethanol or other renewable fuels produced and exported to the United States by other foreign producers are regulated through the importer. An importer that receives ethanol identified as cellulosic biomass or waste-derived ethanol produced by a foreign producer with an approved application would not assign RINs to the ethanol, as RINs for such ethanol will be assigned by the foreign ethanol producer. The importer, like any other marketer, would transfer the RINs assigned by the foreign producer with a volume of ethanol and report the transactions to us.
Attest engagements are similar to financial audits and consist of an independent, professional review of compliance records and reports. Similar to other fuels programs, the RFS program requires reporting parties to arrange for annual attest engagements to be conducted by an auditor that is “independent” under the criteria specified in the regulations. We believe that the attest engagements provide an appropriate and useful tool for verifying the accuracy of the information reported to us. Attest engagements are performed in accordance with standard procedures and standards established by the American Institute of Certified Public Accountants and the Institute of Internal Auditors. The attest engagement consists of an outside certified public accountant (CPA) or certified independent auditor (CIA) following agreed upon procedures to determine whether underlying records, reported items, and transactions agree, and issuing a report as to their findings. Attest engagements are performed on an annual basis.
Obligated parties, producers, exporters and importers of renewable fuel, and any party who own RINs are all subject to the attest engagement requirements.
We had proposed that obligated parties, exporters, and renewable fuels producers be subject to attest engagement requirements. We received several comments on this proposal. Some commenters suggested that the attest engagements should be required for renewable fuels producers and importers, but not for obligated parties. These commenters believe that attest engagements are needed for renewable fuel producers and importers in order to verify reported production and RIN volumes, whereas we can monitor compliance by obligated parties by cross-checking their reports regarding RIN transactions and use with the reports from other parties. These commenters also believe that the information required by obligated parties under the RFS program is not such that an attest engagement is needed because the rule does not require verification of raw data as with other fuels programs. We have considered these comments but continue to believe that the attest engagements are an appropriate means of verifying the accuracy of the information reported to us by obligated parties. In addition to documentation of RIN transactions and use, the reports include information on production and import volumes and calculation of the party's RFS obligation. We believe that attest engagements are necessary in order to verify that the underlying data regarding production and import volumes and RFS obligation, as well as the underlying data regarding RIN transactions and use, support the information included in the reports. As a result, the final rule includes an attest engagement requirement for obligated parties.
We also received several comments that the attest engagement auditor should be required to examine only representative samples of the party's RIN transaction documents rather than the documents for each RIN transaction, as required in the proposed regulations. We agree that examination of representative samples of RIN transaction documents would provide sufficient oversight and that the requirement included in the proposed regulations may be unnecessarily burdensome. As a result, the attest engagement provisions have been modified to require the auditor to examine only representative samples of RIN transaction documents. However, in the case of attest engagements applied to RIN generation by producers or importers of renewable fuel, or the use of RINs for compliance purposes by obligated parties or exporters, the auditor must examine documentation for all RINs generated or used. We believe this requirement is necessary to ensure that obligated parties and exporters are meeting their RFS obligation and that ethanol producers and importers are assigning RINs to each batch of renewable fuel produced or imported as required under the regulations.
The proposed attest engagement regulations at § 80.1164(b) did not include importers of renewable fuels. One commenter pointed out these procedures should apply to both renewable fuels producers and importers. Renewable fuel importers have the same reporting requirements as renewable fuel producers, and, therefore, there is the same need for verification of the information given on the reports through attest engagements. It was an inadvertent oversight that renewable fuel importers were not included in the parties required to
In addition to obligated parties, exporters and renewable fuel producers and importers, we believe that an attest engagement requirement is necessary for any party who takes ownership of a RIN. As discussed above, attest engagements provide an appropriate and useful tool for verifying the accuracy of the information reported to us. Like obligated parties and renewable fuel producers and importers, the final rule requires RIN owners to submit information regarding RIN transaction activity to us. We believe that attest engagement audits are necessary to verify the accuracy of the information included in these reports. Therefore, this final rule includes an attest engagement requirement for RIN owners who are not obligated parties or renewable fuel producers or importers. We believe that inclusion of the requirement in the final rule is a logical outgrowth of the proposed attest engagement requirements for other parties who are required to submit similar information regarding RIN transaction activity to us.
The prohibition and liability provisions applicable to the RFS program are similar to those of other gasoline programs. The final rule identifies certain prohibited acts, such as a failure to acquire sufficient RINs to meet a party's renewable fuel obligation (RVO), producing or importing a renewable fuel without properly assigning a RIN, creating, transferring or using invalid RINs, improperly transferring renewable fuel volumes without RINs, improperly separating RINs from renewable fuel, retaining more RINs during a quarter than the party's inventory of renewable fuel, or transferring RINs that are not identified by proper RIN numbers. Any person subject to a prohibition will be held liable for violating that prohibition. Thus, for example, an obligated party will be liable if the party fails to acquire sufficient RINs to meet its RVO. A party who produces or imports renewable fuels will be liable for a failure to properly assign RINs to batches of renewable fuel produced or imported. A renewable fuels marketer will be liable for improperly transferring renewable fuel volumes without RINs or retaining more RINs during a quarter than the party's inventory of renewable fuels. Any party may be liable for creating, transferring, or using an invalid RIN, or transferring a RIN that is not properly identified.
In addition, any person who is subject to an affirmative requirement under the RFS program will be liable for a failure to comply with the requirement. For example, an obligated party will be liable for a failure to comply with the annual compliance reporting requirements. A renewable fuel producer or importer will be liable for a failure to comply with the applicable renewable fuel batch reporting requirements. Any party subject to recordkeeping or product transfer document requirements would be liable for a failure to comply with these requirements. Like other EPA fuels programs, the final rule provides that a party who causes another party to violate a prohibition or fail to comply with a requirement may be found liable for the violation.
The Energy Act amended the penalty and injunction provisions in section 211(d) of the Clean Air Act to apply to violations of the renewable fuels requirements in section 211(o).
Because there are no standards under the RFS rule that may be measured downstream, we believe that a presumptive liability scheme, i.e., a scheme in which parties upstream from the facility where the violation is found are presumed liable for the violation, would not be applicable under the RFS program. As a result, the RFS rule does not contain such a scheme.
The regulations prohibit any party from creating, transferring or using invalid RINs. These invalid RIN provisions apply regardless of the good faith belief of a party that the RINs are valid. These enforcement provisions are necessary to ensure the RFS program goals are not compromised by illegal conduct in the creation and transfer of RINs.
Any obligated party that reports the use of invalid RINs to meet its renewable fuels obligation may be liable for a regulatory violation for use of invalid RINs. If the obligated party fails to meet its renewable fuels obligation without the invalid RINs, the party may also be liable for not meeting its renewable fuels obligation. In addition, the transfer of invalid RINs is prohibited, so that any party or parties that transfer invalid RINs may be liable for a regulatory violation for transferring the invalid RINs. In a case where invalid RINs are transferred and used, EPA normally will hold each party that committed a violation responsible, including both the user and the transferor of the invalid RINs. For this reason, obligated parties and RIN brokers should use good business judgment when deciding whether to purchase RINs from any particular seller and should consider including prudent business safeguards in RIN transactions, such as requiring RIN sellers to sign contracts with indemnity provisions to protect the purchaser in the event penalties are assessed because we find the RINs are invalid. Similarly, parties that sell RINs should take steps to ensure any RINs that are sold were properly created to avoid penalties that result from the transfer of invalid RINs.
As in other motor vehicle fuel credit programs, the regulations address the consequences if an obligated party is found to have used invalid RINs to demonstrate compliance with its RVO. In this situation, the obligated party that used the invalid RINs will be required to deduct any invalid RINs from its compliance calculations. As discussed above, the obligated party will be liable for not meeting its renewable fuels obligation if the remaining number of valid RINs is insufficient to meet its RVO, and the obligated party may be subject to monetary penalties if it used invalid RINs in its compliance demonstration. In determining an appropriate penalty, EPA will consider a number of factors, including whether the obligated party did in fact procure sufficient valid RINs to cover the deficit created by the invalid RINs. A penalty may include both the economic benefit of using invalid RINs and a gravity component.
Although an obligated party may be liable for a violation if it uses invalid RINs for compliance purposes, we normally will look first to the generator or seller of the invalid RINs both for payment of penalty and to procure sufficient valid RINs to offset the invalid RINs. However, if EPA is unable to
We received several comments on the prohibition regarding use of invalid RINs. Some commenters believe that an obligated party that uses RINs which are later found to be invalid should be given an opportunity to “cure” the shortfall caused by the invalid RINs without penalty. As indicated above, a penalty for a good faith purchaser is not automatic. Where an invalid RIN was created by another party, such as the producer or marketer of the renewable fuel, the party responsible for the existence of the invalid RIN would be liable and would be required to purchase a RIN to make up for the invalid RIN and pay an appropriate penalty. If the responsible party cannot be identified or is out of business, or if EPA is otherwise unable to obtain relief from the party, then the obligated party that used the RIN would be required to purchase a RIN to make up for the invalid RIN. However, any penalty for a good faith purchaser would likely be small, particularly where EPA is able to obtain relief from the party that was responsible for the invalid RIN. Where a RIN was originally believed to be valid but is later found to be invalid, whether a current year RIN may be used to make up for the prior-year invalid RIN would be determined in the context of the enforcement action.
Another commenter suggested that an obligated party should not be liable for a violation unless the party knowingly used the invalid RINs to demonstrate compliance. Where the suspect RINs are later proved to be valid, the party should be able to use the RINs in the subsequent year regardless of the year of generation or any rollover cap. For the reasons stated above, we believe that it is appropriate to hold an obligated party responsible for using invalid RINs even where the party in good faith believed the RINs to be valid. Normally, suspect RINs will be not be replaced until the RINs are proved to be invalid. In the unlikely circumstance that a RIN is first determined to be invalid and then later found to be valid, the ability to use the RIN in a subsequent year would be determined in the context of the enforcement action.
Finally, parties that are predominately renewable fuel producers or importers, but which must be designated as obligated parties due to the production or importation of a small amount of gasoline, should not be able to separate RINs from all renewable fuels that they own. To address such circumstances, we are prohibiting obligated parties from separating RINs that they generate from volumes of renewable fuel in excess of their RVO. However, obligated parties must separate any RINs generated by other parties from renewable fuel if they own the renewable fuel.
While the definition of renewable fuel does not limit compliance with the standard to any one particular type of renewable fuel, ethanol is currently the most prevalent renewable fuel blended into gasoline today. Biodiesel represents another renewable fuel which, while not as widespread as ethanol use (in terms of volume), has been increasing in production capacity and use over the last several years. This section provides a brief overview of the ethanol and biodiesel industries today and how they are projected to grow into the future.
As of October 2006, there were 110 ethanol production facilities operating in the United States with a combined production capacity of approximately 5.2 billion gallons per year.
There are a total of 102 plants processing corn and/or other similarly processed grains. Of these facilities, 92 utilize dry-milling technologies and the remaining 10 plants rely on wet-milling processes. Dry mill ethanol plants grind the entire kernel and produce only one primary co-product: Distillers' grains with solubles (DGS). The co-product is sold wet (WDGS) or dried (DDGS) to the agricultural market as animal feed. In contrast to dry mill plants, wet mill facilities separate the kernel prior to processing and in turn produce other co-products (usually gluten feed, gluten meal, and oil) in addition to DGS. Wet mill plants are generally more costly to build but are larger in size on average. As such, nearly 22 percent of the current overall ethanol production comes from the 10 previously-mentioned wet mill facilities.
The remaining 8 plants which process waste beverages, cheese whey, or sugars/starches, operate differently than their grain-based counterparts. These facilities do not require milling and instead operate a simpler enzymatic fermentation process.
In addition to grain and starch-to-ethanol production, another method exists for producing ethanol from a more diverse feedstock base. This process involves converting cellulosic materials such as bagasse, wood, straw, switchgrass, and other biomass into ethanol. Cellulose consists of tightly-linked polymers of starch, and production of ethanol from it requires additional steps to convert these polymers into fermentable sugars. Scientists are actively pursuing acid and enzyme hydrolysis as well as gasification to achieve this goal, but the technologies are still not fully developed for large-scale commercial production. As of October 2006, the only known cellulose-to-ethanol plant in North America was Iogen in Canada, which produces approximately one million gallons of ethanol per year from wood chips. Several companies have announced plans to build cellulose-to-ethanol plants in the U.S., but most are still in the research and development or pre-construction planning phases. The majority of the plans involve converting bagasse, rice hulls, wood, switchgrass, corn stalks, and other agricultural waste or biomass into ethanol. For a more detailed discussion on future cellulosic ethanol plants and production technologies, refer to RIA Sections 1.2.3.6 and 7.1.2, respectively.
Ethanol production is a relatively resource-intensive process that requires the use of water, electricity, and steam. Steam needed to heat the process is generally produced onsite or by other dedicated boilers. Of today's 110 ethanol production facilities, 101 burn natural gas, 7 burn coal, 1 burns coal and biomass, and 1 burns syrup from the process to produce steam.
The majority of domestic ethanol is currently produced in the Midwest within PADD 2—where most of the corn is grown. Of the 110 U.S. ethanol production facilities, 100 are located in PADD 2. As a region, PADD 2 accounts for 96 percent (or over five billion gallons) of the annual domestic ethanol production, as shown in Table VI.A.1-3.
Leading the Midwest in ethanol production are Iowa, Illinois, Nebraska, Minnesota, and South Dakota with a combined capacity of nearly four billion gallons per year. Together, these five states' 70 ethanol plants account for 76 percent of the total domestic product. However, although the majority of ethanol production comes from PADD 2, there are a growing number of plants located outside the traditional corn belt. In addition to the 15 states comprising PADD 2, ethanol plants are currently located in California, Colorado, Georgia, New Mexico, and Wyoming. Some of these facilities ship in feedstocks (namely corn) from the Midwest, others rely on locally grown/produced feedstocks, while others rely on a combination of both.
The U.S. ethanol industry is currently comprised of a mixture of corporations and farmer-owned cooperatives (co-ops). More than half (or 60) of today's plants are owned by corporations and, on average, these plants are larger in size than farmer-owned co-ops. Accordingly, company-owned plants account for almost 64 percent of the total U.S. ethanol production capacity. Further, more than 50 percent of the total domestic product comes from plants owned by just 6 different companies—Archer Daniels Midland, Broin, VeraSun, Hawkeye Renewables, Global/MGP Ingredients, and Aventine Renewable Energy.
Over the past 25 years, domestic fuel ethanol production has steadily increased due to environmental regulation, federal and state tax incentives, and market demand. More recently, ethanol production has soared due to the phase out of MTBE, an increasing number of state ethanol mandates, and elevated crude oil prices. As shown in Figure VI.A.2-1, over the past three years, domestic ethanol production has nearly doubled from 2.1 billion gallons in 2002 to 4.0 billion gallons in 2005. For 2006, the Renewable Fuels Association is anticipating about 4.7 billion gallons of domestic ethanol production.
EPA forecasts that domestic ethanol production will continue to grow into the future. In addition to the past impacts of federal and state tax incentives, as well as the more recent impacts of state ethanol mandates and the removal of MTBE from all U.S. gasoline, crude oil prices are expected to continue to drive up demand for
A select group of builders, technology providers, and construction contractors are completing the majority of the construction projects described in Table VI.A.2-1. As such, the completion dates of these projects are staggered over approximately 18 months, resulting in the gradual phase-in of ethanol production shown in Figure VI.A.2-2.
As shown in Table VI.A.2-1 and Figure VI.A.2-2, once all the construction projects currently underway are complete (estimated by March 2008), the resulting U.S. ethanol production capacity would be about 8.6 billion gallons. Without even considering forecasted biodiesel production (described below in Section VI.B.1), this would be more than enough renewable fuel to satisfy the 2012 RFS requirements (7.5 billion gallons). However, ethanol production is expected to continue to grow. There are more and more ethanol projects being announced each day. These potential projects are at various stages of planning from conducting feasibility studies to gaining local approval to applying for permits to financing/fundraising to obtaining contractor agreements. Together these potential projects could result in an additional 21 billion gallons of ethanol production capacity as shown in Table VI.A.2-2.
Although there is clearly a great potential for ethanol production growth, it is highly unlikely that all the announced projects would actually reach completion in a reasonable amount of time, or at all, considering the large number of projects moving forward. Since there is no precise way to know exactly which plants will come
As shown above in Table VI.A.2-3, once all the under construction and planned projects are complete the resulting ethanol production capacity would be 14.3 billion gallons. The majority of which would still originate from PADD 2. This volume, expected to be online by 2012, exceeds the EIA AEO 2006 demand estimate (9.6 billion gallons by 2012, discussed more in RIA Section 2.1). The forecasted growth would nearly triple today's production capacity and greatly exceed the 2012 RFS requirement (7.5 billion gallons). While our forecast represents ethanol production capacity (actual production could be lower), we believe it is still a good indicator of what domestic ethanol production could look like in the future. In addition, we predict that domestic ethanol production will continue to be supplemented by imports in the future. According to a current report by F.O. Licht, U.S. net import demand is estimated to be around 300 million gallons per year by 2012, being supplied primarily through the Caribbean Basin Initiative (CBI), with some direct imports from Brazil during times of shortfall or high price. For more information on ethanol imports, refer to RIA Section 1.5.
Of the 112 forecasted new ethanol plants (47 under construction and 65 planned), 106 would rely on grain-based feedstocks. More specifically, 89 would rely exclusively on corn, 13 would process a blend of corn and/or similarly processed grains (milo or wheat), 3 would process molasses, and 1 would process a combination of molasses and sweet sorghum (milo). Of the remaining six plants (all in the planned stage), four would process cellulosic biomass feedstocks and two would start off processing corn and later transition to cellulosic materials. Of the four dedicated cellulosic plants, one would process bagasse, one would process a combination of bagasse and wood, and two would process biomass. Of the two transitional corn/cellulosic plants, one would ultimately process a combination of bagasse, rice hulls, and wood and the other would ultimately process wood and other agricultural residues. In addition to the forecasted new plants, an existing corn ethanol plant plans to expand production and transition to corn stalks, switchgrass, and biomass in the future. A summary of the resulting overall feedstock usage (including current, under construction, and planned projects) is found in Table VI.A.2-4.
Of the 112 forecasted new plants, 100 would burn some amount of natural gas—at least initially. More specifically, 91 plants would rely exclusively on natural gas; 2 would rely on a combination of natural gas, bran and biomass; 1 would burn a combination of natural gas, distillers' grains and syrup; and 6 would start off burning natural gas and later transition to coal. As for the remaining 12 plants, 3 would burn manure-derived methane (biogas); 7 would rely exclusively on coal; 1 would burn a combination of coal and biomass; and 1 would burn a combination of coal, tires and biomass. In addition to the new ethanol plants, three existing plants currently burning natural gas are predicted to transition to alternate boiler fuels in the future. More specifically, two plants plan to transition to biomass and one plans to start burning coal. Our research suggests that 7 of the new plants would utilize combined heat and power (CHP) technology, although others may exist. Three of the new CHP plants would burn natural gas, three would burn coal, and one would burn a combination of coal, tires, and biomass. Among the existing CHP plants, two are predicted to transition from natural gas to coal or biomass at this time. Overall, the net number of CHP ethanol plants would increase from 11 to 18. A summary of the resulting overall plant energy source utilization is found below in Table VI.A.2-5.
The Energy Policy Act of 2005 requires that 250 million gallons of the renewable fuel consumed in 2013 and beyond meet the definition of cellulosic biomass ethanol. The Act defines cellulosic biomass ethanol as ethanol derived from any lignocellulosic or hemicellulosic matter that is available on a renewable or recurring basis including dedicated energy crops and trees, wood and wood residues, plants, grasses, agricultural residues, fibers, animal wastes and other waste materials, and municipal solid waste. The term also includes any ethanol produced in facilities where animal or other waste materials are digested or otherwise used to displace 90 percent of more of the fossil fuel normally used in the production of ethanol.
As shown in Table VI.A.2-4, there are seven ethanol plants planning to utilize cellulosic feedstocks in the future. These facilities have a combined ethanol production capacity of 320 million gallons per year. It is unclear whether these plants would be online and capable of producing 250 million gallons of ethanol by 2013 to meet the Act's cellulosic biomass ethanol requirement. However, as shown in Table VI.A.2-5, there are 12 facilities that burn or plan to burn waste materials to power their ethanol plants. Depending on how much fossil fuel is displaced, these facilities (with a combined ethanol production capacity of 969 million gallons per year) could also meet the definition of cellulosic biomass ethanol under the Act. Considering both feedstock and waste energy plants, the total cellulosic ethanol potential could be as high as 1.3 billion gallons. Even if only one fifth of this ethanol were to end up qualifying as cellulosic biomass ethanol or come to fruition by 2013, it would be more than enough to satisfy the 250 million gallon requirement specified in the Act.
To understand the impact of the increased ethanol production/use on gasoline properties and in turn overall air quality, we first need to gain a better understanding of where ethanol is used today and how the picture is going to change in the future. As such, in addition to the production analysis presented above, we have completed a parallel consumption analysis comparing current ethanol consumption to future predictions.
In the 2004 base case, 3.5 billion gallons of ethanol
As shown above, nearly half (or about 45 percent) of the ethanol was consumed in PADD 2 gasoline, where the majority of ethanol was produced. The next highest region of use was the State of California which accounted for about 25 percent of domestic ethanol consumption. This is reasonable because California alone accounts for over 10 percent of the nation's total gasoline consumption and all the fuel (both Federal RFG and California Phase 3 RFG) has been assumed to contain ethanol (following their recent MTBE ban) at 5.7 volume percent.
As shown above in Table VI.A.3-1, 99 percent of MTBE use occurred in PADDs 1 and 3. This reflects the high concentration of RFG areas in the northeast (PADD 1) and the local production of MTBE in the gulf coast (PADD 3). PADD 1 receives a large portion of its gasoline from PADD 3 refineries who either produce the fossil-fuel based oxygenate or are closely affiliated with MTBE-producing petrochemical facilities in the area. Overall, 100 percent of MTBE in 2004 was assumed to be used in reformulated gasoline.
In 2004, total ethanol use exceeded MTBE use. Ethanol's lead oxygenate role is relatively new, however the trend has been a progression over the past few years. From 2001 to 2004, ethanol consumption more than doubled (from 1.7 to 3.5 billion gallons), while MTBE use (in RFG) was virtually cut in half (from 3.7 to 1.9 billion gallons). A plot of oxygenate use over the past decade is provided below in Figure VI.A.3-1.
The nation's transition to ethanol is linked to states' responses to recent environmental concerns surrounding MTBE groundwater contamination. Resulting concerns over drinking water quality have prompted several states to significantly restrict or completely ban MTBE use in gasoline. At the time of this analysis, 19 states had adopted MTBE bans. A list of the states with MTBE bans is provided in RIA Table 2.1-4.
As mentioned above, ethanol demand is expected to increase well beyond the levels contained in the renewable fuels standard (RFS) under the Act. With the removal of the RFG oxygenate mandate,
In assessing the impacts of expanded renewable fuel use, we have chosen to evaluate two different future ethanol consumption levels, one reflecting the statutory required minimum, and one reflecting the higher levels projected by EIA. For the statutory consumption scenario we assumed 6.7 billion gallons of ethanol use (0.25 billion gallons of which was assumed to be cellulosic) and 0.3 billion gallons of biodiesel. This figure is lower than the 7.2 billion gallons of ethanol we modeled in the proposal because it considers the renewable fuel equivalence values we are finalizing for corn ethanol (1), biodiesel (1.5) and cellulosic ethanol (2.5). For the higher projected renewable fuel consumption scenario, we assumed 9.6 billion gallons of ethanol (0.25 billion gallons of which was assumed to be cellulosic) and 0.3 billion gallons of biodiesel. Although the actual renewable fuel volumes consumed in 2012 may differ from both the required and projected volumes, we believe that
To estimate where ethanol would be consumed in 2012, we used a linear programming (LP) refinery cost model (discussed in more detail in Section VII). For both future ethanol consumption scenarios discussed above, the modeling provided us with a summary of ethanol usage by PADD, fuel type, and season. There was some post-processing involved to ensure that all state ethanol mandates and winter oxy-fuel requirements were satisfied. The adjusted results for the 6.7 Bgal RFS case and the 9.6 Bgal EIA case are presented below in Tables VI.A.4-1 and VI.A.4-2, respectively.
As shown above, the LP modeling predicts that the majority of ethanol will be consumed in PADD 2, where most of the ethanol is produced. The results show varying levels of ethanol usage in RFG in response to the removal of the oxygenate requirement. For the higher ethanol consumption scenario, the modeling suggests that the majority of additional ethanol would be absorbed in PADD 3 conventional gasoline. With respect to seasonality, in both cases, the modeling predicts that a greater fraction of ethanol use would occur in the summertime due to the 1psi RVP waiver. For a more detailed discussion on future ethanol consumption, refer to Chapter 2 of the RIA.
Historically, the cost to make biodiesel was an inhibiting factor to production in the U.S. The cost to produce biodiesel was high compared to the price of petroleum derived diesel fuel, even with the subsidies and credits provided by federal and state programs. Much of the demand occurred as a result of mandates from states and local municipalities, that required the use of biodiesel. However, over the past couple of years biodiesel production has been increasing rapidly. The combination of higher crude oil prices and greater federal tax subsidies has created a favorable economic situation. The Biodiesel Blenders Tax Credit programs and the Commodity Credit Commission Bio-energy Program, both subsidize producers and offset production costs. The Energy Policy Act extended the Biodiesel Blenders Tax Credit program to 2008. This credit provides about one dollar per gallon in the form of a federal excise tax credit to biodiesel blenders from virgin vegetable oil feedstocks and 50 cents per gallon to biodiesel produced from recycled grease and animal fats. The program was started in 2004 under the American Jobs Act, spurring the expansion of biodiesel production and demand. Historical estimates and future forecasts of biodiesel production in the U.S. are presented in Table VI.B.1-1 below.
With the increase in biodiesel production, there has also been a
In addition to the 85 biodiesel plants already in production, as of early 2006, there were 65 plants in the construction phase and 13 existing plants that are expanding their capacity, which when completed would increase total biodiesel production capacity to over one billion gallons per year. Most of these plants should be completed by late 2007. As shown in Table VI.B.2-1 if all of this capacity came to fruition, U.S. biodiesel capacity would exceed 1.4 billion gallons.
For cost and emission analysis purposes, three biodiesel usage cases were considered: A 2004 base case, a 2012 reference case, and a 2012 control case. The 2004 base case was formed based on historical biodiesel usage (25 million gallons as summarized in Table VI.B.1.1). The reference case was computed by taking the 2004 base case and growing it out to 2012 by applying the 2004-2012 EIA diesel fuel growth rate.
This section examines whether there are any feasibility issues associated with the meeting the minimum renewable fuel requirements of the Energy Act. Issues are examined with respect to renewable production capacity, cellulosic ethanol production capacity, and distribution system capability. Land resource requirements are discussed in Chapter 7 of the RIA.
As shown in Sections VI.A. and VI.B., increases in renewable fuel production capacity are already proceeding at a pace significantly faster than required to meet the 2012 mandate in the Act of 7.5 billion gallons as well as the mandate (starting in 2013) of a minimum of 250 million gallons of cellulosic ethanol. The combination of ethanol and biodiesel plants in existence and planned or under construction is expected to provide a total renewable fuel production capacity of over 9.6 billion gallons by the end of 2012. Production capacity is expected to continue to increase in response to strong demand. We estimate that this will require a maximum of 2,100 construction workers and 90 engineers on a monthly basis through 2012.
There are a wide variety of government and renewable fuels industry research and development programs dedicated to improving our ability to produce renewable fuels from cellulosic feedstocks. In this discussion, we deal with at least three completely different approaches to producing ethanol from cellulosic biomass. The first is based on what NREL refers to as the “sugar platform,”
Corn grain is a nearly ideal feedstock for producing ethanol by fermentation, especially when compared with cellulosic biomass feedstocks. Corn grain is easily ground into small particles, following which the exposed starch which has α-linked saccharide polymers is easily hydrolyzed into
Plant cell walls are made up of cellulose and hemicellulose polymers embedded in a lignin matrix. This complex structure prevents both the first step, hydrolyzation of the cellulose and hemicellulose polymers, and the second step, fermentation of the hydrolyzed sugars into ethanol.
Those who wish to use cellulosic biomass feedstocks to produce ethanol face several, difficult problems. The lignin sheath, present in all cellulosic materials, prevents, or at the very least, severely restricts hydrolysis. To produce ethanol from cellulosic biomass feedstocks by fermentation, some type of thermo-mechanical, mechanical, chemical or a combination of these pretreatments is always necessary before the cellulosic and hemicellulosic polymers can be hydrolyzed. In effect, the lignin structure must be “opened” to allow efficient and effective strong acid hydrolysis, weak acid hydrolysis, or weak acid enzymatic hydrolysis of the cellulose/hemicellulose to their glucose and xylose sugar components. Over time, many pretreatment methods or combinations of methods have been tried, some with more success than others. Usually, intense physical pretreatments such as steam explosion are required; grasses and forest thinnings usually need to be chipped, prior to chemical or enzymatic hydrolysis. The most common chemical pretreatments for cellulosic feedstocks are strong acid, dilute acid, caustic, organic solvents, ammonia, sulfur dioxide, carbon dioxide or other chemicals which make the biomass more accessible to the enzymes. Following pretreatment, acidic (dilute and concentrated) and enzymatic hydrolysis are the two process types commonly used to hydrolyze cellulosic feedstocks before fermentation into ethanol.
Dilute acid hydrolysis is the oldest technology for converting cellulose biomass to ethanol. The dilute acid process uses a 1-percent sulfuric acid in a continuous flow reactor at about 420 °F; reaction times are measured in seconds and minutes, which facilitates continuous processing. The process involves two reactions with a sugar conversion efficiency of about 50 percent. The process conditions at which the cellulosic molecules are converted into sugar are also those at which the sugar is almost immediately converted into other chemicals, principally furfural. The rapid conversion to furfural reduces the sugar yield, which along with other by-products inhibits the fermentation process. One way to decrease sugar degradation is to use a two-stage process which takes advantage of the fact that hemicellulose (5-carbon) sugars degrade more rapidly than cellulose (6-carbon) sugars. The first stage is conducted under mild process conditions to recover the 5-carbon sugars, while the second stage is conducted under harsher conditions to recover the 6-carbon sugars. Both hydrolyzed solutions are then fermented to ethanol. Lime is used to neutralize the residual acid before the fermentation stage. Regardless, some sugar degrades to furfural, which naturally limits the net yield of ethanol. The residual cellulose and lignin are used as boiler fuel for electricity or steam production.
Concentrated acid hydrolysis uses a 70-percent sulfuric acid solution, followed by water hydrolysis to convert the cellulose into sugar. The process rapidly, and nearly completely, converts cellulose to glucose (6-carbon) and hemicellulose to xylose (5-carbon) sugar, with little degradation to furfural; the reaction times are typically slower than those of the dilute acid process. The critical factors needed to make this process economically viable are to optimize sugar recovery and cost effectively recover the acid for recycling. The concentrated acid process is somewhat more complicated and requires more time, but it has the primary advantage of yielding up to about 90% of both hemicellulosic and cellulosic sugars.
Enzymatic hydrolysis is not necessarily a recent discovery. We found reports of research conducted by a variety of companies and government agencies going back to at least 1991.
Cost-effective cellulase enzymes must also be developed for this technology to be completely successful.
The second platform for producing cellulosic ethanol is to convert the biomass into a syngas which is then converted into ethanol. A “generic” syngas process is essentially a “steam reformer,” which “gasifies” biomass and other carbon based substances including wastes, in a reduced-oxygen environment and reacts them with steam to produce a synthesis gas or “syngas” consisting primarily of carbon monoxide and hydrogen. The syngas is then passed over in a Fischer-Tropsch catalyst to produce ethanol.
The biomass feedstock is dried to about 15% moisture content and ground small enough to be efficiently burned and reacted in the reformer. The reformer, an important upstream element of the process, is essentially a common solid-fuel gasifier, which with some modification and steam injection becomes what is sometimes referred to as the “primary reformer.”
When any fuel is completely burned, all of its potential energy is released as heat which can be recovered for immediate use. In a common gasification process, the partially burned fuel (wood or coal) releases a small amount of heat, but leaves some uncombusted, gaseous products. Ordinarily, the hot product gases are fed directly to a nearby boiler or gas turbine, to do work; it has been reported that for a well-designed system, the overall efficiency may approach that of a solid fuel boiler. However, when steam is injected into the gasifier, it reacts with the burning solid fuel to produce more gaseous product. The primary reaction is between carbon and water which produces hydrogen and carbon monoxide and an inorganic ash. The ash and heavy hydrocarbon-tars are removed from the raw syngas before it is compressed and passed over Fisher-Tropsch catalyst to produce ethanol. Fisher-Tropsch technology has been used for many years in the chemical and refining industries, most notably to produce gasoline and diesel fuel from syngas produced by coal gasification. Whether the Fischer-Tropsch reaction produces diesel or ethanol is primarily the result of changes to process pressure, temperature and in some cases the use of custom catalysts. In most cases, the Fischer-Tropsch process did not produce pure ethanol in the first pass through the system. Rather, a stream of mixed chemicals was produced, including gasoline, diesel, and oxygenated hydrocarbons (alcohol).
The development of another technology, called plasma, is also underway for creating a syngas from which ethanol is produced. A plasma “reactor,” generates an ionized gas (plasma) which serves as an electrical conductor to transfer intense radiant energy to a biomass or waste material. This intense energy is said to actually breakdown the various materials in the biomass or waste into their atomic components. Anything present in the feed-mass that doesn't gasify, is essentially “vitrified.” This vitrified stream is reportedly inert and can be used as aggregate in paving materials. Following gasification, the syngas is cooled, impurities are removed, and the gas is sent to ethanol production as with the syngas platform described above.
Cellulosic biomass can come from a variety of sources. Because the conversion of cellulosic biomass to ethanol has not yet been commercially demonstrated, we cannot say at this time which feedstocks are superior to others. A few of the many resources are: Post-sorted municipal waste, rice and wheat straw,
Ethanol and biodiesel blended fuels are currently not shipped by petroleum product pipeline due to operational issues and additional cost factors. Hence, a separate distribution system is needed for ethanol and biodiesel up to the point where they are blended into petroleum-based fuel as it is loaded into tank trucks for delivery to retail and fleet operators. In cases where ethanol and biodiesel are produced within 200 miles of a terminal, trucking is often the preferred means of distribution. For longer shipping distances, the preferred
Modifications to the rail, barge, tank truck, and terminal distribution systems will be needed to support the transport of the anticipated increased volumes of renewable fuels. These modifications include the addition of terminal blending systems for ethanol and biodiesel, additional storage tanks at terminals, additional rail delivery systems at terminals for ethanol and biodiesel, and additional rail cars, barges, and tank trucks to distribute ethanol and biodiesel to terminals. Terminal storage tanks for 100 percent biodiesel will also need to be heated during cold months to prevent gelling. The most comprehensive study of the infrastructure requirements for an expanded fuel ethanol industry was conducted for the Department of Energy (DOE) in 2002.
This section examines the impact on fuel costs resulting from the growth in renewable fuel use between a base year of 2004 and 2012. We note that based on analyses conducted by the Energy Information Administration (EIA), renewable fuels will be used in gasoline and diesel fuel in excess of the RFS requirements. As such, the changes in the use of renewable fuels and their related cost impacts are not directly attributable to the RFS rule. Rather, our analysis assesses the broader fuels impacts of the growth in renewable fuel use in the context of corresponding changes to the makeup of gasoline. These fuel impacts include the elimination of the reformulated gasoline (RFG) oxygen standard which has resulted in the refiners ceasing to use the gasoline blendstock methyl tertiary butyl ether (MTBE) and replacing it with ethanol. Thus, in this analysis, we are assessing the impact on the cost of gasoline and diesel fuel of increased use of renewable fuels, the cost savings resulting from the phase out of MTBE and the increased cost due to the other changes in fuel quality that result.
As discussed in Section II, we chose to analyze a range of renewable fuel use. In the case of ethanol's use in gasoline, the lower end of this range is based on the minimum renewable fuel volume requirements in the Act, (the RFS case) and the higher end is based on AEO 2006 (the EIA case). At both ends of this range, we assume that biodiesel consumption will be the level estimated in AEO 2006. We analyzed the projected fuel consumption scenario and associated program costs in 2012, the year that the RFS is fully phased-in. The volumes of renewable fuels consumed in 2012 at the two ends of the range are summarized in Table II.A.1-1.
We have estimated an average corn ethanol production cost of $1.26 per gallon in 2012 (2004 dollars) for the RFS case and $1.32 per gallon for the EIA case. For cellulosic ethanol, we estimate it will cost approximately $1.65 in 2012 (2004 dollars) to produce a gallon of ethanol using corn stover as a cellulosic feedstock. In this analysis, however, we assume that the cellulosic requirement will be met by corn-based ethanol produced by energy sourced from biomass (animal and other waste materials as discussed in Section III.B of today's preamble) and costing the same as corn based ethanol produced by conventional means.
We estimated production costs for soy-derived biodiesel of $2.06 per gallon in 2004 and $1.89 per gallon in 2012. For yellow grease derived biodiesel, we estimate an average production cost of $1.19 per gallon in 2004 and $1.11 in 2012.
For the proposed rule, we estimated the cost of increased use of renewable fuel and other major cost impacts by developing our own cost spreadsheet model. That analysis considered the production cost, distribution cost as well as the cost for balancing the octane and RVP caused by these fuel changes. That analysis, however, could not properly balance octane and other gasoline qualities. For this final rule, we have therefore used the services of Jacobs Consultancy to run their refinery LP model to estimate the cost impacts of the RFS rule.
The results from the refinery LP model indicate that the impacts on overall gasoline costs from the increased use of ethanol and the corresponding changes to the other aspects of gasoline would be 0.49 cents per gallon for the RFS case. The EIA case would result in increased total cost of 1.03 cents per gallon. The actual cost at the fuel pump, however, will be decreased due to the effect of State and Federal tax subsidies for ethanol. Taking this into consideration results in “at the pump” decreased costs (cost savings) of −0.47 cents per gallon for the RFS case and “at the pump” decreased cost of −0.83 cents per gallon for the EIA case. Section 7 of the RIA contains more detail on the cost analysis used to develop these costs.
A significant amount of work has been done in the last decade on surveying and modeling the costs involved in producing ethanol from corn to serve business and investment purposes as well as to try to educate energy policy decisions. Corn ethanol costs for our work were estimated using a model developed by USDA in the 1990s that has been continuously updated by USDA. The most current version was documented in a peer-reviewed journal paper on cost modeling of the dry-grind corn ethanol process, and it produces results that compare well with cost information found in surveys of existing plants.
The cost of ethanol production is most sensitive to the prices of corn and the primary co-product, DDGS. Utilities, capital, and labor expenses also have an impact, although to a lesser extent. Corn feedstock minus DDGS sale credits
The estimated average corn ethanol production cost of $1.26 per gallon in 2012 (2004 dollars) in the RFS case and $1.32 per gallon in the EIA case represents the full cost to the plant operator, including purchase of feedstocks, energy required for operations, capital depreciation, labor, overhead, and denaturant, minus revenue from sale of co-products. It assumes that 86% of new plants will use natural gas as a thermal energy source, at a price of $6.16/MMBtu (2004 dollars).
Under the Energy Act, starch-based ethanol can be counted as cellulosic if at least 90% of the process energy is derived from renewable feedstocks, which include plant cellulose, municipal solid waste, and manure biogas.
In 1999, the National Renewable Energy Laboratory (NREL) published a report outlining its work with the USDA to design a computer model of a plant to produce ethanol from hard-wood chips.
NREL and USDA used a modified version of the model to compare the cost of using corn-grain with the cost of using corn stover to produce ethanol. We used the corn stover model from the second NREL/USDA study for the analysis for this rule. Because there were no operating plants that could potentially provide real world process design, construction, and operating data for processing cellulosic ethanol, NREL had considered modeling the plant based on assumptions associated with a first-of-a-kind or pioneer plant. The literature indicates that such models often underestimate actual costs since the high performance assumed for pioneer process plants is generally unrealistic.
Instead, the NREL researchers assumed that the corn stover plant was an Nth generation plant, e.g., not a pioneer plant or first-or-its kind, built after the industry had been sufficiently established to provide verified costs. The corn stover plant was normalized to the corn kernel plant, e.g., placed on a similar basis.
We calculated fixed and variable operating costs using percentages of direct labor and total installed capital costs. Following this methodology, we estimate that producing a gallon of ethanol using corn stover as a cellulosic feedstock would cost $1.65 in 2012 (2004 dollars).
We based our estimate for the cost to produce biodiesel on the use of USDA's, NREL's and EIA's biodiesel computer models, along with estimates from engineering vendors that design biodiesel plants. Biodiesel fuel can be made from a wide variety of virgin vegetable oils such as canola, corn oil, cottonseed, etc. though, the operating costs (minus the costs of the feedstock oils) for these virgin vegetable oils are similar to the costs based on using soy oil as a feedstock, according to an analysis by NREL Biodiesel costs are therefore determined based on the use of soy oil, since this is the most commonly used virgin vegetable feedstock oil, and the use of recycled cooking oil (yellow grease) as a feedstock. Production costs are based on the process of continuous transesterification, which converts these feedstock oils to esters, along with the ester finishing processes and glycerol recovery. The models and vendors data are used to estimate the capital, fixed and operating costs associated with the production of biodiesel fuel, considering utility, labor, land and any other process and operating requirements, along with the prices for
The USDA, NREL and EIA models are based on a medium sized biodiesel plant that was designed to process raw degummed virgin soy oil as the feedstock. Additionally, the EIA model also contains a representation to estimate the biodiesel production cost for a plant that uses yellow grease as a feedstock. In the USDA model, the equipment needs and operating requirements for their biodiesel plant was estimated through the use of process simulation software. This software determines the biodiesel process requirements based on the use of established engineering relationships, process operating conditions and reagent needs. To substantiate the validity and accuracy of their model, USDA solicited feedback from major biodiesel producers. Based on responses, they then made adjustments to their model and updated their input prices to year 2005. The NREL model is also based on process simulation software, though the results are adjusted to reflect NREL's modeling methods, using prices based on year 2002. The output for all of these models was provided in spreadsheet format. We also use engineering vendor estimates as another source to generate soy oil and yellow grease biodiesel production costs. These firms are primarily engaged in the business of designing biodiesel plants.
The production costs are based on an average biodiesel plant located in the Midwest using feedstock oils and methanol, which are catalyzed into esters and glycerol by use of sodium hydroxide. Because local feedstock costs, distribution costs, and biodiesel plant type introduce some variability into cost estimates, we believe that using an average plant to estimate production costs provides a reasonable approach. Therefore, we simplified our analysis and used costs based on an average plant and average feedstock prices since the total biodiesel volumes forecasted are not large and represent a small fraction of the total projected renewable volumes.
The models and vendor estimates are further modified to use input prices for feedstocks, byproducts and energy that reflect the effects of the fuels provisions in the Energy Act. In order to capture a range of production costs, we generated cost projections from all of the models and vendors. We present the details on these estimates in Chapter 7 of the RIA.
For soy oil biodiesel production, we estimate a production cost ranging from $1.89 to $2.15 per gallon in 2012 (in 2004 dollars) using these different models and sources of information. For yellow grease derived biodiesel, we used the EIA and vendor estimates to generate total production costs which range from $1.11 to $1.56 for year 2012.
With the current Biodiesel Blender Tax Credit Program, producers using virgin vegetable oil stocks receive a one dollar per gallon tax subsidy while yellow grease producers receive 50 cents per gallon, reducing the net production cost to a range of 89 to 115 cents per gallon for soy oil and 61 to 106 cents per gallon for yellow greased derived biodiesel fuel in 2012. This compares favorably to the projected wholesale diesel fuel prices of 138 cents per gallon in 2012, signifying that the economics for biodiesel are positive under the effects of the blender credit program, though the tax credit program will expire in 2008 if it is not extended. Congress may later elect to extend the blender credit program following the precedence used for extending the ethanol blending subsidies. Additionally, the Small Biodiesel Blenders Tax credit program and state tax and credit programs offer some additional subsidies and credits, though the benefits are modest in comparison to the Blender's Tax credit.
Biodiesel fuel is blended into highway and nonroad diesel fuel, which increases the volume and therefore the supply of diesel fuel and thereby reduces the demand for refinery-produced diesel fuel. In this section, we estimate the overall cost impact, considering how much refinery based diesel fuel is displaced by the forecasted production volume of biodiesel fuel. The cost impacts are evaluated considering the production cost of biodiesel with and without the subsidy from the Biodiesel Blenders Tax credit program. Additionally, the diesel cost impacts are quantified with refinery diesel prices as forecasted by Jacob's which is based on EIA's AEO 2006.
We estimate the net effect that biodiesel production has on overall cost for diesel fuel in year 2012 using total production costs for biodiesel and diesel fuel. The costs are evaluated based on how much refinery based diesel fuel is displaced by the biodiesel volumes as forecasted by EIA, accounting for energy density differences between the fuels. The cost impact is estimated from a 2004 year basis, by multiplying the production costs of each fuel by the respective changes in volumes for biodiesel and estimated displaced diesel fuel. We further assume that all of the forecasted biodiesel volume is used as transport fuel, neglecting minor uses in the heating oil market.
For RFS cases, the net effect of biodiesel production on diesel fuel costs, including the biodiesel blenders' subsidy, is a reduction in the cost of transport diesel fuel costs by $114 million per year, which equates to a reduction in fuel cost of about 0.20 cents per gallon.
There are two components to the costs associated with distributing the volumes of ethanol necessary to meet the requirements of the Renewable Fuels Standard (RFS): (1) The capital cost of making the necessary upgrades to the fuel distribution infrastructure system, and (2) the ongoing additional freight costs associated with shipping ethanol to terminals. The most comprehensive study of the infrastructure requirements for an expanded fuel ethanol industry was conducted for the Department of Energy (DOE) in 2002.
The 2002 DOE study examined two cases regarding the use of renewable fuels for estimating the capital costs for distributing additional ethanol. The first assumed that 5.1 billion gal/yr of ethanol would be used in 2010, and the second assumed that 10 billion gal/yr of ethanol would be used in the 2015 timetable. We interpolated between these two cases to provide the foundation for our estimate of the capital costs to support the use of 6.7 billion gal/yr of ethanol in 2012 for the
Table VII.B.1.a-1contains our estimates of the infrastructure changes and associated capital costs for the two ethanol use scenarios examined in today's rule. Amortized over 15 years with a 7 percent cost of capital, the total capital costs equate to approximately 1.4 cents per gallon of ethanol under the RFS case and 1.2 cents per gallon under the EIA case.
The Energy Information Administration (EIA) translated the ethanol freight cost estimates in the DOE study to a census division basis.
Including the cost of capital recovery for the necessary distribution facility changes, we estimate the national average cost of distributing ethanol to be 12.7 cents per gallon under the RFS case and 13.1 cents per gallon under the EIA case.
The volume of biodiesel used by 2012 under the RFS is estimated at 300 million gallons per year. The 2012 baseline case against which we are estimating the cost of distributing the additional volume of biodiesel is 30 million gallons.
The capital costs associated with distribution of biodiesel are higher per gallon than those associated with the distribution of ethanol due to the need for storage tanks, blending systems, barges, tanker trucks and rail cars to be insulated and in many cases heated during the winter months.
In the proposal, we estimated that the freight costs for ethanol may adequately reflect those for biodiesel as well. In response to comments, we sought additional information regarding the freight costs for biodiesel. This information indicates that freight costs for biodiesel are typically 30 percent higher than those for ethanol which translates into an estimate of 15.5 cents per gallon for biodiesel freight costs on a national average basis.
Including the cost of capital recovery for the necessary distribution facility changes, we estimate the cost of distributing biodiesel to be 21.5 cents per gallon. Depending on whether the feedstock is waste grease or virgin oil, we estimate the total cost for producing and distributing biodiesel to be between $1.33 and $2.11 per gallon of biodiesel, on a nationwide average basis.
To estimate the cost of increased use of renewable fuels, the cost savings from the phase out of MTBE and the production cost of alkylate, we relied on
The baseline case was established by modeling fuel volumes for 2004, with data on fuel properties provided to the contractor by EPA. Fuel property data for this base case was built off of 2004 refinery batch reports provided to EPA; however, the base case assumed sulfur standards based on gasoline data in 2004, not with fully phased in Tier 2 gasoline standards at the 30 ppm level. In addition we assumed the phase-in of 15 ppm sulfur standards for highway, nonroad, locomotive and marine diesel fuel. The supply/demand balance for the U.S. was based on gasoline volumes from EIA and the California Air Resources Board (CARB). Our decision to use 2004 rather than 2005 as the baseline year was because of the refinery upset conditions associated with the Gulf Coast hurricanes in 2005.
The reference case was based on modeling the base case, using 2012 fuel prices, and scaling the 2004 fuel volumes to 2012 based on growth in fuel demand. In addition, we scaled MTBE and ethanol upward, in proportion to gasoline growth, and assumed the RFS program would not be in effect. For example, if the PADD 1 gasoline pool MTBE oxygen was 0.5 wt% in 2004, the reference case assumed it should remain at 0.5 wt%. Finally, we assumed the MSAT 1 standards would remain in place as would the RFG oxygen mandate. We assumed the crude slate quality in 2012 is the same as the baseline case.
Two control cases were run for 2012. The assumptions for each of the control cases are summarized below
Control Case 1 (RFS case): 6.7 billion gallons/yr (BGY) of ethanol in gasoline; it reflects the renewable fuel mandate. We have also assumed that 0.3 billion gallons of biodiesel will be consumed as reflected in Table II.A.1-1. In addition, it is assumed that no MTBE is in gasoline, MSAT1 is in place, the psi waiver for conventional gasoline containing 10 volume percent ethanol is in effect, the RFS is in effect, and there is no RFG oxygenate mandate.
Control Case 2 (EIA case): Same as Control Case 1, except the ethanol volume in gasoline is 9.6 BGY.
The estimated cost of increased use of renewable fuels, the cost savings from the phase out of MTBE and the cost of converting some of the former MTBE feedstocks to produce alkylate, isooctane, and isooctene is provided by the output of the refinery model. As described in VII.C.1, the cost analysis was conducted by comparing the 2012 reference case with the two control cases which are assumed to take place in 2012.
The major factors which impact the costs in the refinery model are (1) blending in more ethanol, (2) adjusting the gasoline blending to lower RVP, (3) removing the MTBE, (4) converting MTBE feedstocks to other high quality replacement, and (5) adjusting for the change in gasoline energy density. The first is the addition of ethanol to the gasoline pool. The refinery model estimates the cost impact of increasing the volume of ethanol in the reference case from 3.94 billion gallons to 6.67 and 9.60 billion gallons in the RFS and EIA modeled cases, respectively. The estimated production prices for ethanol for the RFS and EIA cases are provided above in Section VII.A. We also show the results with the federal and state subsidies applied to the production price of ethanol.
The addition of ethanol to wintertime gasoline, and to summertime RFG, will cause an increase of approximately 1 psi in RVP which needs to be offset to maintain constant RVP levels. One method that refiners could choose to offset the increase in RVP is to reduce the butane levels in their gasoline. To some extent, the modeling results showed some occurrences of that, but it also did not report an overall increase in butane sales as a result of the increased use of ethanol.
To convert the captive MTBE over to alkylate, after the rejection of methanol, refiners will need to combine refinery-produced isobutane with the isobutylene that was used as a feedstock for MTBE. The use of the isobutane will reduce the RVP of the gasoline pool from which it comes, helping to offset the RVP impacts of ethanol. Also, the increased production of alkylate provides a low RVP gasoline blendstock which offsets a portion of the cracked stocks produced by the fluidized catalytic cracker unit. Other means that the refinery model used to offset the high blending RVP of ethanol included purchasing gasoline components with lower RVP, producing more poly gasoline which has low RVP and selling more high-RVP naphtha to petrochemical sales.
Based on the refinery modeling conducted for today's rule, we have calculated the costs of these fuels changes that will occur for the RFS and EIA cases. The costs are expressed two different ways. First, we express the cost of the program without the ethanol consumption subsidies in which the costs are based on the total accumulated cost of each of the fuels changes. Second, we express the cost with the ethanol consumption subsidies included since the subsidized portion of the renewable fuels costs will not be represented to the consumer in its fuels costs paid at the pump, but instead by being paid through the state and federal tax revenues. In all cases, the capital costs are amortized at 7 percent return on investment (ROI), and based on 2006 dollars.
Table VII.C.3.a-1 summarizes the costs without ethanol subsidies for each of the two control cases, including the cost for each aspect of the fuel changes, and the aggregated total and the per-gallon costs for all the fuel changes.
Our analysis shows that when considering all the costs associated with these fuel changes resulting from the expanded use of subsidized ethanol that these various possible gasoline use scenarios will increase fuel costs by $820 million or $1,740 million in the year 2012 for the RFS and EIA cases, respectively. Expressed as per-gallon costs, these fuel changes would increase fuel costs by 0.50 to 1.1 cents per gallon of gasoline.
Table VII.C.3.b-1 expresses the total and per-gallon gasoline costs for the two control scenarios with the federal and state ethanol subsidies included. The federal tax subsidy is 51 cents per gallon for each gallon of new ethanol blended into gasoline. The state tax subsidies apply in 5 states and range from 1.6 to 29 cents per gallon. The cost reduction to the fuel industry and consumers is estimated by multiplying the subsidy times the volume of new ethanol estimated to be used in the state. The per-gallon costs are derived by dividing the total costs over all U.S. gasoline projected to be consumed in 2012.
The cost including subsidies better represents gasoline's production cost as reflected to the fuel industry as a whole and to consumers “at the pump” because the federal and state subsidies tend to hide a portion of the actual costs. Our analysis estimates that the fuel industry and consumers will see a 0.34 and 0.71 cent per gallon decrease in the apparent cost of producing gasoline for the RFS and EIA cases, respectively.
In this section, we evaluate the impact of increased production and use of renewable fuels on emissions and air quality in the U.S., particularly ethanol and biodiesel. In performing these analyses, we compare the emissions which would have occurred in the future if fuel quality had remained unchanged from pre-Act levels to those which will be either required under the Energy Policy Act of 2005 (Energy Act or the Act) or exist due to market forces.
This approach differs from that traditionally taken in EPA regulatory impact analyses. Traditionally, we would have compared future emissions with and without the requirement of the Energy Act. However, as described in Section II, we expect that total renewable fuel use in the U.S. in 2012 to exceed the Act's requirements even in the absence of the RFS program. Thus, a traditional regulatory impact analysis would have shown no impact on emissions or air quality. This is because, strictly speaking, if the same volume and types of renewable fuels are produced and used with and without the RFS program, the RFS program has no impact on fuel quality and thus, no impact on emissions or air quality. However, levels of renewable fuel use are increasing dramatically relative to both today and the recent past, with corresponding impacts on emissions and air quality. We believe that it is appropriate to evaluate these changes here, regardless of whether they are occurring due to economic forces or Energy Act requirements.
In the process of estimating the impact of increased renewable fuel use, we also include the impact of reduced use of MTBE in gasoline. It is the
Several models of the impact of gasoline quality on motor vehicle emissions have been developed since the early 1990's. We evaluated these models and selected those which were based on the most comprehensive set of emissions data and developed using the most advanced statistical tools for this analysis. Still, as will be described below, significant uncertainty exists as to the effect of these gasoline components on emissions from both motor vehicle and nonroad equipment, particularly from the latest vehicle and engine models equipped with the most advanced emission controls. Pending adequate funding, we plan to conduct significant vehicle and equipment testing over the next several years to improve our estimates of the impact of these additives and other gasoline properties on emissions. We hope that the results from these test programs will be available for reference in the future evaluations of the emission and air quality impacts of U.S. fuel programs required by the Act.
The remainder of this sub-section is divided into three parts. The first evaluates the impact of increased ethanol use and decreased MTBE use on gasoline quality. The second evaluates the impact of increased ethanol use and decreased MTBE use on motor vehicle emissions. The third evaluates the impact of increased ethanol use and decreased MTBE use on nonroad equipment emissions.
For the final rulemaking, we estimate the impact of increased ethanol use and decreased MTBE use on gasoline quality using refinery modeling conducted specifically for the RFS rulemaking.
The impacts of oxygenate use are smaller with respect to RFG. This is due to RFG's VOC and toxics emission performance specifications, which limit the range of feasible fuel quality values. Thus, oxygenate type or level does not consistently affect the RVP level and aromatic and benzene contents of RFG.
Table VIII.A.1.a-1 shows the fuel quality of a typical summertime, non-oxygenated conventional gasoline and how these qualities change with the addition of 10 volume percent ethanol. Similarly, the table shows the fuel quality of a typical MTBE RFG blend and how fuel quality might change with either ethanol use or simply MTBE removal. All of these fuels are based, in whole or in part, on projections made by Jacobs in their recent refinery modeling performed for EPA and therefore, represent improvements over the projections made for the NPRM. Please see Chapter 2 of the RIA for a detailed description of the methodologies used to determine the specific changes in projected fuel quality. As discussed there, we use the Jacobs model projections of RFG fuel quality directly in our emission modeling. For conventional gasoline, we use the Jacobs modeling described in Section VII to determine the change in fuel quality due to ethanol use and apply this change to base fuel quality estimates contained in EPA's NMIM emission inventory model. Sulfur is not shown in Table VIII.A.1.a-1, as it is held constant at 30 ppm, which is the average Tier 2 sulfur standard applicable to all gasoline sold in the U.S. in the timeframe of our emission analyses.
We use the EPA Predictive Models to estimate the impact of gasoline fuel quality on exhaust VOC and NO
In responding to California's request for a waiver of the RFG oxygen mandate in 2000, we found that both very limited and conflicting data were available on the effect of fuel quality on exhaust emissions from Tier 1 and later vehicles.
For the NPRM, we evaluated one recent study by the Coordinating Research Council (CRC) which assessed the impact of ethanol and two other fuel properties on emissions from twelve 2000-2004 model year vehicles (CRC study E-67). Based on comments received on the NPRM, we evaluated four additional studies of the fuel-emission effects of recent model year vehicles. The results of these test programs indicate that emissions from these late model year vehicles are likely sensitive to changes in fuel properties. However, both the size and direction of the effects are not consistent between the various studies. More testing is still needed before confident predictions of the effect of fuel quality on emissions from these vehicles can be made.
In the NPRM, we developed two sets of assumptions regarding the effect of fuel quality on emissions from Tier 1 and later vehicles to reflect this uncertainty. A primary analysis assumed that exhaust emissions from Tier 1 and later vehicles are not sensitive to fuel quality. This is consistent with our analysis of California's request for a waiver of the RFG oxygen mandate. A sensitivity analysis assumed that the NMHC and NO
The five available studies of Tier 1 and later vehicles support continuing this approach for exhaust NMHC and NO
We base our estimates of fuel quality on non-exhaust VOC and benzene emissions on the EPA MOBILE6.2 model. The one exception to this is the effect of ethanol on permeation emissions through plastic fuel tanks and elastomers used in fuel line connections. Recent testing has shown that ethanol increases permeation emissions, both by permeating itself and increasing the permeation of other gasoline components. This effect was included in EPA's analysis of California's most recent request for a waiver of the RFG oxygen requirement, but is not in MOBILE6.2.
No models are available which address the impact of gasoline quality on PM emissions. Very limited data indicate that ethanol blending might reduce exhaust PM emissions under very cold weather conditions (e.g., −20 °F to 0 °F). Very limited testing at warmer temperatures (e.g., 20 °F to 75 °F) shows no definite trend in PM emissions with oxygen content. Thus, for now, no quantitative estimates can be made regarding the effect of ethanol use on direct PM emissions.
Table VIII.A.1.b-1 presents the average per vehicle (2012 fleet) emission impacts of three types of RFG: Non-oxygenated, a typical MTBE RFG as has been marketed in the Gulf Coast, and a typical ethanol RFG which has been marketed in the Midwest.
As can be seen, all three types of RFG produce significantly lower emissions of VOC, CO and benzene than conventional gasoline. The impact of ethanol RFG on non-exhaust VOC emissions is lower than the other two types of RFG due to the impact of ethanol on permeation emissions. The impact of RFG on emissions of NO
It should be noted that these comparisons assume that all gasoline blends meet EPA's Tier 2 gasoline sulfur standard of 30 ppm. Prior to the Tier 2 program, RFG contained less sulfur than conventional gasoline and reduced NO
Historically, no non-oxygenated RFG was sold, due to the requirement that RFG contain at least 2.0 weight percent oxygen. However, with the Energy Act's removal of this requirement, all three types of RFG blends can be sold today. Increased use of ethanol in RFG would therefore either replace MTBE RFG or non-oxygenated RFG. The former has already occurred in many areas, as MTBE was essentially removed from the U.S. gasoline market by the end of 2006. The impact of using ethanol in RFG in lieu of MTBE or no oxygenate can be seen from comparing the relative impacts of the various RFG blends shown in Table VIII.A.1.b-1.
Blending RFG with ethanol instead of MTBE or no oxygenate will increase VOC and NO
Table VIII.A.1.b-2 presents the effect of blending either MTBE or ethanol into conventional gasoline while matching octane.
Use of either oxygenate reduces exhaust VOC and CO emissions, but increases NO
The exhaust emission effects shown above for VOC and NO
We received several comments related to the effect of ethanol on emissions from onroad vehicles. None of the comments led us to change the basic approach taken to estimating the impact of changing fuel quality described above. Several comments suggested that we expand our discussion of the uncertainty in these fuel effects (as well as the effects of fuel quality on emissions from nonroad equipment and diesels described below). While such an expanded discussion might be generally desirable, the lack of relevant emission data from late model vehicles and equipment prevents this. We believe that we have adequately described the uncertainty in the emission estimates presented below and our plans to obtain more data in order to improve these estimates in the near future.
To estimate the effect of gasoline quality on emissions from nonroad equipment, we used EPA's NONROAD emission model. We used the 2005 version of this model, NONROAD2005, which includes the effect of ethanol on permeation emissions from most nonroad equipment.
Only sulfur and oxygen content affect exhaust VOC, CO and NO
As can be seen, higher oxygen content reduces exhaust VOC and CO emissions significantly, but also increases NO
Evaporative emissions from nonroad equipment are impacted by only RVP, and permeation by ethanol content. Both the RVP increase due to blending of ethanol and its permeation effect cause non-exhaust VOC emissions to increase with the use of ethanol in nonroad equipment. The 26 percent effect represents the average impact across the U.S. in July for both 2-stroke and 4-stroke equipment. We updated the NONROAD2005 hose permeation emission factors for small spark-ignition engines and recreational marine watercraft to reflect the use of ethanol.
For nonroad toxics emissions, we base our estimates of the impact of fuel quality on the fraction of exhaust VOC emissions represented by each toxic on MOBILE6.2 (i.e., the same effects predicted for onroad vehicles). The National Mobile Inventory Model (NMIM) contains estimates of the fraction of VOC emissions represented by the various air toxics based on oxygenate type (none, MTBE or ethanol). However, estimates for nonroad gasoline engines running on different fuel types are limited, making it difficult to accurately model the impacts of changes in fuel quality. In the recent final rule addressing mobile air toxic emissions, EPA replaced the toxic-related fuel effects contained in NMIM with those from MOBILE6.2 for onroad vehicles.
EPA assessed the impact of biodiesel fuel on emissions in 2002 and published a draft report summarizing the results.
While the conclusions reached in the 2002 EPA report relative to biodiesel effects on VOC, CO and PM emissions have been generally accepted, the magnitude of the B20 effect on NO
Areas experiencing increased renewable production will experience the corresponding emission increases associated with their production. The primary impact of renewable fuel production and distribution regards ethanol, since it is expected to be the predominant renewable fuel used in the foreseeable future. We approximate the impact of increased ethanol and biodiesel production, including corn and soy farming, on emissions based on DOE's GREET model, version 1.7. In addition, we develop a second estimate of emissions from ethanol production facilities using estimates of emissions from current ethanol plants obtained from the States. We also include emissions effects resulting from the transport of increased volumes of renewable fuels and decreased volumes of gasoline and diesel fuel. These emissions are summarized in Table VIII.A.3-1.
At the same time, areas with refineries might experience reduced emissions, not necessarily relative to current emission levels, but relative to those which would have occurred in the future had renewable fuel use not risen. However, to the degree that increased renewable fuel use reduces imports of gasoline and diesel fuel, as opposed to the domestic production of these fuels, these reduced refinery emissions will occur overseas and not in the U.S.
Similarly, areas with MTBE production facilities might experience reduced emissions from these plants as they cease producing MTBE. However, many of these plants may be converted to produce other gasoline blendstocks, such as iso-octane or alkylate. In this case, their emissions are not likely to change substantially.
We use the NMIM to estimate emissions under the various ethanol scenarios on a county by county basis. NMIM basically runs MOBILE6.2 and NONROAD2005 with county-specific inputs pertaining to fuel quality, ambient conditions, levels of onroad vehicle VMT and nonroad equipment usage, etc. We ran NMIM for two months, July and January. We estimate annual emission inventories by summing the two monthly inventories and multiplying by six.
As described above, we removed the effect of gasoline fuel quality on exhaust VOC and NO
The national emission inventories for VOC, CO and NO
Both
CO also participates in forming ozone, much like VOCs. Generally, CO is 15-50 times less reactive than typical VOC. Still, the reduction in CO emissions is roughly 27-32 times the increase in VOC emissions in the two scenarios. Thus, the projected reduction in CO emissions is important from an ozone perspective. However, as described above, the methodology for projecting the effect of ethanol use on CO emissions is inconsistent with that for exhaust VOC and NO
There will also be some increases in emissions due to ethanol and biodiesel production. Table VIII.B.1-2 shows estimates of annual emissions expected to occur nationwide due to increased production of ethanol. These estimates include a reduction in emissions related to the distribution of the displaced gasoline. The table reflects the use of
As can be seen, the potential increases in emissions from ethanol production and transportation are of the same order of magnitude as those from ethanol use, with the exception of CO emissions. The vast majority of these emissions are related to farming and ethanol production. Both farms and ethanol plants are generally located in ozone attainment areas.
Where counties are constructing new ethanol plants, expanding existing plants, or planning construction for future plants, the average increase in VOC and NO
Table VIII.B.1-3 shows estimates of annual emissions expected to occur nationwide due to increased production of biodiesel. These estimates include a reduction in emissions related to the distribution of the displaced diesel fuel. Again, these emissions are generally expected to be in ozone attainment areas.
The national emission inventories for VOC and NO
The overall VOC and NO
We also estimate the percentage change in VOC, NO
Table VIII.B.3-1 presents our primary estimates of the percentage change in VOC, NO
As expected, increased ethanol use tends to increase NO
Table VIII.B.3-2 presents the percentage change in VOC, NO
Directionally, the changes in VOC and NO
We estimate the impact of increased ethanol use on the ambient concentrations of two pollutants: Ozone and PM. Quantitative estimates are made for ozone, while only qualitative estimates can be made currently for ambient PM. These impacts are described below.
We use a metamodeling tool developed at EPA, the ozone response surface metamodel (Ozone RSM), to estimate the effects of the projected changes in emissions from gasoline vehicles and equipment for the RFS and EIA cases. We included the estimated changes in emissions from renewable fuel production and distribution. Because of limitations in the Ozone RSM, we could not easily assign these emissions to the specific counties where the plants are or are expected to be located. Instead, we assigned all of the emissions related to renewable fuel production and distribution to the set of states expected to contain most of the production facilities.
The Ozone RSM was created using multiple runs of the Comprehensive Air Quality Model with Extensions (CAM
The Ozone RSM limits the number of geographically distinct changes in VOC and NO
As can be seen, ozone levels generally increase to a small degree with increased ethanol use. This is likely due to the projected increases in both VOC and NO
In our sensitivity analysis, where exhaust emissions from Tier 1 and later onroad vehicles are assumed to respond to ethanol like Tier 0 vehicles, the population-weighted increase in ambient ozone levels is slightly less than twice as high, or 0.272-0.315 ppb. This increase represents about 0.35 percent of the standard.
There are a number of important caveats concerning these estimates. First, the emission effects of adding ethanol to gasoline are based on extremely limited data for recent vehicles and equipment. Second, the Ozone RSM does not account for changes in CO emissions. As shown above, ethanol use should reduce CO emissions significantly, directionally reducing ambient ozone levels in those areas where ozone formation is VOC-limited. (Ozone levels in areas which are NO
We received several requests in comments on the proposal to quantify the impact of the reduced CO emissions
Moving to health effects, exposure to ozone has been linked to lung function decrements, respiratory symptoms, aggravation of asthma, increased hospital and emergency room visits, increased asthma medication usage, inflammation of the lungs, and a variety of other respiratory effects and cardiovascular effects including premature mortality. Ozone can also adversely affect the agricultural and forestry sectors by decreasing yields of crops and forests. Although the health and welfare impacts of changes in ambient ozone levels are typically quantified in regulatory impact analyses, we do not evaluate them for this analysis. On average, the changes in ambient ozone levels shown above are small and would be even smaller if changes in CO emissions and VOC reactivity were taken into account. The increase in ozone would likely lead to negligible monetized impacts. We therefore do not estimate and monetize ozone health impacts for the changes in renewable use due to the small magnitude of this change, and the uncertainty present in the air quality modeling conducted here, as well as the uncertainty in the underlying emission effects themselves discussed earlier.
Ambient PM can come from two distinct sources. First, PM can be directly emitted into the atmosphere. Second, PM can be formed in the atmosphere from gaseous pollutants. Gasoline-fueled vehicles and equipment contribute to ambient PM concentrations in both ways.
As described above, we are not currently able to predict the impact of fuel quality on direct PM emissions from gasoline-fueled vehicles or equipment. Therefore, we are unable at this time to project the effect that increased ethanol use will have on levels of directly emitted PM in the atmosphere.
PM can also be formed in the atmosphere (termed secondary PM here) from several gaseous pollutants emitted by gasoline-fueled vehicles and equipment. Sulfur dioxide emissions contribute to ambient sulfate PM. NO
The formation of secondary organic PM is very complex, due in part to the wide variety of VOCs emitted into the atmosphere. The degree to which a specific gaseous VOC reacts to form PM in the atmosphere depends on the types of reactions that specific VOC undergoes and the products of those reactions. Both of these factors depend on other pollutants present, such as the hydroxyl radical, ozone, NO
Recent smog chamber studies have indicated that gaseous aromatic VOCs can form secondary PM under certain conditions. These compounds comprise a greater fraction of exhaust VOC emissions than non-exhaust VOC emissions, as non-exhaust VOC emissions are dominated by VOCs with relatively high vapor pressures. Aromatic VOCs tend to have lower vapor pressures. As increased ethanol use is expected to reduce exhaust VOC emissions, emissions of aromatic VOCs should also decrease. In addition, refiners are expected to reduce the aromatic content of gasoline by 5 volume percentage points as ethanol is blended into gasoline. Emissions of aromatic VOCs should decrease with lower concentrations of aromatics in gasoline. Thus, emissions of gaseous aromatic VOCs could decrease for both reasons.
Overall, we expect that the decrease in secondary organic PM is likely to exceed the increase in secondary nitrate PM. In 1999, NO
EPA currently utilizes the CMAQ model to predict ambient levels of PM as a function of gaseous and PM emissions. This model includes mechanisms to predict the formation of nitrate PM from NO
Renewable fuels have been of significant interest for many years due to their potential to displace fossil fuels, which have often been targeted as primary contributors to emissions of greenhouse gases such as carbon dioxide, and national energy concerns primarily due to an increasing dependence on foreign sources of petroleum. In the Notice of Proposed Rulemaking, we provided a preliminary assessment of the greenhouse gas emission and energy impacts of renewable fuel and an initial assessment of the economic value of renewable fuel displacing petroleum-based fuels. We
We also performed a full lifecycle or well-to-wheel analysis for this final rule to estimate the GHG and fossil energy reductions from replacing petroleum based fuels with renewable fuels. Argonne National Laboratory's (ANL) GREET
As noted in Section III, although we have chosen to base our lifecycle analyses on Argonne National Laboratory's GREET model there are a variety of other lifecycle models and analyses available. The choice of model inputs and assumptions all have a bearing on the results of lifecycle analyses, and many of these assumptions remain the subject of debate among researchers. Lifecycle analyses must also contend with the fact that the inputs and assumptions generally represent industry-wide averages even though energy consumed and emissions generated can vary widely from one facility or process to another.
There currently exists no organized, comprehensive dialogue among stakeholders about the appropriate tools and assumptions behind any lifecycle analyses. We will be initiating more comprehensive discussions about lifecycle analyses with stakeholders in the near future.
We used the petroleum energy reductions shown in Table IX-1 to determine implications on imports of petroleum products. Our analysis found that calculated petroleum energy reductions come almost entirely from imports of finished products in this 2012 case and amount to the equivalent of 123,000 barrels of transportation fuel under the RFS case and 240,000 barrels of transportation fuel for the EIA case.
Another effect of increased use of renewable fuels in the U.S. is that it diversifies the energy sources in making transportation fuel. Diverse sources of fuel energy reduce both financial and strategic risks associated with a potential disruption in supply or a spike in cost of a particular energy source. This reduction in risks is a measure of improved energy security. The ORNL report used an “oil premium” approach to identify those energy-security related impacts which are not reflected in the market price of oil, and which are expected to change in response to an incremental change in the level of U.S. oil imports.
The following sections provide a more complete description of our analyses of the GHG emissions, fossil fuel, oil imports, and energy security impacts of this final rule.
Although the use of renewable fuels in the transportation sector directly displaces some petroleum consumed as motor vehicle fuel, this displacement of petroleum is in fact only one aspect of the overall impact of renewable fuels on fossil fuel use. Fossil fuels are also used in producing and transporting renewable feedstocks such as plants or animal byproducts, in converting the renewable feedstocks into renewable fuel, and in transporting and blending the renewable fuels for consumption as motor vehicle fuel. To estimate the true impacts of increases in renewable fuels on fossil fuel use, modelers attempt to take many or all these steps into account.
Similarly, energy is used and GHGs emitted in the pumping of oil, transporting the oil to the refinery, refining the crude oil into finished transportation fuel, transporting the refined gasoline or diesel fuel to the consumer and then burning the fuel in the vehicle. Such analyses are termed lifecycle or well-to-wheels analyses. We performed a full lifecycle analysis as part of this final rulemaking to determine the GHG and fossil energy reductions from the increased use of renewable fuels.
This lifecycle assessment approach and rationale were highlighted in the proposal. Comments received focused mainly on improving the process, for example the choice of lifecycle model used and initiating a stakeholder dialogue to build consensus around the assumptions and approach. In general comments were supportive of using a full lifecycle assessment approach, but differed on the appropriate model and associated assumptions EPA should use in its analysis.
The results presented in this analysis represent a snapshot in time. They represent annual GHG and fossil fuel savings in the year considered, in this case 2012. Consistent with the emissions modeling described in Section VII, our analysis of the GHG and fossil fuel consumption impacts of renewable fuel use was conducted using three volume scenarios. The first scenario was the same reference case used elsewhere in this final rulemaking. The reference case scenario provided the point of comparison for the other two scenarios. The other two renewable fuel scenarios for 2012 represented the
In both the RFS and EIA scenarios, we assumed that the biodiesel production volume would be 0.303 billion gallons based on EIA AEO2006 projections. Furthermore, for both scenarios we assume that 250 million gallons of ethanol that qualify for cellulosic biomass ethanol credit will be produced in 2012 from corn using biomass as the process energy source. The remaining renewable fuel volumes in each scenario would be ethanol made from corn and imports. The import volume is based on EIA's projections for the percent of total ethanol volume supplied by imports in 2012. The total volumes for all three scenarios are shown in Table II.A.1-1.
For the purposes of calculating this difference or the amount of conventional fuel no longer consumed—that is, displaced—as a result of the use of the replacement renewable fuel, we assumed the ethanol volumes shown in Table II.A.1-1 are 5% denatured. The ethanol volumes were adjusted down to represent pure (100%) ethanol, biodiesel volumes were not adjusted. The adjusted volumes were then converted to total Btu using the appropriate volumetric energy content values (76,000 Btu/gal for ethanol, 115,000 Btu/gal for gasoline, 118,000 Btu/gal for biodiesel, and 130,000 Btu/gal for diesel fuel). We make the assumption that vehicle energy efficiency will not be affected by the presence of renewable fuels (i.e., efficiency of combusting one Btu of ethanol is equal to the efficiency of combusting one Btu of gasoline).
This lifecycle analysis is conducted without any regard to the geographic attributes of where emissions or energy use occurs; the model represents global reductions in GHG emissions and energy use, not just those occurring in the U.S. For example, under a full lifecycle assessment approach, the savings associated with reducing overseas crude oil extraction and refining are included, as are the international emissions associated with producing imported ethanol. There were two exceptions to this, both dealing with secondary impacts that may result internationally due to the expanded use of renewable fuels within the United States.
The first exception is the emissions associated with international land use change. Due to decreasing corn exports some changes to international land use may occur, for example, as more crops are planted in other regions to compensate for the decrease in crop exports from the U.S. While the emissions associated with domestic land use change are well understood and are included in our lifecycle analysis, we did not include the potential impact on international land use and any emissions that might directly result. Our currently modeling capability does not allow us to assess what international land use changes would occur or how these changes would affect greenhouse gas emissions. For example, we would need to know how international cropping patterns would change as well as farming inputs and practices that might affect emissions assessment.
The second case where we have not quantified the international impacts results from any reduction in world oil prices would tend to result from decreased demand in the U.S. as renewable fuels replace oil. It is commonly presumed in economic analyses that all else being equal quantity demanded of a valuable good (i.e., oil) will increase as price decreases. A world wide reduction of oil price would tend to reduce the cost of producing transportation fuel which in turn would tend to reduce the price consumers internationally would have to pay for this fuel.
To the extent fuel prices are decreased, demand and consumption would tend to increase; this impact of reduced cost of driving is sometimes referred to as a “rebound effect.” Such a greater consumption internationally would presumably result in an increase in greenhouse gas emissions as consumers in the rest of the world drive more. These increased emissions would in part offset the emission impacts otherwise described in this preamble. While such international impacts of U.S. actions are important to understand, we have not have fully considered and quantified the international rebound effects of this renewable fuel standard. Nevertheless, such impacts remain an important consideration for future analysis.
As in the analyses for the proposal, for this final rulemaking we used the GREET fuel-cycle model. GREET has been under development for several years and has undergone extensive peer review through multiple updates. Of the available sources of information on lifecycle analyses of energy consumed and emissions generated, we believe that GREET offers the most comprehensive treatment of the transportation sector. For this final rule, we used an updated version of the GREET model
The two main comments we received on our lifecycle modeling were that we should initiate a public dialogue on lifecycle analyses, models and assumptions, and that our sole reliance on the GREET model should be avoided, given other models are available. We have begun a public dialogue in that we identify the assumptions in the GREET model that were examined and modified for this final rulemaking. Furthermore, we will be initiating more comprehensive discussions about lifecycle analysis with stakeholders which could lead to an increased use of lifecycle analysis in future actions.
In terms of our sole reliance on the GREET model, several other models have been developed for conducting renewable fuels lifecycle analysis. For example, researchers at the Energy and Resources Group (ERG) of the University of California Berkeley have developed the ERG Biofuel Analysis Meta-Model (EBAMM) and Mark Delucchi at the Institute of Transportation Studies of the University of California Davis has developed the Lifecycle Emissions Model (LEM). Other non-fuel specific lifecycle modeling tools could also be used to perform renewable fuel lifecycle analysis.
Several studies have been released recently making use of these other models and showing different results than we find in the analysis done for this rule. For example, whereas GREET estimates a net GHG reduction of about 22% for corn ethanol compared to gasoline, the previously cited works by Farrell et al. utilizing the EBAMM show around a 13% reduction. The main difference in results is not due to the model used but assumptions on scope and input data.
For example, most studies focus on average or current ethanol production which uses a current mix of wet and dry mill ethanol production and use of coal and natural gas as process energy. In contrast, for this rulemaking we consider future increases in renewable fuel production so we focus on new production capacity which will rely more heavily on more efficient dry mill production than the current mix of wet and dry mill capacities. Other studies also typically base ethanol and farm energy use on historic data while we are assuming future capacity increases will use a state of the art dry milling plant and most current farming energy use
We have not had an opportunity to develop comparable analyses of the GHG and energy impacts of this rule using these other models. However, as discussed in chapters 6.1.1 and 6.2.3 of the RIA, we believe the scope of the GREET model and the assumptions we have used in running the model tend toward the middle of the range. Therefore we believe these results provide a reasonable assessment of the energy and GHG impacts of the expanded use of renewable fuels.
The feedstocks and processes used to model renewable fuel production were those which our analysis in Chapter 1 of the RIA shows will primarily be used through 2012. However, other pathways for producing renewable fuels may become popular such as producing cellulosic biomass ethanol from municipal solid waste as well as different process for the feedstocks considered, like gasification of switchgrass and production of “renewable” diesel fuel through hydrotreating vegetable oils.
Furthermore, the lifecycle analysis used for this rulemaking is based on averages of the different renewable fuels modeled. For example, the GHG emission and fossil energy savings associated with increased use of corn ethanol are calculated based on a mix of corn wet and dry milling, assuming a certain projected mix of each process. While this method may not exactly represent the reductions associated with a given gallon of renewable fuel, it is accurate for the purpose of this analysis which is to determine the impact of the total increased volume of renewable fuels used.
We recognize that different feedstocks and processes will each have unique characteristics when it comes to lifecycle GHG emissions and energy use. However, we understand that other feedstocks and processes as well as differences in other parts of the renewable fuel lifecycle will impact the savings associated with their use and this is the focus of ongoing work at the agency.
Since the analysis done for the NPRM, we have updated the GREET model with the following changes:
In addition to the changes listed above we also examined and updated other GREET input assumptions for corn ethanol and biodiesel production.
We also examined several other GREET input values, but determined that the default GREET values should not be changed for a variety of reasons. These included, corn and ethanol transport distances and modes and byproduct allocation methods. Our investigation of these other GREET input values are discussed more fully in Chapter 6 of the RIA. The current GREET default factors for these other inputs were included in the analysis for this final rule.
We did not investigate the input values associated with the production of petroleum-based gasoline or diesel fuel in the GREET model for this final rule. However, the refinery modeling discussed in Section VII provides some additional information on the process energy requirements associated with the production of gasoline and diesel under a renewable fuels mandate. We will use information from this refinery modeling in future analysis to determine if any GREET input values should be changed.
A summary of the GREET input values we investigated and modified for the final rule analysis is given below.
As mentioned above, the results of lifecycle analysis are highly dependent on the input data assumptions used. Section IX.A.1.b outlined changes made to the GREET model inputs to better represent the scope and purpose of our analysis for this rulemaking. However, we also performed several sensitivity analyses on some key assumptions to see how varying them would impact overall results.
We performed a sensitivity analysis on expanding the lifecycle fuel production system boundaries to include farm equipment production (e.g., emissions and energy use associated with producing steel, rubber, etc. used to make farming equipment). It was found that including farm equipment production energy use and emissions increases ethanol lifecycle energy use and GHG emissions by approximately 1 percent. Therefore, the lifecycle results are not changed significantly due to this expansion of system boundaries.
We also performed a sensitivity analysis on the allocation method used in ethanol production. A number of by-products are made during the production of ethanol. In lifecycle analyses, the energy consumed and emissions generated by an ethanol plant must be allocated not only to ethanol, but also to each of the by-products. There are a number of methods that can be used to estimate by-product allocations. The displacement method for by-product allocation, described in Section 6.1.2.10 of the RIA, is the default for the GREET model and is the method used by EPA. However, we evaluated another method, the process energy approach, to determine the impact this assumption has on the overall results of the analysis.
Use of the process energy based allocation method reduces ethanol lifecycle energy use and GHG emissions by approximately 30 percent compared to the displacement allocation approach. This indicates that ethanol lifecycle analysis results are extremely sensitive to the choice of allocation method used. (See the RIA, Chapter 6 for more information on these two by-product allocation methods) The displacement allocation method is the method supported by international lifecycle assessment standards
The displacement index (DI) represents the percent reduction in GHG emissions or fossil fuel energy brought about by the use of a renewable fuel in comparison to the conventional gasoline or diesel that the renewable fuel replaces. The formula for calculating the displacement index depends on which fuel is being displaced (i.e. gasoline or diesel), and which endpoint is of interest (e.g. petroleum energy, GHG). For instance, when investigating the CO
The units of g/Btu ensure that the comparison between the renewable fuel and the conventional fuel is made on a common basis, and that differences in the volumetric energy content of the fuels is taken into account. The denominator includes the CO
The combustion of biomass-based fuels, such as ethanol from corn and woody crops, generates CO
Using GREET, we calculated the lifecycle values for energy consumed and GHGs produced for corn-ethanol, cellulosic ethanol, and soybean-based biodiesel. These values were in turn used to calculate the displacement indexes. The results are shown in Table IX.A.3-1. Details of these calculations can be found in Chapter 6 of the RIA.
The displacement indexes in this table represent the impact of replacing a Btu of gasoline or diesel with a Btu of renewable fuel. Thus, for instance, for every Btu of gasoline which is replaced by corn ethanol, the total lifecycle GHG emissions that would have been produced from that Btu of gasoline would be reduced by 21.8 percent. For every Btu of diesel which is replaced by biodiesel, the total lifecycle petroleum energy that would have been consumed as a result of burning that Btu of diesel fuel would be reduced by 91.2 percent.
Consistent with the cost modeling done for this rule, for the 2012 cases we assume the “cellulosic” ethanol volume is actually produced from corn utilizing a biomass fuel source at the ethanol production plant. The displacement index for that fuel as shown in Table IX.A.3-1 is used in the calculation of reductions. We have included the column for cellulosic ethanol for comparison, indicating that a move toward cellulosic ethanol will not displace petroleum much differently than other renewable fuels but will have a positive impact on GHG emissions reductions.
For imported ethanol, it is more difficult to estimate the lifecycle energy and GHG displacement indexes since we know much less about how the crops used to make the ethanol are grown and what energy is used in the ethanol production facility. While not exclusively, we anticipate much imported ethanol to be primarily sugarcane based ethanol.
The GHG emissions when producing sugarcane ethanol differs from corn ethanol in that the GHG emissions from growing sugarcane is likely different than for growing a equivalent amount of corn to make a gallon of ethanol. Also, the process of turning sugar into ethanol is easier than when starting with starch and therefore less energy intensive (which typically translates into lower GHG). Importantly, we understand that at least some of the ethanol produced in Brazil uses the bagasse from the sugarcane itself as a process fuel source. We know from our analysis that using a biomass source for process energy greatly improves the GHG benefit of the renewable fuel. These factors would result in sugarcane ethanol having a greater GHG benefit per gallon than corn ethanol, certainly where natural gas or coal is the typical process fuel source used.
Conversely, sugarcane ethanol production does not result in a co-product such as distillers grain as in the case of corn ethanol. In our analyses, accounting for co-products significantly improved the GHG displacement index for corn ethanol. Furthermore, there would be additional transportation emissions associated with transporting the imported ethanol to the U.S. as compared to domestically produced ethanol. Developing a technically rigorous lifecycle estimate for energy needs and GHG impacts for imported ethanol is not a simple task and was not available in the timeframe of this rulemaking.
Considering all of the differences between imported and domestic ethanol, for this rulemaking, we assumed imported ethanol would be predominately from sugarcane and have estimated DI's approximately mid-way between the DI's for corn ethanol and DI's for cellulosic ethanol. We are continuing to develop a better understanding of the lifecycle energy and GHG impacts of producing ethanol from sugarcane and other likely feedstock sources of imported ethanol for any future analysis.
We used the methodology described above to evaluate impacts of increased use of renewable fuels on consumption of petroleum and fossil fuels and also on emissions of CO
We estimated the reduction associated with the increased use of renewable fuels on lifecycle emissions of CO
We estimated the reduction associated with the increased use of renewable fuels on lifecycle fossil fuels and petroleum. These values are then compared to the U.S. transportation sector emissions to get a percent reduction. The estimates for the 2012 cases are presented in Table IX.A.4.b-1.
In the proposal, we estimated the impact of expanded renewable fuel use on the importation of oil and finished transportation fuel. No comments were received suggesting alternative methodologies should be used. Therefore, we have incorporated that calculation in this final rule without change.
In 2005, the United States imported almost 60 percent of the oil it consumed. This compares to just over 35 percent of oil from imports in 1975.
To assess the impact of the RFS program on petroleum imports, we estimate the fraction of domestic consumption derived from foreign sources using results from the AEO 2006. We compared the levels and mix of imports in the AEO reference case with those in the low macroeconomic growth case and high oil price case. In Section 6.4.1 of the RIA we describe in greater detail how fuel producers may change their levels and mix of imports in response to a decrease in fuel demand. For the purposes of this rulemaking, we show values for the low macroeconomic growth comparison, where import reductions come almost entirely from imports of finished products as shown below in Table IX.B-1. The reductions in imports are compared to the AEO projected levels of net petroleum imports. The range of reductions in net petroleum imports are estimated to be between 0.9 to 1.7 percent, as shown in Table IX.B-1.
We also calculate the change in expenditures in both petroleum and ethanol imports and compare these with the U.S. trade position measured as U.S. net exports of all goods and services economy-wide. The decreased expenditures were calculated by multiplying the changes in gasoline, diesel, and ethanol imports by the respective AEO 2006 wholesale gasoline, distillate, and ethanol price forecasts for the specific analysis years. In Table IX.B-2, the net expenditures in reduced petroleum imports, increased ethanol imports, and decreased corn exports are compared to the total value of U.S. net exports of goods and services for the whole economy for 2012. Relative to the 2012 projection, the avoided expenditures due to the RFS would represent 0.4 to 0.7% of economy-wide net exports.
One of the effects of increased use of renewable fuels in the U.S. from the RFS is that it diversifies the energy sources in making transportation fuel. A potential disruption in supply reflected in the price volatility of a particular energy source carries with it both financial as well as strategic risks. These risks can be reduced to the extent that diverse sources of fuel energy reduce the dependence on any one source. This reduction in risks is a measure of improved energy security.
At the time of the proposal, EPA stated that an analysis would be completed and estimates provided in support of this rule. In order to understand the energy security implications of the RFS, EPA has worked with Oak Ridge National Laboratory (ORNL), which has developed approaches for evaluating the social costs and energy security implications of oil use. In a new study produced for the RFS, entitled
The approach developed by ORNL estimates the incremental benefits to society, in dollars per barrel, of reducing U.S. oil imports, called “oil premium.” Since the 1997 publication of this report, changes in oil market conditions, both current and projected, suggest that the magnitude of the oil premium has changed. Significant driving factors that have been revised include: Oil prices, current and anticipated levels of OPEC production, U.S. import levels, the estimated responsiveness of regional oil supplies and demands to price, and the likelihood of oil supply disruptions. For this analysis, oil prices from the EIA's AEO 2006 were used. Using the “oil premium” approach, estimates of benefits of improved energy security from reduced U.S. oil imports from increased use of renewable fuels are calculated.
In conducting this analysis, ORNL considered the full economic cost of importing petroleum into the U.S. The full economic cost of importing petroleum into the U.S. is defined for this analysis to include two components in addition to the purchase price of petroleum itself. These are: (1) The higher costs for oil imports resulting from the effect of U.S. import demand on the world oil price and OPEC market power (i.e., the so called “demand” or “monoposony” costs); and (2) the risk of reductions in U.S. economic output and disruption of the U.S. economy caused by sudden disruptions in the supply of imported oil to the U.S. (i.e., macroeconomic disruption/adjustment costs).
The first component of the full economic costs of importing petroleum into the U.S. follows from the effect of U.S. import demand on the world oil price over the long-run. Because the U.S. is a sufficiently large purchaser of foreign oil supplies, its purchases can affect the world oil price. This monopsony power means that increases in U.S. petroleum demand can cause the world price of crude oil to rise, and conversely, that reduced U.S. petroleum demand can reduce the world price of crude oil. Thus, one consequence of decreasing U.S. oil purchases due to increased use of renewable fuel is the potential decrease in the crude oil price paid for all crude oil purchased.
The second component of the external economic costs resulting from U.S. oil imports arises from the vulnerability of the U.S. economy to oil shocks. The cost of shocks depends on their likelihood, size, and length, the capabilities of the market and U.S. Strategic Petroleum Reserve (SPR), the largest stockpile of government-owned emergency crude oil in the world, to respond, and the sensitivity of the U.S. economy to sudden price increases. While the total vulnerability of the U.S. economy to oil price shocks depends on the levels of both U.S. petroleum consumption and imports, variation in import levels or demand flexibility can affect the magnitude of potential increases in oil price due to supply disruptions. Disruptions are uncertain events, so the costs of alternative possible disruptions are weighted by disruption probabilities. The probabilities used by the ORNL study are based on a 2005 Energy Modeling Forum
The last often-identified component of the full economic costs of U.S. oil
U.S. military costs are excluded from the analysis performed by ORNL because their attribution to particular missions or activities is difficult. Most military forces serve a broad range of security and foreign policy objectives. Attempts to attribute some share of U.S. military costs to oil imports are further challenged by the need to estimate how those costs might vary with incremental variations in U.S. oil imports. Similarly, while the costs for building and maintaining the SPR are more clearly related to U.S. oil use and imports, historically these costs have not varied in response to changes in U.S. oil import levels. Thus, while SPR is factored into the ORNL analysis, the cost of maintaining the SPR is excluded.
As stated earlier, we have placed the draft report in the docket of this rulemaking for the purposes of inviting further consideration. However, the draft results of that report have not been used in quantifying the impacts of this rule.
As described in the Notice of Proposed Rulemaking (NPRM), we used the Forest and Agricultural Sector Optimization Model (FASOM) developed by Professor Bruce McCarl of Texas A&M University and others, to estimate the agricultural sector impacts of increasing renewable fuel volumes required by the RFS and for those volumes anticipated by EIA for 2012. Although current renewable fuel volume predictions are higher than the scenarios described in this rulemaking, we based our analysis on assumptions developed during the NPRM process. Our agricultural sector analysis considered the impacts of the domestic production of renewable fuels. Therefore, when we refer to either the RFS Case or the EIA Case, we include only renewable fuels produced from feedstocks grown in the U.S.
At the time the NPRM was published, we had not yet finished our analysis of the agricultural impacts associated with the RFS. In the NPRM, we stated our intent to have the analysis completed in time for the Final Rulemaking (FRM). In the proposal we described our plan to evaluate the effect of increasing renewable fuels volumes on U.S. commodity prices, renewable fuel byproduct prices, livestock feed sources, land use, exports, and farm income. The results of this analysis are summarized in this section. Additional details are included in the Regulatory Impact Analysis (RIA).
FASOM is a long-term economic model of the U.S. agriculture sector that attempts to maximize total revenues for producers while meeting the demands of consumers. Using a number of inputs, FASOM estimates which crops, livestock, and processed agricultural products will be produced in the U.S. The cost of these and other inputs are used to determine the price and level of production of commodities (e.g., field crops, livestock, and biofuel products). FASOM does not capture short-term fluctuations (i.e., month-to-month, annual) in prices and production, however, as it is designed to identify long-term trends (i.e., five to ten years).
FASOM predicts that as renewable fuel volumes increase, corn prices will rise by about 18 cents (RFS Case) and 39 cents (EIA Case) above the Reference Case price of $2.32 per bushel. For consistency, all of the dollar estimates are presented in 2004 dollars. Soybean prices will rise by about 18 cents (RFS Case) and 21 cents (EIA Case) above the Reference Case price of $5.26 per bushel by 2012. Since biodiesel volumes will not increase significantly in either the RFS or EIA scenarios, FASOM does not predict significant changes in the soybean related markets with respect to usage changes, or most other variables of interest for this rulemaking. The one exception is U.S. soybean exports, which are affected modestly.
Changes in corn use can be seen by the changing percentage of corn used for ethanol. In 2005, approximately 12 percent of the corn supply was used for ethanol production, however we estimate the amount of corn used for ethanol in 2012 will increase to 20 percent (RFS Case) and 26 percent (EIA Case).
The rising price of corn and soybeans has a direct impact on how corn is used. Higher domestic corn prices lead to lower U.S. exports as the world markets shift to other sources of these products or expand the use of substitute grains. FASOM estimates that U.S. corn exports will drop from about 2 billion bushels in our Reference Case, to 1.6 billion bushels (RFS Case) and 1.3 billion bushels (EIA Case) by 2012. U.S. exports of corn are estimated to drop by about 19 percent by 2012 for the RFS Case and by roughly 38 percent in the EIA Case. In value terms, U.S. exports of corn fall by $573 million in the RFS Case and by $1.29 billion in the EIA Case in 2012.
The impact on domestic livestock feed due to higher corn prices and higher U.S. demand for corn in ethanol is also partially offset by decreasing the use of corn for U.S. livestock feed. Substitutes are available for corn as a feedstock, and this market is price sensitive. One alternate feedstock is distillers dried grains with solubles (DDGS), a byproduct associated with the dry milling of ethanol production. Since FASOM predicts relatively flat prices for DDGS across all ethanol volume scenarios, the result is a significant increase in the use of DDGS as a feed source. We estimate DDGS in feed for the RFS case will almost double by 2012, increasing from 8.5 million tons to 15.2 million tons. Under the EIA Case, we expect DDGS to increase to 22.2 million tons by 2012.
The increase in soybean prices is estimated to cause a decline in U.S. soybean exports. In terms of export earnings, U.S. exports of soybeans fall by $220 million in the RFS Case and by $194 million in the EIA Case in 2012.
The increase in renewable fuel production provides a significant increase in net farm income to the U.S. agricultural sector. FASOM predicts that in 2012, net U.S. farm income will increase by $2.6 billion dollars in the RFS renewable fuel volumes case (RFS Case) and $5.4 billion in the EIA renewable fuel volumes case (EIA Case). The RFS and EIA farm revenue increases represent roughly a 5 and 10 percent increase, respectively, in U.S. net farm income from the sale of farm commodities over the Reference Case of roughly $53 billion.
Higher corn prices will have a direct impact on the value of U.S. agricultural land. As demand for corn and farm products increases, the price of U.S. farm land will also increase. Our analysis shows that in 2012, higher renewable fuel volumes increase land prices by about 8 percent (RFS Case) and 17 percent (EIA Case). Much of the high quality, suitable land in the U.S. is already being used to produce corn. FASOM estimates an increase of 1.6 million acres (RFS Case) and 2.6 million acres (EIA Case) above the 78.5 million corn acres harvested in the Reference Case in 2012. Due to this higher value of land, we are predicting that farms will withdraw a portion of the land currently in the Conservation Reserve Program (CRP), about 2.3 million acres (RFS Case) and 2.5 million acres (EIA
FASOM estimates U.S. annual wholesale food costs will increase by approximately $2.2 billion with the RFS renewable volumes and $3.7 billion with the EIA renewable volumes by 2012. These costs translate to approximately $7 per person per year (RFS case) and $12 per person per year (EIA case).
In the proposal, we noted that expansion in the use of renewable fuels also raises the issue of whether water quality and rural ecosystems in general could be affected due to increased production of agricultural feedstocks used to produce greater volumes of renewable fuels. We received one comment from Marathon asserting that our environmental assessment was incomplete and did not address water quality issues. In the time frame to complete this rulemaking, we were not able to conduct a comprehensive assessment of the environmental impacts in the agricultural sector of the wider use of renewable fuels. However, we have considered two indicators—fertilizer use on agricultural crops and Conservation Resource Program (CRP) lands—that may relate to environmental quality and water quality from the production of renewable fuels. The CRP is a voluntary program administered by the U.S. Department of Agriculture that helps defray the costs to farmers of taking agricultural lands out of production and placing them in CRP to provide environmental protection.
As discussed in Section X, FASOM predicts the total amount of nitrogen applied on all farms will increase by 1.2 percent in the RFS Case and by 2 percent in the EIA Case, relative to the Reference Case in 2012. The total amount of phosphorous applied on all farms increases by 0.7 percent in the RFS Case and 1.2 percent in the EIA Case, relative to the Reference Case in 2012. Currently, there are approximately 40 million acres in the CRP. FASOM predicts 2.3 million acres (RFS Case) and 2.5 million acres (EIA Case) of land would be withdrawn from the CRP due to higher land values.
Many interested parties participated in the rulemaking process that culminates with this final rule. This process provided opportunity for submitting written public comments following the proposal that we published on September 22, 2006 (71 FR 55552). We considered these comments in developing the final rule. In addition, we held a public hearing on the proposed rulemaking on October 13, 2006, and we have considered comments presented at the hearing.
Throughout the rulemaking process, EPA met with stakeholders including representatives from the refining industry, renewable fuels production, and marketers and distributors, and others. The program we are finalizing today was developed as a collaborative effort with these stakeholders.
We have prepared a detailed Summary and Analysis of Comments document, which describes comments we received on the proposal and our response to each of these comments. The Summary and Analysis of Comments is available in the docket for this rule at the Internet address listed under
Under Executive Order (EO) 12866, (58 FR 51735, October 4, 1993) this action is a “significant regulatory action” because of the policy implications of the final rule. Even though EPA has estimated that renewable fuel use through 2012 will be sufficient through the operation of market forces to meet the levels required in the standard, the final rule reflects the first renewable fuel mandate at the federal level. Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for review under EO 12866 and any changes made in response to OMB recommendations have been documented in the docket for this action.
The information collection requirements in this final rule have been submitted for approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501
The information is planned to be collected to ensure that the required amount of renewable fuel is used each year. The credit trading program required by the Energy Policy Act will be satisfied through a program utilizing Renewable Identification Numbers (RINs), which are assigned when renewable fuel is produced in or imported to geographic areas covered by the rule. Production and importation of renewable fuel will serve as a surrogate measure of renewable fuel consumption. Our final RIN-based program will fulfill all the functions of a credit trading program, and thus will meet the Energy Policy Act's requirements. For each calendar year, each obligated party will be required to submit a report to the Agency documenting the RINs it acquired, and showing that the sum of all RINs acquired is equal to or greater than its renewable volume obligation. The Agency could then verify that the RINs used for compliance purposes were valid by simply comparing RINs reported by producers to RINs claimed by obligated parties.
For fuel standards, Section 208(a) of the Clean Air Act requires that manufacturers provide information the Administrator may reasonably require to determine compliance with the regulations; submission of the information is therefore mandatory. We will consider confidential all information meeting the requirements of Section 208(c) of the Clean Air Act.
The annual public reporting and recordkeeping burden for this collection of information is estimated to be 3.3 hours per response. A document entitled “Information Collection Request (ICR); OMB-83 Supporting Statement, Environmental Protection Agency, Office of Air and Radiation,” has been placed in the public docket. The supporting statement provides a detailed explanation of the Agency's estimates by collection activity and explains how comments may be submitted by interested parties. The estimates contained in the docket are briefly summarized here:
Estimated total number of potential respondents: 6,425.
Estimated total number of responses: 13,380.
Estimated total annual burden hours: 43,030.
Estimated total respondent cost (estimated at $71 per hour): $3,055,130.
Estimated total non-postage purchased services (estimated at $142 per hour): $5,219,920.
EPA received various comments on the rulemaking provisions covered by the proposed ICR. All comments that were submitted to EPA are considered in the Summary and Analysis of Comments, which can be found in the
Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, or disclose or provide information to or for a Federal agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transmit or otherwise disclose the information.
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 numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is approved by OMB, the Agency will publish a technical amendment to 40 CFR part 9 in the
The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of today's rule on small entities, small entity is defined as: (1) A small business as defined by the Small Business Administration's (SBA) regulations at 13 CFR 121.201 (see table below); (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field. The following table provides an overview of the primary SBA small business categories potentially affected by this
EPA has determined that it is not necessary to prepare a regulatory flexibility analysis in connection with this final rule.
Since the vast majority of crude oil produced in or imported into the U.S. is consumed as gasoline or diesel fuel, concerns about our dependence on foreign sources of crude oil has renewed interest in renewable transportation fuels. The passage of the Energy Policy Act of 2005 demonstrated a strong commitment on the part of U.S. policymakers to consider additional means of supporting renewable fuels as a supplement to petroleum-based fuels in the transportation sector. Section 1501 of the Energy Policy Act, which was added to the CAA as Section 211(o), requires EPA to establish the RFS program to ensure that the pool of gasoline sold in the contiguous 48 states contains specific volumes of renewable fuel for each calendar year starting with 2006. The Agency is required to set a standard for each year representing the amount of renewable fuel that obligated parties (e.g., refiners, blenders, and importers) must use as a percentage of gasoline sold or introduced into commerce, and the Agency is required to promulgate a credit trading program for the RFS program.
Title XV (Ethanol and Motor Fuels) of the Energy Policy Act provides, at Section 1501(a)(2) [42 U.S.C. 7545(o)(9)(A)-(D)], special provisions for “small refineries”, such as a temporary exemption from the standards until calendar year 2011. The Act defines the term “small refinery” as “* * * a refinery for which the average aggregate daily crude oil throughput for a calendar year * * * does not exceed 75,000 barrels.” As shown in the table above, this term is different than SBA's small business category for gasoline
A small refinery, per the Energy Policy Act, is a refinery where the annual crude throughput is less than or equal to 75,000 barrels (i.e., a small-capacity refinery), and could be owned by a larger refiner that exceeds SBA's small entity size standards. The small business employee criteria were established for SBA's small business definition to set apart those companies which are most likely to be at an inherent economic disadvantage relative to larger businesses.
The refiners that are potentially affected by this rule are those that produce gasoline. For our recent final rule “Control of Hazardous Air Pollutants From Mobile Sources” (72 FR 8428, February 26, 2007), we performed an industry characterization of potentially affected gasoline refiners. We used that industry characterization to determine which refiners would also meet the SBA definition of a small entity. From that industry characterization, and further analysis following the Notice of Proposed Rulemaking (71 FR 55552, September 22, 2006), we have determined that there are 15 gasoline refiners who own 16 refineries (14 refiners own one refinery each, the remaining refiner owns two refineries) that meet the definition of a small refiner. Of the 16 refineries, 13 also meet the Energy Policy Act's definition of a small refinery.
As previously stated, many aspects of the RFS program, such as the required amount of annual renewable fuel volumes, are specified in the Energy Policy Act. As discussed above in Section II.A.1, the annual projections of ethanol production to satisfy market demand exceed the required annual renewable fuel volumes. When the small refinery exemption ends, it is anticipated that there will be over one
When the Agency certifies that a rule will not have a significant economic impact on a substantial number of small entities, EPA's policy is to make an assessment of the rule's impact on any small entities and to engage the potentially regulated entities in a dialog regarding the rule, and minimize the impact to the extent feasible. The following sections discuss our outreach with the potentially affected small entities and regulatory flexibilities to decrease the burden on these entities in compliance with the requirements of the RFS program.
We do not believe that the RFS program would have a significant economic impact on a substantial number of small entities, however we have still tried to reduce the impact of this rule on small entities. Prior to issuing the proposed rule, we held meetings with small refiners to discuss the requirements of the RFS program and the special provisions offered by the Energy Policy Act for small refineries.
The Energy Policy Act set out the following provisions for small refineries:
• A temporary exemption from the Renewable Fuels Standard requirement until 2011;
• An extension of the temporary exemption period for at least two years for any small refinery where it is determined that the refinery would be subject to a disproportionate economic hardship if required to comply;
• Any small refinery may petition, at any time, for an exemption based on disproportionate economic hardship; and,
• A small refinery may waive its temporary exemption to participate in the credit generation program, or it may also “opt-in”, by waiving its temporary exemption, to be subject to the RFS requirement.
During these meetings with the small refiners we also discussed the impacts of these provisions being offered to small refineries only. Three refiners met the definition of a small refiner, but their refineries did not meet the Act's definition of a small refinery; which naturally concerned the small refiners. Another concern that the small refiners had was that if this rule were to have a significant economic impact on a substantial number of small entities a lengthy SBREFA process would ensue (which would delay the promulgation of the RFS rulemaking) and thus provide less lead time for these small entities prior to the RFS program start date.
Following our discussions with the small refiners, they provided three suggested regulatory flexibility options that they believed could further assist affected small entities in complying with the RFS program standard: (1) That all small
We agreed with the small refiners' suggestion that small refiners be afforded the same temporary exemption that the Act specifies for small refineries. This relief would apply to refiners who meet the 1,500 employee count criteria, as well as the crude capacity criteria that we have used in previous fuels programs when providing relief for small refiners. Regarding the small refiners' second and third suggestions regarding credits, we note that the RIN-based program will automatically provide them with credit for any renewables that they blend into their motor fuels. Until 2011, small refiners will essentially be treated as oxygenate blenders and may separate RINs from batches and trade or sell these RINs, unless they choose to opt-in to the program.
Registration, recordkeeping and reporting are necessary to track compliance with the renewable fuels standard and transactions involving RINs, and these compliance requirements will be similar to those required under our previous and current 40 CFR part 80 fuel compliance programs. We will use the same basic forms for RFS program registration that we use under the reformulated gasoline (RFG) and anti-dumping program, as these forms are well known in the regulated community and are simple to fill out. We will use a simplified method of reporting via the Agency's Central Data Exchange (CDX), which will reduce the reporting burden on regulated parties. Records related to RIN transactions may be kept in any format and the period of record retention by reporting parties is five years, similar to other fuel programs. Records to be retained include copies of all compliance reports submitted to EPA and copies of product transfer documents (PTDs). Sections IV and V, above, contain more detailed discussions on the registration, recordkeeping, reporting, and compliance requirements of this final rule.
We are aware of a few other current or proposed Federal rules that are related to this rule. The primary related federal rules are the Mobile Source Air Toxics (MSAT2) rule (72 FR 8428, February 26, 2007), the Tier 2 Vehicle/Gasoline Sulfur rulemaking (65 FR 6698, February 10, 2000), and the fuel sulfur rules for highway diesel (66 FR 5002, January 18, 2001) and nonroad diesel (69 FR 38958, June 29, 2004).
As stated above, based on the statutory relief provided by the Energy Policy Act for small refineries, we are certifying that this rule will not have a significant economic impact on a substantial number of small entities. Additionally, we believe that extending the small refinery exemption to small refiners would further reduce the economic impacts on small entities. We believe that small refiners generally lack the resources available to larger companies, and therefore find it appropriate to extend this exemption to all small refiners. Thus, we are extending the small refinery temporary exemption to all qualified small refiners. Small refiners will also be permitted to separate RINs from batches and trade or sell these RINs prior to 2011 if the small refiner operates as an ethanol blender.
Past fuels rulemakings have included a provision that, for the purposes of the regulatory flexibility provisions for small entities, a refiner must also have an average crude capacity of no more than 155,000 barrels of crude per day (bpcd). To be consistent with these previous rules, we are finalizing in this rule that refiners that meet this criterion (in addition to having no more than 1,500 total corporate employees) will be considered small refiners for the purposes of the regulatory flexibility provisions for this rulemaking.
Since the RFS program would have no significant economic impact on a substantial number of small entities
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 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 in any one year. Before promulgating an EPA 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 other than the least costly, most cost-effective or least burdensome alternative if the Administrator publishes with the final rule an explanation why that alternative was not adopted.
Before EPA establishes any regulatory requirements that may significantly or uniquely affect small governments, including tribal governments, it must have developed under Section 203 of the UMRA a small government agency plan. The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of EPA regulatory programs with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements.
EPA has determined that this rule does not contain a Federal mandate that may result in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, or the private sector in any one year. EPA has estimated that renewable fuel use through 2012 will be sufficient to meet the required levels. Therefore, individual refiners, blenders, and importers are already on track to meet rule obligations through normal market-driven incentives. Thus, today's rule is not subject to the requirements of Sections 202 and 205 of the UMRA.
EPA has determined that this rule contains no regulatory requirements that might significantly or uniquely affect small governments. Compliance with the mandates of the RFS rule, including the reporting and recordkeeping requirements, are the responsibility of exporters, producers, and importers of renewable fuel and gasoline, and not small governments.
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.”
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. Thus, Executive Order 13132 does not apply to this rule.
In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and State and local governments, EPA specifically solicited comment on the proposed rule from State and local officials. A number of states commented on the proposed rule. These comments are available in the rulemaking docket, and are summarized and addressed in the Summary and Analysis document.
Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (65 FR 67249, November 9, 2000), requires EPA to develop an accountable process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.” This final rule does not have tribal implications, as specified in Executive Order 13175. This rule will be implemented at the Federal level and will apply to refiners, blenders, and importers. Tribal governments will be affected only to the extent they purchase and use regulated fuels. Thus, Executive Order 13175 does not apply to this rule.
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, the Agency must 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.
EPA interprets EO 13045 as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5-501 of the EO has the potential to influence the regulation. This final rule is not subject to EO 13045 because it does not establish an environmental standard intended to mitigate health or safety risks and because it implements specific standards established by Congress in statutes.
This rule is not a “significant energy action” as defined in Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355 (May 22, 2001)) because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy.
EPA expects the provisions to have very little effect on the national fuel supply since normal market forces alone are promoting greater renewable fuel use than required by the RFS mandate. We discuss our analysis of the energy and supply effects of the increased use of renewable fuels in Sections VI and X of this preamble.
As noted in the proposed rule, Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (“NTTAA”), Public Law No. 104-113, 12(d) (15 U.S.C. 272 note)
This rulemaking involves technical standards. EPA has decided to use ASTM D6751-06a “Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels”. This standard was developed by ASTM International (originally known as the American Society for Testing and Materials), Subcommittee D02.E0, and was approved in August 2006. The standard may be obtained through the ASTM Web site (
Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States.
EPA lacks the discretionary authority to address environmental justice in this final rulemaking since the Agency is implementing specific standards established by Congress in statutes. Although EPA lacks authority to modify today's regulatory decision on the basis of environmental justice considerations, EPA nevertheless determined that this final rule does not have a disproportionately high and adverse human health or environmental impact on minority or low-income populations.
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
This rule is subject to Section 307(d) of the CAA. Section 307(d)(7)(B) provides that “[o]nly an objection to a rule or procedure which was raised with reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review.” This section also provides a mechanism for the EPA to convene a proceeding for reconsideration, “[i]f the person raising an objection can demonstrate to the EPA that it was impracticable to raise such objection within [the period for public comment] or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule.” Any person seeking to make such a demonstration to the EPA should submit a Petition for Reconsideration to the Office of the Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., NW., Washington, DC 20460, with a copy to both the person(s) listed in the preceding
Statutory authority for the rules finalized today can be found in section 211 of the Clean Air Act, 42 U.S.C. 7545. Additional support for the procedural and compliance related aspects of today's rule, including the recordkeeping requirements, come from Sections 114, 208, and 301(a) of the CAA, 42 U.S.C. 7414, 7542, and 7601(a).
Environmental protection, Air pollution control, Fuel additives, Gasoline, Imports, Incorporation by reference, Labeling, Motor vehicle pollution, Penalties, Reporting and recordkeeping requirements.
42 U.S.C. 7414, 7542, 7545, and 7601(a).
(a)
(1)
(A) Is produced from grain, starch, oil seeds, vegetable, animal, or fish materials including fats, greases, and oils, sugarcane, sugar beets, sugar components, tobacco, potatoes, or other biomass; or
(B) Is natural gas produced from a biogas source, including a landfill, sewage waste treatment plant, feedlot, or other place where decaying organic material is found.
(ii) The term “renewable fuel” includes cellulosic biomass ethanol, waste derived ethanol, biodiesel, and any blending components derived from renewable fuel.
(2)
(3)
(4)
(5)
(b)
(c)
(d)
(1) The renewable fuel volume will equal the sum of all renewable fuel volumes used in motor fuel, provided that:
(i) One gallon of cellulosic biomass ethanol or waste derived ethanol shall be considered to be the equivalent of 2.5 gallons of renewable fuel; and
(ii) Only the renewable fuel portion of blending components derived from renewable fuel shall be counted towards the renewable fuel volume.
(2) If the nationwide average volume percent of renewable fuel in gasoline in 2006 is equal to or greater than the standard in paragraph (b) of this section, the standard has been met.
(e)
(1) The deficit carryover volume shall be calculated as follows:
(2) There shall be no other consequence of failure to attain the standard in paragraph (b) of this section in 2006 for any of the parties in paragraph (c) of this section.
The definitions of § 80.2 and the following additional definitions apply for the purposes of this subpart. For calendar year 2007 and beyond, the definitions in this section § 80.1101 supplant those in § 80.1100.
(a)
(1) Ethanol derived from any lignocellulosic or hemicellulosic matter that is available on a renewable or recurring basis and includes any of the following:
(i) Dedicated energy crops and trees.
(ii) Wood and wood residues.
(iii) Plants.
(iv) Grasses.
(v) Agricultural residues.
(vi) Animal wastes and other waste materials, the latter of which may include waste materials that are residues (e.g., residual tops, branches, and limbs from a tree farm).
(vii) Municipal solid waste.
(2) Ethanol made at facilities at which animal wastes or other waste materials are digested or otherwise used onsite to displace 90 percent or more of the fossil fuel that is combusted to produce thermal energy integral to the process of making ethanol, by:
(i) The direct combustion of the waste materials or a byproduct resulting from digestion of such waste materials (e.g., methane from animal wastes) to make thermal energy; and/or
(ii) The use of waste heat captured from an off-site combustion process as a source of thermal energy.
(b)
(1) Animal wastes, including poultry fats and poultry wastes, and other waste materials.
(2) Municipal solid waste.
(c)
(d)
(i) Grain.
(ii) Starch.
(iii) Oilseeds.
(iv) Vegetable, animal, or fish materials including fats, greases, and oils.
(v) Sugarcane.
(vi) Sugar beets.
(vii) Sugar components.
(viii) Tobacco.
(ix) Potatoes.
(x) Other biomass.
(xi) Natural gas produced from a biogas source, including a landfill, sewage waste treatment plant, feedlot, or other place where there is decaying organic material.
(2) The term “Renewable fuel” includes cellulosic biomass ethanol, waste derived ethanol, biodiesel (mono-alky ester), non-ester renewable diesel, and blending components derived from renewable fuel.
(3) Ethanol covered by this definition shall be denatured as required and defined in 27 CFR parts 20 and 21.
(4) Small volume additives (excluding denaturants) less than 1.0 percent of the total volume of a renewable fuel shall be counted as part of the total renewable fuel volume.
(5) A fuel produced by a renewable fuel producer that is used in boilers or heaters is not a motor vehicle fuel and therefore is not a renewable fuel.
(e)
(f)
(g)
(h)
(1) Registered as a motor vehicle fuel or fuel additive under 40 CFR part 79.
(2) A mono-alkyl ester.
(3) Meets ASTM D-6751-07, entitled “Standard Specification for Biodiesel Fuel Blendstock (B100) for Middle Distillate Fuels.” ASTM D-6751-07 is incorporated by reference. This incorporation by reference was approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. A copy may be obtained from the American Society for Testing and Materials, 100 Barr Harbor Drive, West Conshohocken, Pennsylvania. A copy may be inspected at the EPA Docket Center, Docket No. EPA-HQ-OAR-2005-0161, EPA/DC, EPA West, Room 3334, 1301 Constitution Ave., NW., Washington, DC, or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to:
(4) Intended for use in engines that are designed to run on conventional diesel fuel.
(5) Derived from nonpetroleum renewable resources (as defined in paragraph (m) of this section).
(i)
(1) Registered as a motor vehicle fuel or fuel additive under 40 CFR part 79.
(2) Not a mono-alkyl ester.
(3) Intended for use in engines that are designed to run on conventional diesel fuel.
(4) Derived from nonpetroleum renewable resources (as defined in paragraph (m) of this section).
(j)
(k)
(l)
(1) Any person who brings gasoline or renewable fuel into the 48 contiguous states of the United States from a foreign country or from an area that has not opted in to the program requirements of this subpart pursuant to § 80.1143; and
(2) Any person who brings gasoline or renewable fuel into an area that has opted in to the program requirements of this subpart pursuant to § 80.1143.
(m)
(1) Plant oils.
(2) Animal fats and animal wastes, including poultry fats and poultry wastes, and other waste materials.
(3) Municipal solid waste and sludges and oils derived from wastewater and the treatment of wastewater.
(n)
(1) Transfer of a batch of renewable fuel to a location outside the United States; and
(2) Transfer of a batch of renewable fuel from a location in the contiguous 48 states to Alaska, Hawaii, or a United States territory, unless that state or territory has received an approval from the Administrator to opt-in to the renewable fuel program pursuant to § 80.1143.
(o)
(1)
(2)
(p)
The RFS standards and other requirements of § 80.1101 and all sections following are effective beginning on September 1, 2007.
(a) The annual value of the renewable fuel standard for 2007 shall be 4.02 percent.
(b) Beginning with the 2008 compliance period, EPA will calculate the value of the annual standard and publish this value in the
(c) EPA will base the calculation of the standard on information provided by the Energy Information Administration regarding projected gasoline volumes and projected volumes of renewable fuel expected to be used in gasoline blending for the upcoming year.
(d) EPA will calculate the annual renewable fuel standard using the following equation:
(e) Beginning with the 2013 compliance period, EPA will calculate the value of the annual cellulosic standard and publish this value in the
(f) EPA will calculate the annual cellulosic standard using the following equation:
(a) (1) An obligated party is a refiner that produces gasoline within the 48 contiguous states, or an importer that imports gasoline into the 48 contiguous states. A party that simply adds renewable fuel to gasoline, as defined in § 80.1107(c), is not an obligated party.
(2) If the Administrator approves a petition of Alaska, Hawaii, or a United States territory to opt-in to the renewable fuel program under the provisions in § 80.1143, then “obligated party” shall also include any refiner that produces gasoline within that state or territory, or any importer that imports gasoline into that state or territory.
(3) For the purposes of this section, “gasoline” refers to any and all of the products specified at § 80.1107(c).
(b) For each compliance period starting with 2007, any obligated party is required to demonstrate, pursuant to § 80.1127, that it has satisfied the Renewable Volume Obligation for that compliance period, as specified in § 80.1107(a).
(c) An obligated party may comply with the requirements of paragraph (b) of this section for all of its refineries in the aggregate, or for each refinery individually.
(d) An obligated party must comply with the requirements of paragraph (b) of this section for all of its imported gasoline in the aggregate.
(e) An obligated party that is both a refiner and importer must comply with the requirements of paragraph (b) of this section for its imported gasoline separately from gasoline produced by its refinery or refineries.
(f) Where a refinery or importer is jointly owned by two or more parties, the requirements of paragraph (b) of this section may be met by one of the joint owners for all of the gasoline produced at the refinery, or all of the imported gasoline, in the aggregate, or each party may meet the requirements of paragraph (b) of this section for the portion of the gasoline that it owns, as long as all of the gasoline produced at the refinery, or all of the imported gasoline, is accounted for in determining the renewable fuels obligation under § 80.1107.
(g) The requirements in paragraph (b) of this section apply to the following compliance periods:
(1) For 2007, the compliance period is September 1 through December 31.
(2) Beginning in 2008, and every year thereafter, the compliance period is January 1 through December 31.
(a) The Renewable Volume Obligation for an obligated party is determined according to the following formula:
(b) The non-renewable gasoline volume for a refiner, blender, or importer for a given year, GV
(c) All of the following products that are produced or imported during a compliance period, collectively called “gasoline” for the purposes of this section (unless otherwise specified), are to be included in the volume used to calculate a party's renewable volume obligation under paragraph (a) of this section, except as provided in paragraph (d) of this section:
(1) Reformulated gasoline, whether or not renewable fuel is later added to it.
(2) Conventional gasoline, whether or not renewable fuel is later added to it.
(3) Reformulated gasoline blendstock that becomes finished reformulated gasoline upon the addition of oxygenate (“RBOB”).
(4) Conventional gasoline blendstock that becomes finished conventional gasoline upon the addition of oxygenate (“CBOB”).
(5) Blendstock (including butane and gasoline treated as blendstock (“GTAB”)) that has been combined with other blendstock and/or finished gasoline to produce gasoline.
(6) Any gasoline, or any unfinished gasoline that becomes finished gasoline upon the addition of oxygenate, that is produced or imported to comply with a state or local fuels program.
(d) The following products are not included in the volume of gasoline produced or imported used to calculate a party's renewable volume obligation under paragraph (a) of this section:
(1) Any renewable fuel as defined in § 80.1101(d).
(2) Blendstock that has not been combined with other blendstock or finished gasoline to produce gasoline.
(3) Gasoline produced or imported for use in Alaska, Hawaii, the Commonwealth of Puerto Rico, the U.S. Virgin Islands, Guam, American Samoa, and the Commonwealth of the Northern Marianas, unless the area has opted into the RFS program under § 80.1143.
(4) Gasoline produced by a small refinery that has an exemption under § 80.1141 or an approved small refiner
(5) Gasoline exported for use outside the 48 United States, and gasoline exported for use outside Alaska, Hawaii, the Commonwealth of Puerto Rico, the U.S. Virgin Islands, Guam, American Samoa, and the Commonwealth of the Northern Marianas, if the area has opted into the RFS program under § 80.1143.
(6) For blenders, the volume of finished gasoline, RBOB, or CBOB to which a blender adds blendstocks.
(7) The gasoline portion of transmix produced by a transmix processor, or the transmix blended into gasoline by a transmix blender, under 40 CFR 80.84.
(a)(1) Each gallon of a renewable fuel shall be assigned an equivalence value by the producer or importer pursuant to paragraph (b) or (c) of this section.
(2) The equivalence value is a number that is used to determine how many gallon-RINs can be generated for a batch of renewable fuel according to § 80.1126.
(b) Equivalence values shall be assigned for certain renewable fuels as follows:
(1) Cellulosic biomass ethanol and waste derived ethanol produced on or before December 31, 2012 which is denatured shall have an equivalence value of 2.5.
(2) Ethanol other than cellulosic biomass ethanol or waste-derived ethanol which is denatured shall have an equivalence value of 1.0.
(3) Biodiesel (mono-alkyl ester) shall have an equivalence value of 1.5.
(4) Butanol shall have an equivalence value of 1.3.
(5) Non-ester renewable diesel, including that produced from coprocessing a renewable crude with fossil fuels in a hydrotreater, shall have an equivalence value of 1.7.
(6) All other renewable crude-based renewable fuels shall have an equivalence value of 1.0.
(c)(1) For renewable fuels not listed in paragraph (b) of this section, a producer or importer shall submit an application to the Agency for an equivalence value following the provisions of paragraph (d) of this section.
(2) A producer or importer may also submit an application for an alternative equivalence value pursuant to paragraph (d) of this section if the renewable fuel is listed in paragraph (b) of this section, but the producer or importer has reason to believe that a different equivalence value than that listed in paragraph (b) of this section is warranted.
(d)
(2) The application for an equivalence value shall include a technical justification that includes a description of the renewable fuel, feedstock(s) used to make it, and the production process.
(3) The Agency will review the technical justification and assign an appropriate Equivalence Value to the renewable fuel based on the procedure in this paragraph (d).
(4) For biogas, the Equivalence Value is 1.0, and 77,550 Btu of biogas is equivalent to 1 gallon of renewable fuel.
Each RIN is a 38 character numeric code of the following form:
KYYYYCCCCFFFFFBBBBBRRDSSSSSSSSEEEEEEEE
(a) K is a number identifying the type of RIN as follows:
(1) K has the value of 1 when the RIN is assigned to a volume of renewable fuel pursuant to §§ 80.1126(e) and 80.1128(a).
(2) K has the value of 2 when the RIN has been separated from a volume of renewable fuel pursuant to § 80.1126(e)(4) or § 80.1129.
(b) YYYY is the calendar year in which the batch of renewable fuel was produced or imported. YYYY also represents the year in which the RIN was originally generated.
(c) CCCC is the registration number assigned according to § 80.1150 to the producer or importer of the batch of renewable fuel.
(d) FFFFF is the registration number assigned according to § 80.1150 to the facility at which the batch of renewable fuel was produced or imported.
(e) BBBBB is a serial number assigned to the batch which is chosen by the producer or importer of the batch such that no two batches have the same value in a given calendar year.
(f) RR is a number representing the equivalence value of the renewable fuel as specified in § 80.1115 and multiplied by 10 to produce the value for RR.
(g) D is a number identifying the type of renewable fuel, as follows:
(1) D has the value of 1 if the renewable fuel can be categorized as cellulosic biomass ethanol as defined in § 80.1101(a).
(2) D has the value of 2 if the renewable fuel cannot be categorized as cellulosic biomass ethanol as defined in § 80.1101(a).
(h) SSSSSSSS is a number representing the first gallon-RIN associated with a batch of renewable fuel.
(i) EEEEEEEE is a number representing the last gallon-RIN associated with a batch of renewable fuel. EEEEEEEE will be identical to SSSSSSSS if the batch-RIN represents a single gallon-RIN. Assign the value of EEEEEEEE as described in § 80.1126.
(a)
(2) If the Administrator approves a petition of Alaska, Hawaii, or a United
(b)
(c)
(1) The number of gallon-RINs generated for a batch of renewable fuel may not exceed 99,999,999.
(2) A batch of renewable fuel cannot represent renewable fuel produced or imported in excess of one calendar month.
(d)
(2) A producer or importer of renewable fuel may generate RINs for volumes of renewable fuel that it owns on September 1, 2007.
(3) A party generating a RIN shall specify the appropriate numerical values for each component of the RIN in accordance with the provisions of § 80.1125 and this paragraph (d).
(4) Except as provided in paragraph (d)(6) of this section, the number of gallon-RINs that shall be generated for a given batch of renewable fuel shall be equal to a volume calculated according to the following formula:
(5) Multiple gallon-RINs generated to represent a given volume of renewable fuel can be represented by a single batch-RIN through the appropriate designation of the RIN volume codes SSSSSSSS and EEEEEEEE.
(i) The value of SSSSSSSS in the batch-RIN shall be 00000001 to represent the first gallon-RIN associated with the volume of renewable fuel.
(ii) The value of EEEEEEEE in the batch-RIN shall represent the last gallon-RIN associated with the volume of renewable fuel, based on the RIN volume determined pursuant to paragraph (d)(4) of this section.
(6) (i) For renewable crude-based renewable fuels produced in a facility or unit that coprocesses renewable crudes and fossil fuels, the number of gallon-RINs that shall be generated for a given batch of renewable fuel shall be equal to the gallons of renewable crude used rather than the gallons of renewable fuel produced.
(ii) Parties that produce renewable crude-based renewable fuels in a facility or unit that coprocesses renewable crudes and fossil fuels may submit a petition to the Agency requesting the use of volumes of renewable fuel produced as the basis for the number of gallon-RINs, pursuant to paragraph (d)(4) of this section.
(7)
(i) For ethanol, the following formula shall be used:
(ii) For biodiesel (mono alkyl esters), the following formula shall be used:
(iii) For other renewable fuels, an appropriate formula commonly accepted by the industry shall be used to standardize the actual volume to 60 °F. Formulas used must be reported to the Agency, and may be reviewed for appropriateness.
(8) (i) A party is prohibited from generating RINs for a volume of renewable fuel that it produces if:
(A) The renewable fuel has been produced from a chemical conversion process that uses another renewable fuel as a feedstock; and
(B) The renewable fuel used as a feedstock was produced by another party.
(ii) Any RINs that the party acquired with renewable fuel used as a feedstock shall be assigned to the new renewable fuel that was made with that feedstock.
(e)
(2) A RIN is assigned to a volume of renewable fuel when ownership of the RIN is transferred along with the transfer of ownership of the volume of renewable fuel, pursuant to § 80.1128(a).
(3) All assigned RINs shall have a K code value of 1.
(4)
(ii) Any remaining gallon-RINs generated for the cellulosic biomass ethanol or waste-derived ethanol which represent the remaining 1.5 portion of the Equivalence Value may remain unassigned.
(iii) The producer or importer of cellulosic biomass ethanol or waste-derived ethanol shall designate the K code as 2 for all unassigned RINs.
(a)
(2) For compliance for calendar years 2008 and later, the value of (
(3) RINs may only be used to demonstrate compliance with the RVO for the calendar year in which they were generated or the following calendar year. RINs used to demonstrate compliance in one year cannot be used to demonstrate compliance in any other year.
(4) A party may only use a RIN for purposes of meeting the requirements of paragraphs (a)(1) and (a)(2) of this section if that RIN is an unassigned RIN with a K code of 2 obtained in accordance with §§ 80.1126(e)(4), 80.1128, and 80.1129.
(5) The number of gallon-RINs associated with a given batch-RIN that can be used for compliance with the RVO shall be calculated from the following formula:
(b)
(i) The party did not carry a deficit into calendar year i from calendar year i−1.
(ii) The party subsequently meets the requirements of paragraph (a)(1) of this section for calendar year i+1 and carries no deficit into year i+2.
(2) A deficit is calculated according to the following formula:
(a)
(2) Except as provided in § 80.1126(e)(4) and § 80.1129, no party can separate a RIN that has been assigned to a batch pursuant to § 80.1126(e).
(3) An assigned RIN cannot be transferred to another party without simultaneously transferring a volume of renewable fuel to that same party.
(4) No more than 2.5 assigned gallon-RINs with a K code of 1 can be transferred to another party with every gallon of renewable fuel transferred to that same party.
(5) (i) On each of the dates listed in paragraph (a)(5)(v) of this section in any calendar year, the following equation must be satisfied for assigned RINs and volumes of renewable fuel owned by a party:
(ii) The equivalence value EV
(iii) If the equivalence value for a volume of renewable fuel i can be determined pursuant to § 80.1115 based on its composition, then the appropriate equivalence value shall be used for EV
(iv) If the equivalence value for a volume of renewable fuel cannot be determined based on its composition, the value of EV
(v) The applicable dates are March 31, June 30, September 30, and December 31. For 2007 only, the applicable dates are September 30, and December 31.
(6)
(ii) A producer or importer of renewable fuel can transfer ownership of a volume of renewable fuel without simultaneously transferring ownership of gallon-RINs having a K code of 1 if it can demonstrate one of the following:
(A) It is a small volume producer exempt from the requirement to generate RINs pursuant to § 80.1126(b); or
(B) The producer or importer received an equivalent volume of renewable fuel from another party without accompanying RINs.
(C) The producer or importer has generated RINs for cellulosic biomass ethanol or waste-derived ethanol having an equivalence value of 2.5, and has chosen to specify as unassigned a number of gallon-RINs pursuant to § 80.1126(e)(4).
(7) Any transfer of ownership of assigned RINs must be documented on product transfer documents generated pursuant to § 80.1153.
(i) The RIN must be recorded on the product transfer document used to transfer ownership of the RIN and the volume to another party; or
(ii) The RIN must be recorded on a separate product transfer document transferred to the same party on the same day as the product transfer document used to transfer ownership of the volume of renewable fuel.
(b)
(2) Any party that has registered pursuant to § 80.1150 can hold title to an unassigned RIN.
(3) Unassigned RINs can be transferred from one party to another any number of times.
(4) An unassigned batch-RIN can be divided by its holder into multiple batch-RINs, each representing a smaller number of gallon-RINs, if all of the following conditions are met:
(i) All RIN components other than SSSSSSSS and EEEEEEEE are identical for the original parent and newly formed daughter RINs.
(ii) The sum of the gallon-RINs associated with the multiple daughter batch-RINs is equal to the gallon-RINs associated with the parent batch-RIN.
(a)(1) Separation of a RIN from a volume of renewable fuel means termination of the assignment of the RIN to a volume of renewable fuel.
(2) RINs that have been separated from volumes of renewable fuel become unassigned RINs subject to the provisions of § 80.1128(b).
(b) A RIN that is assigned to a volume of renewable fuel is separated from that volume only under one of the following conditions:
(1) Except as provided in paragraph (b)(6) of this section, a party that is an obligated party according to § 80.1106 must separate any RINs that have been assigned to a volume of renewable fuel if they own that volume.
(2) Except as provided in paragraph (b)(5) of this section, any party that owns a volume of renewable fuel must separate any RINs that have been assigned to that volume once the volume is blended with gasoline or diesel to produce a motor vehicle fuel.
(3) Any party that exports a volume of renewable fuel must separate any RINs that have been assigned to the exported volume.
(4) Any renewable fuel producer or importer that produces or imports a volume of renewable fuel shall have the right to separate any RINs that have been assigned to that volume if the producer or importer designates the renewable fuel as motor vehicle fuel and the renewable fuel is used as motor vehicle fuel.
(5) RINs assigned to a volume of biodiesel (mono-alkyl ester) can only be separated from that volume pursuant to paragraph (b)(2) of this section if such biodiesel is blended into diesel fuel at a concentration of 80 volume percent biodiesel (mono-alkyl ester) or less.
(i) This paragraph (b)(5) shall not apply to obligated parties or exporters of renewable fuel.
(ii) This paragraph (b)(5) shall not apply to renewable fuel producers meeting the requirements of paragraph (b)(4) of this section.
(6) For RINs that an obligated party generates, the obligated party can only separate such RINs from volumes of renewable fuel if the number of gallon-RINs separated is less than or equal to its annual RVO.
(7) A producer or importer of cellulosic biomass ethanol or waste-derived ethanol can separate a portion of the RINs that it generates pursuant to § 80.1126(e)(4).
(c) The party responsible for separating a RIN from a volume of renewable fuel shall change the K code in the RIN from a value of 1 to a value of 2 prior to transferring the RIN to any other party.
(d) (1) Upon and after separation from a renewable fuel volume, a RIN shall not appear on documentation that is either:
(i) Used to identify title to the volume of renewable fuel; or
(ii) Transferred with the volume of renewable fuel.
(2) Upon and after separation of a RIN from its associated volume, product transfer documents used to transfer ownership of the volume must continue to meet the requirements of § 80.1153(a)(5)(iii).
(e) Any obligated party that uses a renewable fuel in a boiler or heater must retire any RINs associated with that volume of renewable fuel and report the retired RINs in the applicable reports under § 80.1152.
(a) Any party that owns any amount of renewable fuel (in its neat form or blended with gasoline or diesel) that is exported from the region described in § 80.1126(a) shall acquire sufficient RINs to offset a Renewable Volume Obligation representing the exported renewable fuel.
(b)
(1) A renewable fuel exporter's total Renewable Volume Obligation shall be calculated according to the following formula:
D
(2)(i) If the equivalence value for a volume of renewable fuel can be determined pursuant to § 80.1115 based on its composition, then the appropriate equivalence value shall be used in the calculation of the exporter's Renewable Volume Obligation.
(ii) If the equivalence value for a volume of renewable fuel cannot be determined, the value of EV
(c) Each exporter of renewable fuel must demonstrate compliance with its RVO using RINs it has acquired pursuant to § 80.1127.
(a)
(1) Is a duplicate of a valid RIN.
(2) Was based on volumes that have not been standardized to 60 °F.
(3) Has expired.
(4) Was based on an incorrect equivalence value.
(5) Is deemed invalid under § 80.1167(g).
(6) Does not represent renewable fuel as it is defined in § 80.1101.
(7) Was otherwise improperly generated.
(b) In the case of RINs that are invalid, the following provisions apply:
(1) Invalid RINs cannot be used to achieve compliance with the Renewable Volume Obligation of an obligated party or exporter, regardless of the party's good faith belief that the RINs were valid at the time they were acquired.
(2) Upon determination by any party that RINs owned are invalid, the party must adjust their records, reports, and compliance calculations as necessary to reflect the deletion of the invalid RINs.
(3) Any valid RINs remaining after deleting invalid RINs must first be applied to correct the transfer of invalid RINs to another party before applying the valid RINs to meet the party's Renewable Volume Obligation at the end of the compliance year.
(4) In the event that the same RIN is transferred to two or more parties, all such RINs will be deemed to be invalid, unless EPA in its sole discretion determines that some portion of these RINs is valid.
(a) A reported spillage under paragraph (d) of this section means a spillage of renewable fuel associated with a requirement by a federal, state or local authority to report the spillage.
(b) Except as provided in paragraph (c) of this section, in the event of a reported spillage of any volume of renewable fuel, the owner of the renewable fuel must retire a number of gallon-RINs corresponding to the volume of spilled renewable fuel multiplied by its equivalence value.
(1) If the equivalence value for the spilled volume may be determined pursuant to § 80.1115 based on its composition, then the appropriate equivalence value shall be used.
(2) If the equivalence value for a spilled volume of renewable fuel cannot be determined, the equivalence value shall be 1.0.
(c) If the owner of a volume of renewable fuel that is spilled and reported establishes that no RINs were generated to represent the volume, then no gallon-RINs shall be retired.
(d) A RIN that is retired under paragraph (b) of this section:
(1) Must be reported as a retired RIN in the applicable reports under § 80.1152.
(2) May not be transferred to another party or used by any obligated party to demonstrate compliance with the party's Renewable Volume Obligation.
(a)(1) Gasoline produced at a refinery by a refiner, or foreign refiner (as defined at § 80.1165(a)), is exempt from the renewable fuel standards of § 80.1105 if that refinery meets the definition of a small refinery under § 80.1101(g) for calendar year 20460.
(2) This exemption shall apply through December 31, 2010, unless a refiner chooses to waive this exemption (as described in paragraph (f) of this section), or the exemption is extended (as described in paragraph (e) of this section).
(3) For the purposes of this section, the term “refiner” shall include foreign refiners.
(b)(1) The small refinery exemption is effective immediately, except as specified in paragraph (b)(4) of this section.
(2) A refiner owning a small refinery must submit a verification letter to EPA containing all of the following information:
(i) The annual average aggregate daily crude oil throughput for the period January 1, 2004, through December 31, 2004 (as determined by dividing the aggregate throughput for the calendar year by the number 365).
(ii) 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 letter is true to the best of his/her knowledge, and that the company owned the refinery as of January 1, 2004.
(iii) Name, address, phone number, facsimile number, and e-mail address of a corporate contact person.
(3) Verification letters must be submitted by August 31, 2007, to one of the addresses listed in paragraph (h) of this section.
(4) For foreign refiners the small refinery exemption shall be effective upon approval, by EPA, of a small refinery application. The application must contain all of the elements required for small refinery verification letters (as specified in paragraph (b)(2) of this section), must satisfy the provisions of § 80.1165(f) through (h) and (o), and must be submitted by August 31, 2007 to one of the addresses listed in paragraph (h) of this section.
(c) If EPA finds that a refiner provided false or inaccurate information regarding a refinery's crude throughput (pursuant to paragraph (b)(2)(i) of this section) in its small refinery verification letter, the exemption will be void as of the effective date of these regulations.
(d) If a refiner is complying on an aggregate basis for multiple refineries, any such refiner may exclude from the calculation of its Renewable Volume Obligation (under § 80.1107(a)) gasoline from any refinery receiving the small refinery exemption under paragraph (a) of this section.
(e)(1) The exemption period in paragraph (a) of this section shall be extended by the Administrator for a period of not less than two additional years if a study by the Secretary of Energy determines that compliance with the requirements of this subpart would impose a disproportionate economic hardship on the small refinery.
(i) A refiner may at any time petition the Administrator for an extension of its small refinery exemption under paragraph (a) of this section for the reason of disproportionate economic hardship.
(ii) A petition for an extension of the small refinery exemption must specify the factors that demonstrate a disproportionate economic hardship and must provide a detailed discussion regarding the inability of the refinery to produce gasoline meeting the requirements of § 80.1105 and the date the refiner anticipates that compliance with the requirements can be achieved at the small refinery.
(2) The Administrator shall act on such a petition not later than 90 days after the date of receipt of the petition.
(f) At any time, a refiner with an approved small refinery exemption under paragraph (a) of this section may waive that exemption upon notification to EPA.
(1) A refiner's notice to EPA that it intends to waive its small refinery exemption must be received by November 1 to be effective in the next compliance year.
(2) The waiver will be effective beginning on January 1 of the following calendar year, at which point the gasoline produced at that refinery will be subject to the renewable fuels standard of § 80.1105.
(3) The waiver must be sent to EPA at one of the addresses listed in paragraph (h) of this section.
(g) A refiner that acquires a refinery from either an approved small refiner (as defined under § 80.1142(a)) or another refiner with an approved small refinery exemption under paragraph (a) of this section shall notify EPA in writing no later than 20 days following the acquisition.
(h) Verification letters under paragraph (b) of this section, petitions for small refinery hardship extensions under paragraph (e) of this section, and small refinery exemption waivers under paragraph (f) of this section shall be sent to one of the following addresses:
(1)
(2)
(a) (1) Gasoline produced by a refiner, or foreign refiner (as defined at § 80.1165(a)), is exempt from the renewable fuel standards of § 80.1105 if the refiner or foreign refiner does not meet the definition of a small refinery under § 80.1101(g) but meets all of the following criteria:
(i) The refiner produced gasoline at its refineries by processing crude oil through refinery processing units from January 1, 2004 through December 31, 2004.
(ii) The refiner employed an average of no more than 1,500 people, based on the average number of employees for all pay periods for calendar year 2004 for all subsidiary companies, all parent companies, all subsidiaries of the parent companies, and all joint venture partners.
(iii) The refiner had a corporate-average crude oil capacity less than or equal to 155,000 barrels per calendar day (bpcd) for 2004.
(2) The small refiner exemption shall apply through December 31, 2010, unless a refiner chooses to waive the
(3) For the purposes of this section, the term “refiner” shall include foreign refiners.
(b) The small refiner exemption is effective immediately, except as provided in paragraph (d) of this section. Refiners who qualify for the small refiner exemption under paragraph (a) of this section must submit a verification letter (and any other relevant information) to EPA containing all of the following information for the refiner and for all subsidiary companies, all parent companies, all subsidiaries of the parent companies, and all joint venture partners:
(1)(i) A listing of the name and address of each company location where any employee worked for the period January 1, 2004 through December 31, 2004.
(ii) The average number of employees at each location based on the number of employees for each pay period for the period January 1, 2004 through December 31, 2004.
(iii) The type of business activities carried out at each location.
(iv) For joint ventures, the total number of employees includes the combined employee count of all corporate entities in the venture.
(v) For government-owned refiners, the total employee count includes all government employees.
(2) The total corporate crude oil capacity of each refinery as reported to the Energy Information Administration (EIA) of the U.S. Department of Energy (DOE), for the period January 1, 2004 through December 31, 2004. 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 when the company submits its verification letter.
(3) The verification letter must be signed by the president, chief operating or chief executive officer of the company, or his/her designee, stating that the information is true to the best of his/her knowledge, and that the company owned the refinery as of December 31, 2004.
(4) Name, address, phone number, facsimile number, and e-mail address of a corporate contact person.
(c) Verification letters under paragraph (b) of this section must be submitted by September 1, 2007.
(d) For foreign refiners the small refiner exemption shall be effective upon approval, by EPA, of a small refiner application. The application must contain all of the elements required for small refiner verification letters (as specified in paragraphs (b)(1), (b)(3), and (b)(4) of this section), must demonstrate compliance with the crude oil capacity criterion of paragraph (a)(1)(iii) of this section, must satisfy the provisions of § 80.1165(f) through (h) and (o), and must be submitted by September 1, 2007 to one of the addresses listed in paragraph (j) of this section.
(e) A refiner who qualifies as a small refiner under this section and subsequently fails to meet all of the qualifying criteria as set out in paragraph (a) of this section will have its small refiner exemption terminated effective January 1 of the next calendar year; however, disqualification shall not apply in the case of a merger between two approved small refiners.
(f) If EPA finds that a refiner provided false or inaccurate information in its small refiner status verification letter under this subpart, the small refiner's exemption will be void as of the effective date of these regulations.
(g) If a small refiner is complying on an aggregate basis for multiple refineries, the refiner may exempt the refineries from the calculation of its Renewable Volume Obligation under § 80.1107.
(h) (1) A refiner may, at any time, waive the small refiner exemption under paragraph (a) of this section upon notification to EPA.
(2) A refiner's notice to EPA that it intends to waive the small refiner exemption must be received by November 1 in order for the waiver to be effective for the following calendar year. The waiver will be effective beginning on January 1 of the following calendar year, at which point the refiner will be subject to the renewable fuel standard of § 80.1105.
(3) The waiver must be sent to EPA at one of the addresses listed in paragraph (j) of this section.
(i) Any refiner that acquires a refinery from another refiner with approved small refiner status under paragraph (a) of this section shall notify EPA in writing no later than 20 days following the acquisition.
(j) Verification letters under paragraph (b) of this section and small refiner exemption waivers under paragraph (h) of this section shall be sent to one of the following addresses:
(1)
(2)
(a) A noncontiguous state or United States territory may petition the Administrator to opt-in to the program requirements of this subpart.
(b) The Administrator will approve the petition if it meets the provisions of paragraphs (c) and (d) of this section.
(c) The petition must be signed by the Governor of the state or his authorized representative (or the equivalent official of the territory).
(d)(1) A petition submitted under this section must be received by the Agency by November 1 for the state or territory to be included in the RFS program in the next calendar year.
(2) A petition submitted under this section should be sent to either of the following addresses:
(i)
(ii)
(e) Upon approval of the petition by the Administrator:
(1) EPA shall calculate the standard for the following year, including the total gasoline volume for the State or territory in question.
(2) Beginning on January 1 of the next calendar year, all gasoline refiners and importers in the state or territory for which a petition has been approved shall be obligated parties as defined in § 80.1106.
(3) Beginning on January 1 of the next calendar year, all renewable fuel producers in the State or territory for which a petition has been approved shall, pursuant to § 80.1126(a)(2), be required to generate RINs and assign them to batches of renewable fuel.
(a) Any obligated party described in § 80.1106 and any exporter of renewable fuel described in § 80.1130 must provide EPA with the information specified for registration under § 80.76, if such information has not already been provided under the provisions of this part. An obligated party or an exporter of renewable fuel must receive EPA-issued identification numbers prior to engaging in any transaction involving RINs. Registration information may be submitted to EPA at any time after promulgation of this rule in the
(b) Any importer or producer of a renewable fuel must provide EPA the information specified under § 80.76, if such information has not already been provided under the provisions of this part, and must receive EPA-issued company and facility identification numbers prior to generating or assigning any RINs. Registration information may be submitted to EPA at any time after promulgation of this rule in the
(c) Any party who owns or intends to own RINs, but who is not covered by paragraphs (a) and (b) of this section, must provide EPA the information specified under § 80.76, if such information has not already been provided under the provisions of this part and must receive an EPA-issued company identification number prior to owning any RINs. Registration information may be submitted to EPA at any time after promulgation of this rule in the
(d) Registration shall be on forms, and following policies, established by the Administrator.
(a) Beginning September 1, 2007, any obligated party (as described at § 80.1106) or exporter of renewable fuel (as described at § 80.1130) must keep all of the following records:
(1) Product transfer documents consistent with § 80.1153 and associated with the obligated party's activity, if any, as transferor or transferee of renewable fuel.
(2) Copies of all reports submitted to EPA under § 80.1152(a).
(3) Records related to each RIN transaction, which includes all the following:
(i) A list of the RINs owned, purchased, sold, retired or expired.
(ii) The parties involved in each RIN transaction including the transferor, transferee, and any broker or agent.
(iii) The date of the transfer of the RIN(s).
(iv) Additional information related to details of the transaction and its terms.
(4) Records related to the use of RINs (by facility, if applicable) for compliance, which includes all the following:
(i) Methods and variables used to calculate the Renewable Volume Obligation pursuant to § 80.1107 or § 80.1130.
(ii) List of RINs used to demonstrate compliance.
(iii) Additional information related to details of RIN use for compliance.
(b) Beginning September 1, 2007, any producer or importer of a renewable fuel as defined at § 80.1101(d) must keep all of the following records:
(1) Product transfer documents consistent with § 80.1153 and associated with the renewable fuel producer's or importer's activity, if any, as transferor or transferee of renewable fuel.
(2) Copies of all reports submitted to EPA under § 80.1152(b).
(3) Records related to the generation and assignment of RINs for each facility, including all of the following:
(i) Batch volume in gallons.
(ii) Batch number.
(iii) RIN number as assigned under § 80.1126.
(iv) Identification of batches meeting the definition of cellulosic biomass ethanol.
(v) Date of production or import.
(vi) Results of any laboratory analysis of batch chemical composition or physical properties.
(vii) Additional information related to details of RIN generation.
(4) Records related to each RIN transaction, including all of the following:
(i) A list of the RINs owned, purchased, sold, retired or expired.
(ii) The parties involved in each transaction including the transferor, transferee, and any broker or agent.
(iii) The date of the transfer of the RIN(s).
(iv) Additional information related to details of the transaction and its terms.
(5) Records related to the production or importation of any volume of renewable fuel that the renewable fuel producer or importer designates as motor vehicle fuel and the use of the fuel as motor vehicle fuel.
(c) Beginning September 1, 2007, any producer of a renewable fuel defined at § 80.1101(d) must keep verifiable records of the following:
(1) The amount and type of fossil fuel and waste material-derived fuel used in producing on-site thermal energy dedicated to the production of ethanol at plants producing cellulosic biomass ethanol through the displacement of 90 percent or more of the fossil fuel normally used in the production of ethanol, as described at § 80.1101(a)(2).
(2) The amount and type of feedstocks used in producing cellulosic biomass ethanol as defined in § 80.1101(a)(1).
(3) The equivalent amount of fossil fuel (based on reasonable estimates) associated with the use of off-site generated waste heat that is used in the production of ethanol at plants producing cellulosic biomass ethanol through the displacement of 90 percent or more of the fossil fuel normally used in the production of ethanol, as described at § 80.1101(a)(2).
(4) The plot plan and process flow diagram for plants producing cellulosic biomass and waste derived ethanol as defined in § 80.1101(a) and (b), respectively.
(5) The independent third party verification required under § 80.1155 for producers of cellulosic biomass ethanol and waste derived ethanol.
(d) Beginning September 1, 2007, any party, other than those parties covered in paragraphs (a) and (b) of this section, that owns RINs must keep all of the following records:
(1) Product transfer documents consistent with § 80.1153 and associated with the party's activity, if any, as transferor or transferee of renewable fuel.
(2) Copies of all reports submitted to EPA under § 80.1152(c).
(3) Records related to each RIN transaction, including all of the following:
(i) A list of the RINs owned, purchased, sold, retired or expired.
(ii) The parties involved in each RIN transaction including the transferor, transferee, and any broker or agent.
(iii) The date of the transfer of the RIN(s).
(iv) Additional information related to details of the transaction and its terms.
(e) The records required under this section and under § 80.1153 shall be kept for five years from the date they were created, except that records related to transactions involving RINs shall be kept for five years from the date of transfer.
(f) On request by EPA, the records required under this section and under § 80.1153 must be made available to the Administrator or the Administrator's authorized representative. For records that are electronically generated or maintained, the equipment or software
(a) Any obligated party described in § 80.1106 or exporter of renewable fuel described in § 80.1130 must submit to EPA reports according to the schedule, and containing the information, that is set forth in this paragraph (a).
(1) An annual compliance demonstration report for the previous compliance period shall be submitted every February 28, except as noted in paragraph (a)(1)(x) of this section, and shall include all of the following information:
(i) The obligated party's name.
(ii) The EPA company registration number.
(iii) Whether the party is complying on a corporate (aggregate) or facility-by-facility basis.
(iv) The EPA facility registration number, if complying on a facility-by-facility basis.
(v) The production volume of all of the products listed in § 80.1107(c) for the reporting year.
(vi) The renewable volume obligation (RVO), as defined in § 80.1127(a) for obligated parties and § 80.1130(b) for exporters of renewable fuel, for the reporting year.
(vii) Any deficit RVO carried over from the previous year.
(viii) The total current-year gallon-RINs used for compliance.
(ix) The total prior-years gallon-RINs used for compliance.
(x) A list of all RINs used for compliance in the reporting year. For compliance demonstrations covering calendar year 2007 only, this list shall be reported by May 31, 2008. In all subsequent years, this list shall be submitted by February 28.
(xi) Any deficit RVO carried into the subsequent year.
(xii) Any additional information that the Administrator may require.
(2) The quarterly RIN transaction reports required under paragraph (c)(1) of this section.
(3) The quarterly gallon-RIN activity reports required under paragraph (c)(2) of this section.
(4) Reports required under this paragraph (a) must be signed and certified as meeting all the applicable requirements of this subpart by the owner or a responsible corporate officer of the obligated party.
(b) Any producer or importer of a renewable fuel must, beginning November 30, 2007, submit to EPA reports according to the schedule, and containing the information, that is set forth in this paragraph (b).
(1) A quarterly RIN-generation report for each facility owned by the renewable fuel producer, and each importer, shall be submitted according to the schedule specified in paragraph (d) of this section, and shall include for the reporting period all of the following information for each batch of renewable fuel produced or imported, where “batch” means a discreet quantity of renewable fuel produced or imported and assigned a unique RIN:
(i) The renewable fuel producer's or importer's name.
(ii) The EPA company registration number.
(iii) The EPA facility registration number.
(iv) The applicable quarterly reporting period.
(v) The RINs generated for each batch according to § 80.1126.
(vi) The production date of each batch.
(vii) The type of renewable fuel of each batch, as defined in § 80.1101(d).
(viii) Information related to the volume of denaturant and applicable equivalence value of each batch.
(ix) The volume of each batch produced or imported.
(x) Any additional information the Administrator may require.
(2) The RIN transaction reports required under paragraph (c)(1) of this section.
(3) The quarterly gallon-RIN activity report required under paragraph (c)(2) of this section.
(4) Reports required under this paragraph (b) must be signed and certified as meeting all the applicable requirements of this subpart by the owner or a responsible corporate officer of the renewable fuel producer.
(c) Any party, including any party specified in paragraphs (a) and (b) of this section, that owns RINs during a reporting period must, beginning November 30, 2007, submit reports to EPA according to the schedule, and containing the information, that is set forth in this paragraph (c).
(1) A RIN transaction report for each RIN transaction shall be submitted by the end of the quarter in which the transaction occurred, according to the schedule specified in paragraph (d) of this section. Each report shall include all of the following:
(i) The submitting party's name.
(ii) The party's EPA company registration number.
(iii) The party's facility registration number, if the report required under paragraph (c)(2) of this section is submitted on a facility-by-facility basis.
(iv) The applicable quarterly reporting period.
(v) Transaction type (RIN purchase, RIN sale, expired RIN, retired RIN).
(vi) Transaction date.
(vii) For a RIN purchase or sale, the trading partner's name.
(viii) For a RIN purchase or sale, the trading partner's EPA company registration number. For all other transactions, the submitting party's EPA company registration number.
(ix) RIN subject to the transaction.
(x) For a retired RIN, the reason for retiring the RIN (
(xi) Any additional information that the Administrator may require.
(2) A quarterly gallon-RIN activity report shall be submitted to EPA according to the schedule specified in paragraph (d) of this section. Each report shall summarize gallon-RIN activities for the reporting period, separately for RINs separated from a renewable fuel volume and RINs assigned to a renewable fuel volume. A RIN owner with more than one facility may submit the report required under this paragraph for each of its facilities individually, or for all of its facilities in the aggregate. The quarterly gallon-RIN activity report shall include all of the following information:
(i) The submitting party's name.
(ii) The party's EPA company registration number.
(iii) Whether the party is submitting the report required under this paragraph on a corporate (aggregate) or facility-by-facility basis.
(iv) The party's EPA facility registration number, if the report required under this paragraph is submitted on a facility-by-facility basis.
(v) Number of current-year gallon-RINs owned at the start of the quarter.
(vi) Number of prior-years gallon-RINs owned at the start of the quarter.
(vii) The total current-year gallon-RINs purchased.
(viii) The total prior-years gallon-RINs purchased.
(ix) The total current-year gallon-RINs sold.
(x) The total prior-years gallon-RINs sold.
(xi) The total current-year gallon-RINs retired.
(xii) The total prior-years gallon-RINs retired.
(xiii) The total current-year gallon-RINs expired (fourth quarter only).
(xiv) The total prior-years gallon-RINs expired (fourth quarter only).
(xv) Number of current-year gallon-RINs owned at the end of the quarter.
(xvi) Number of prior-years gallon-RINs owned at the end of the quarter.
(xvii) For parties reporting gallon-RIN activity under this paragraph for RINs assigned to a volume of renewable fuel, the volume of renewable fuel (in gallons) owned at the end of the quarter.
(xviii) Any additional information that the Administrator may require.
(3) All reports required under this paragraph (c) must be signed and certified as meeting all the applicable requirements of this subpart by the RIN owner or a responsible corporate officer of the RIN owner.
(d) Quarterly reports shall be submitted to EPA by: May 31st for the first calendar quarter of January through March; August 31st for the second calendar quarter of April through June; November 30th for the third calendar quarter of July through September; and February 28th for the fourth calendar quarter of October through December. For 2007, quarterly reports shall commence on November 30, 2007.
(e) Reports required under this section shall be submitted on forms and following procedures as prescribed by EPA.
(a) Any time that a person transfers ownership of renewable fuels subject to this subpart, the transferor must provide to the transferee documents identifying the renewable fuel and any assigned RINs which include all of the following information as applicable:
(1) The name and address of the transferor and transferee.
(2) The transferor's and transferee's EPA company registration number.
(3) The volume of renewable fuel that is being transferred.
(4) The date of the transfer.
(5) Whether any RINs are assigned to the volume, as follows:
(i) If the assigned RINs are being transferred on the same PTD used to transfer ownership of the renewable fuel, then the assigned RINs shall be listed on the PTD.
(ii) If the assigned RINs are being transferred on a separate PTD from that which is used to transfer ownership of the renewable fuel, then the PTD which is used to transfer ownership of the renewable fuel shall state the number of gallon-RINs being transferred as well as a unique reference to the PTD which is transferring the assigned RINs.
(iii) If no assigned RINs are being transferred with the renewable fuel, the PTD which is used to transfer ownership of the renewable fuel shall state “No RINs transferred”.
(b) Except for transfers to truck carriers, retailers, or wholesale purchaser-consumers, product codes may be used to convey the information required under paragraphs (a)(1) through (a)(4) of this section if such codes are clearly understood by each transferee. The RIN number required under paragraph (a)(5) of this section must always appear in its entirety.
(a) Renewable fuel producers located within the United States that produce less than 10,000 gallons of renewable fuel each year, and importers who import less than 10,000 gallons of renewable fuel each year, are not required to generate RINs or to assign RINs to batches of renewable fuel. Such producers and importers that do not generate and/or assign RINs to batches of renewable fuel are also exempt from all the following requirements of this subpart K, except as stated in paragraph (b) of this section:
(1) The registration requirements of § 80.1150.
(2) The recordkeeping requirements of § 80.1151.
(3) The reporting requirements of § 80.1152.
(b) Renewable fuel producers and importers who produce or import less than 10,000 gallons of renewable fuel each year and that generate and/or assign RINs to batches of renewable fuel are subject to the provisions of §§ 80.1150 through 80.1152.
(a) A producer of cellulosic biomass ethanol or waste derived ethanol (hereinafter referred to as “ethanol producer” under this section) is required to arrange for an independent third party to review the records required in § 80.1151(c) and provide the ethanol producer with a written verification that the records support a claim that:
(1) The ethanol producer's facility is a facility that has the capability of producing cellulosic biomass ethanol as defined in § 80.1101(a) or waste derived ethanol as defined in § 80.1101(b); and
(2) The ethanol producer produces cellulosic biomass ethanol as defined in § 80.1101(a) or waste derived ethanol as defined in § 80.1101(b).
(b) The verifications required under paragraph (a) of this section must be conducted by a Professional Chemical Engineer who is based in the United States and is licensed by the appropriate state agency, unless the ethanol producer is a foreign producer subject to § 80.1166.
(c) To be considered an independent third party under paragraph (a) of this section:
(1) The third party shall not be operated by the ethanol producer or any subsidiary of employee of the ethanol producer.
(2) The third party shall be free from any interest in the ethanol producer's business.
(3) The ethanol producer shall be free from any interest in the third party's business.
(4) Use of a third party that is debarred, suspended, or proposed for debarment pursuant to the Government-wide Debarment and Suspension regulations, 40 CFR part 32, or the Debarment, Suspension and Ineligibility provisions of the Federal Acquisition Regulations, 48 CFR, part 9, subpart 9.4, shall be deemed noncompliance with the requirements of this section.
(d) The ethanol producer must obtain the written verification required under paragraph (a)(1) of this section by February 28 of the year following the first year in which the ethanol producer claims to be producing cellulosic biomass ethanol or waste derived ethanol.
(e) The verification in paragraph (a)(2) of this section is required for each calendar year that the ethanol producer claims to be producing cellulosic biomass ethanol or waste derived ethanol. The ethanol producer must obtain the written verification required under paragraph (a)(2) of this section by February 28 for the previous calendar year.
(f) The ethanol producer must retain records of the verifications required under paragraph (a) of this section, as required in § 80.1151(c)(5).
(g) The independent third party shall retain all records pertaining to the verification required under this section for a period of five years from the date of creation and shall deliver such records to the Administrator upon request.
(a)
(b)
(1) Improperly generate a RIN (i.e., generate a RIN for which the applicable renewable fuel volume was not produced).
(2) Create or transfer to any person a RIN that is invalid under § 80.1131.
(3) Transfer to any person a RIN that is not properly identified as required under § 80.1125.
(4) Transfer to any person a RIN with a K code of 1 without transferring an appropriate volume of renewable fuel to the same person on the same day.
(c)
(1) Fail to acquire sufficient RINs, or use invalid RINs, to meet the party's renewable fuel volume obligation under § 80.1127.
(2) Fail to acquire sufficient RINs to meet the party's renewable fuel volume obligation under § 80.1130.
(3) Use a validly generated RIN to meet the party's renewable fuel volume obligation under § 80.1127, or separate and transfer a validly generated RIN, where the party ultimately uses the renewable fuel volume associated with the RIN in a heater or boiler.
(d)
(e)
(a)
(2) Any person who causes another person to violate a prohibition under § 80.1160(a) through (d) is liable for a violation of § 80.1160(e).
(b)
(2) Any person who causes another person to fail to meet a requirement of any provision of this subpart is liable for causing a violation of that provision.
(c)
(d)
(a) Any person who is liable for a violation under § 80.1161 is subject to a civil penalty of up to $32,500, as specified in sections 205 and 211(d) 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 § 80.1161(a) for a violation of § 80.1160(c) for failure to meet a renewable volume obligation, or § 80.1160(e) for causing another party to fail to meet a renewable volume obligation, during any averaging period, is subject to a separate day of violation for each day in the averaging period.
(c) Any person liable under § 80.1161(b) for failure to meet, or causing a failure to meet, a requirement of any provision of this subpart is liable for a separate day of violation for each day such a requirement remains unfulfilled.
The requirements regarding annual attest engagements in §§ 80.125 through 80.127, and 80.130, also apply to any attest engagement procedures required under this subpart. In addition to any other applicable attest engagement procedures, the following annual attest engagement procedures are required under this subpart.
(a) The following attest procedures shall be completed for any obligated party as stated in § 80.1106(a) or exporter of renewable fuel that is subject to the renewable fuel standard under § 80.1105:
(1)
(A) The obligated party's volume of finished gasoline, reformulated gasoline blendstock for oxygenate blending (RBOB), and conventional gasoline blendstock that becomes finished conventional gasoline upon the addition of oxygenate (CBOB) produced or imported during the reporting year.
(B) Renewable volume obligation (RVO).
(C) RINs used for compliance.
(ii) Obtain documentation of any volumes of renewable fuel used in gasoline during the reporting year; compute and report as a finding the volumes of renewable fuel represented in these documents.
(iii) Compare the volumes of gasoline reported to EPA in the report required under § 80.1152(a)(1) with the volumes, excluding any renewable fuel volumes, contained in the inventory reconciliation analysis under § 80.133.
(iii) Verify that the production volume information in the obligated party's annual summary report required under § 80.1152(a)(1) agrees with the volume information, excluding any renewable fuel volumes, contained in the inventory reconciliation analysis under § 80.133.
(iv) Compute and report as a finding the obligated party's RVO, and any deficit RVO carried over from the previous year or carried into the subsequent year, and verify that the values agree with the values reported to EPA.
(v) Obtain documentation for all RINs used for compliance during the year being reviewed; compute and report as a finding the RIN numbers and year of generation of RINs represented in these documents; and state whether this information agrees with the report to EPA.
(2)
(ii) Obtain contracts or other documents for the representative sample of RIN transactions; compute and report as a finding the transaction types, transaction dates, and RINs traded; and state whether the information agrees with the party's reports to EPA.
(3)
(ii) Obtain documentation of total RINs (including current-year RINs and previous-year RINs) owned at the start of the quarter, purchased, used for compliance, sold, expired and retired during the quarter being reviewed, and owned at the end of the quarter; compute and report as a finding the total RINs owned at the start and end of the quarter, purchased, used for compliance, sold, expired and retired as represented in these documents; and state whether this information agrees with the party's reports to EPA.
(b) The following attest procedures shall be completed for any renewable fuel producer or importer:
(1)
(ii) Obtain production data for each renewable fuel batch produced during the year being reviewed; compute and report as a finding the RIN numbers, production dates, types, volumes of denaturant and applicable equivalence values, and production volumes for each batch; and state whether this information agrees with the party's reports to EPA.
(iii) Verify that the proper number of RINs were generated and assigned for each batch of renewable fuel produced, as required under § 80.1126.
(iv) Obtain product transfer documents for each renewable fuel batch produced during the year being reviewed; report as a finding any product transfer document that did not include the RIN for the batch.
(2)
(ii) Obtain contracts or other documents for the representative sample of RIN transactions; compute and report as a finding the transaction types, transaction dates, and the RINs traded; and state whether this information agrees with the party's reports to EPA.
(3)
(ii) Obtain documentation of total RINs (including current-year RINs and previous-year RINs) owned at the start of the quarter, purchased, sold, expired and retired during the quarter being reviewed, and owned at the end of the quarter; compute and report as a finding the total RINs owned at the start and end of the quarter, purchased, used for compliance, sold, expired and retired as represented in these documents; and state whether this information agrees with the party's reports to EPA.
(c) The following attest procedures shall be completed for any party other than an obligated party or renewable fuel producer or importer that owns any RINs during a calendar year.
(1)
(ii) Obtain contracts or other documents for the representative sample of RIN transactions; compute and report as a finding the transaction types, transaction dates, and the RINs traded; and state whether this information agrees with the party's reports to EPA.
(2)
(ii) Obtain documentation of total RINs (including current-year RINs and previous-year RINs) owned at the start of the quarter, purchased, sold, expired and retired during the quarter being reviewed, and owned at the end of the quarter; compute and report as a finding the total RINs owned at the start and end of the quarter, purchased, used for compliance, sold, expired and retired as represented in these documents; and state whether this information agrees with the party's reports to EPA.
(d) The following submission dates apply to the attest engagements required under this section.
(1) For each compliance year, each party subject to the attest engagement requirements under this section shall cause the reports required under this section to be submitted to EPA by May 31 of the year following the compliance year.
(2) For the 2007 compliance year only, the attest engagement required under paragraph (a) of this section may be submitted to EPA with the attest engagement for the 2008 compliance year.
(a)
(1)
(2)
(3)
(4)
(i) Gasoline produced at a foreign refinery that has received a small refinery exemption under § 80.1141 or a small refiner exemption under § 80.1142 that is not imported into the United States.
(ii) Gasoline produced at a foreign refinery that has not received a small refinery exemption under § 80.1141 or small refiner exemption under § 80.1142.
(5) A foreign small refiner is a foreign refiner that has received a small refinery exemption under § 80.1141 for one or more of its refineries or a small refiner exemption under § 80.1142.
(b)
(1) A foreign small refiner must designate, at the time of production, each batch of gasoline produced at the foreign refinery that is exported for use in the United States as RFS-FRGAS; and
(2) Meet all requirements that apply to refiners who have received a small refinery or small refiner exemption under this subpart.
(c)
(2) On each occasion when RFS-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 RFS-FRGAS that meets all the following requirements:
(i) The certification shall include the report of the independent third party under paragraph (d) of this section, and all the following additional information:
(A) The name and EPA registration number of the refinery that produced the RFS-FRGAS.
(B) [Reserved]
(ii) The identification of the gasoline as RFS-FRGAS.
(iii) The volume of RFS-FRGAS being transported, in gallons.
(3) On each occasion when any person transfers custody or title to any RFS-FRGAS prior to its being imported into the United States, it must include all the following information as part of the product transfer document information:
(i) Designation of the gasoline as RFS-FRGAS.
(ii) The certification required under paragraph (c)(2) of this section.
(d)
(i) Inspect the vessel prior to loading and determine the volume of any tank bottoms.
(ii) Determine the volume of RFS-FRGAS loaded onto the vessel (exclusive of any tank bottoms before 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 RFS-FRGAS to the United States.
(v) Determine the date and time the vessel departs the port serving the foreign refinery.
(vi) Review original documents that reflect movement and storage of the RFS-FRGAS from the foreign refinery to the load port, and from this review determine:
(A) The refinery at which the RFS-FRGAS was produced; and
(B) That the RFS-FRGAS remained segregated from Non-RFS-FRGAS and other RFS-FRGAS produced at a different refinery.
(2) The independent third party shall submit a report to:
(i) The foreign small refiner containing the information required under paragraph (d)(1) of this section, to accompany the product transfer documents for the vessel; and
(ii) The Administrator containing the information required under paragraph (d)(1) 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 (j)(1) of this section, and a description of the gasoline's movement and storage between production at the source refinery and vessel loading.
(3) 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 (d);
(ii) Be independent under the criteria specified in § 80.65(f)(2)(iii); and
(iii) Sign a commitment that contains the provisions specified in paragraph (f) of this section with regard to activities, facilities, and documents relevant to compliance with the requirements of this paragraph (d).
(e)
(ii) Where a vessel transporting RFS-FRGAS off loads this gasoline at more than one United States port of entry, the requirements of paragraph (e)(1)(i) of this section do not apply at subsequent ports of entry if the United States importer obtains a certification from the vessel owner that the requirements of paragraph (e)(1)(i) of this section were met and 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) If the temperature-corrected volumes determined at the port of entry and at the load port differ by more than one percent, the United States importer and the foreign small refiner shall not treat the gasoline as RFS-FRGAS and the importer shall include the volume of gasoline in the importer's RFS compliance calculations.
(f)
(1) Any United States Environmental Protection Agency inspector or auditor must 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; and
(C) RFS-FRGAS is stored or transported between the foreign refinery and the United States, including storage tanks, vessels and pipelines.
(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 must 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 all the following:
(A) The volume of RFS-FRGAS.
(B) The proper classification of gasoline as being RFS-FRGAS or as not being RFS-FRGAS.
(C) Transfers of title or custody to RFS-FRGAS.
(D) Testing of RFS-FRGAS.
(E) Work performed and reports prepared by independent third parties and by independent auditors under the requirements of this section, including work papers.
(vi) Inspections and audits by EPA may include taking interviewing employees.
(vii) Any employee of the foreign refiner must 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 must be provided to an EPA inspector or auditor, on request, within 10 working days.
(ix) English language interpreters must be provided to accompany EPA inspectors and auditors, on request.
(2) An agent for service of process located in the District of Columbia shall 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.
(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 an application for a small refinery or small refiner exemption, or producing and exporting gasoline under such exemption, and all other actions to comply with the requirements of this subpart relating to such exemption constitute actions or activities covered by and within the meaning of the provisions of 28 U.S.C. 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, including conduct that violates the False
(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 (f) shall be signed by the owner or president of the foreign refiner business.
(8) In any case where RFS-FRGAS produced at a foreign refinery is stored or transported by another company between the refinery and the vessel that transports the RFS-FRGAS to the United States, the foreign refiner shall obtain from each such other company a commitment that meets the requirements specified in paragraphs (f)(1) through (f)(7) of this section, and these commitments shall be included in the foreign refiner's application for a small refinery or small refiner exemption under this subpart.
(g)
(h)
(1) 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) Bonds posted under this paragraph (h) 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, including where such conduct violates the False Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
(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
(iii) Include a commitment that the bond will remain in effect for at least five years following the end of latest annual reporting period that the foreign refiner produces gasoline pursuant to the requirements of this subpart.
(4) 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.
(5) If the bond amount for a foreign refiner 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.
(i)
(j)
(2) No foreign refiner or other person may cause another person to commit an action prohibited in paragraph (j)(1) of this section, or that otherwise violates the requirements of this section.
(k)
(1) Each batch of imported RFS-FRGAS shall be classified by the importer as being RFS-FRGAS.
(2) Gasoline shall be classified as RFS-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 (c) of this section. Additionally, the importer shall comply with all requirements of this subpart applicable to importers.
(3) For each gasoline batch classified as RFS-FRGAS, any United States importer shall have an independent third party do all the following:
(i) Determine the volume of gasoline in the vessel.
(ii) Use the foreign refiner's RFS-FRGAS certification to determine the name and EPA-assigned registration number of the foreign refinery that produced the RFS-FRGAS.
(iii) Determine the name and country of registration of the vessel used to transport the RFS-FRGAS to the United States.
(iv) Determine the date and time the vessel arrives at the United States port of entry.
(4) Any importer shall submit reports within 30 days following the date any vessel transporting RFS-FRGAS arrives at the United States port of entry to:
(i) The Administrator containing the information determined under paragraph (k)(3) of this section; and
(ii) The foreign refiner containing the information determined under paragraph (k)(3)(i) of this section, and including identification of the port at which the product was off loaded.
(5) Any United States importer shall meet all other requirements of this subpart for any imported gasoline that is not classified as RFS-FRGAS under paragraph (k)(2) of this section.
(l)
(i) Certification under paragraph (c)(2) of this section.
(ii) Load port and port of entry testing requirements under paragraphs (d) and (e) of this section.
(iii) Importer testing requirements under paragraph (k)(3) of this section.
(2) These alternative procedures must ensure RFS-FRGAS remains segregated from Non-RFS-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 RFS-FRGAS from that refinery from all other gasoline.
(ii) Contracts with any terminals and/or pipelines that receive and/or transport RFS-FRGAS that prohibit the commingling of RFS-FRGAS with Non-RFS-FRGAS or RFS-FRGAS from other foreign refineries.
(iii) 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 RFS-FRGAS remains segregated throughout the distribution system.
(3) The petition described in this section must be submitted to EPA along with the application for a small refinery or small refiner exemption under this subpart.
(m)
(1) Obtain listings of all tenders of RFS-FRGAS. Agree the total volume of tenders from the listings to the gasoline inventory reconciliation analysis required in § 80.133(b), and to the volumes determined by the third party under paragraph (d) of this section.
(2) For each tender under paragraph (m)(1) 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 RFS-FRGAS loaded onto each vessel.
(3) Select a sample from the list of vessels identified in paragraph (m)(2) of this section used to transport RFS-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 (d) of this section.
(A) Agree the information in these reports with regard to vessel identification and gasoline volume.
(B) Identify, and report as a finding, each occasion the load port and port of entry volume results differ by more than the amount allowed in paragraph (e)(2) of this section, and determine whether all of the requirements of paragraph (e)(2) of this section have been met.
(ii) Obtain the documents used by the independent third party to determine transportation and storage of the RFS-FRGAS from the refinery to the load port, under paragraph (d) of this section. Obtain tank activity records for any storage tank where the RFS-FRGAS is stored, and pipeline activity records for any pipeline used to transport the RFS-FRGAS prior to being loaded onto the vessel. Use these records to determine whether the RFS-FRGAS was produced at the refinery that is the subject of the attest engagement, and whether the RFS-FRGAS was mixed with any Non-RFS-FRGAS or any RFS-FRGAS produced at a different refinery.
(4) Select a sample from the list of vessels identified in paragraph (m)(2) of this section used to transport RFS-FRGAS, in accordance with the guidelines in § 80.127, and for each vessel selected perform the following:
(i) 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.
(ii) 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.
(5) Obtain separate listings of all tenders of RFS-FRGAS, and perform the following:
(i) Agree the volume of tenders from the listings to the gasoline inventory reconciliation analysis in § 80.133(b).
(ii) Obtain a separate listing of the tenders under this paragraph (m)(5) 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.
(6) In order to complete the requirements of this paragraph (m), an auditor shall:
(i) Be independent of the foreign refiner or importer;
(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 80.127, 80.130, 80.1164, and this paragraph (m); and
(iii) Sign a commitment that contains the provisions specified in paragraph (f) of this section with regard to activities and documents relevant to compliance with the requirements of §§ 80.125 through 80.127, 80.130, 80.1164, and this paragraph (m).
(n)
(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 (f)(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; 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 (h) of this section.
(o)
(1) Submitted in accordance with procedures specified by the Administrator, including use of any forms that may be specified by the Administrator.
(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 [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 K, 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
(a)
(b)
(2)(i) The independent third party that conducts the facility verification required under § 80.1155(a) must inspect the foreign producer's facility and submit a report to EPA which describes in detail the physical plant and its operation.
(ii) The independent third party that conducts the facility verification required under § 80.1155(a) must be a licensed Professional Engineer in the chemical engineering field, but need not be based in the United States. The independent third party must include documentation of its qualifications as a licensed Professional Engineer in the report required in paragraph (b)(2)(i) of this section.
(iii) The requirements of paragraphs (b)(2)(i) and (ii) of this section must be met before a foreign entity may be approved as a foreign producer under this subpart.
(c)
(1) Any approved foreign producer under this section must designate each batch of cellulosic biomass ethanol or waste derived ethanol as “RFS-FRETH” at the time the ethanol is produced.
(2) On each occasion when RFS-FRETH is loaded onto a vessel or other transportation mode for transport to the United States, the foreign producer shall prepare a certification for each batch of RFS-FRETH; the certification shall include the report of the independent third party under paragraph (d) of this section, and all the following additional information:
(i) The name and EPA registration number of the company that produced the RFS-FRETH.
(ii) The identification of the ethanol as RFS-FRETH.
(iii) The volume of RFS-FRETH being transported, in gallons.
(3) On each occasion when any person transfers custody or title to any RFS-FRETH prior to its being imported into the United States, it must include all the following information as part of the product transfer document information:
(i) Designation of the ethanol as RFS-FRETH.
(ii) The certification required under paragraph (c)(2) of this section.
(d)
(i) Inspect the vessel prior to loading and determine the volume of any tank bottoms.
(ii) Determine the volume of RFS-FRETH loaded onto the vessel (exclusive of any tank bottoms before loading).
(iii) Obtain the EPA-assigned registration number of the foreign producer.
(iv) Determine the name and country of registration of the vessel used to transport the RFS-FRETH to the United States.
(v) Determine the date and time the vessel departs the port serving the foreign producer.
(vi) Review original documents that reflect movement and storage of the RFS-FRETH from the foreign producer to the load port, and from this review determine the following:
(A) The facility at which the RFS-FRETH was produced.
(B) That the RFS-FRETH remained segregated from Non-RFS-FRETH and other RFS-FRETH produced by a different foreign producer.
(2) The independent third party shall submit a report to the following:
(i) The foreign producer containing the information required under paragraph (d)(1) of this section, to accompany the product transfer documents for the vessel.
(ii) The Administrator containing the information required under paragraph (d)(1) 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 foreign producer facility at which the ethanol was produced, assurance that the ethanol remained segregated as specified in paragraph (j)(1) of this section, and a description of the ethanol's movement and storage between production at the source facility and vessel loading.
(3) 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 (d);
(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 (f) of this section with regard to activities, facilities and documents relevant to compliance with the requirements of this paragraph (d).
(e)
(ii) Where a vessel transporting RFS-FRETH off loads the ethanol at more than one United States port of entry, the requirements of paragraph (e)(1)(i) of this section do not apply at subsequent ports of entry if the United States importer obtains a certification from the vessel owner that the requirements of paragraph (e)(1)(i) of this section were met and that the vessel has not loaded any ethanol between the first United States port of entry and the subsequent port of entry.
(2)(i) If the temperature-corrected volumes determined at the port of entry and at the load port differ by more than one percent, the number of RINs associated with the ethanol shall be calculated based on the lesser of the two volumes in paragraph (e)(1)(i) of this section.
(ii) Where the port of entry volume is the lesser of the two volumes in paragraph (e)(1)(i) of this section, the importer shall calculate the difference between the number of RINs originally assigned by the foreign producer and
(f)
(1) Any United States Environmental Protection Agency inspector or auditor must be given full, complete and immediate access to conduct inspections and audits of the foreign producer facility.
(i) Inspections and audits may be either announced in advance by EPA, or unannounced.
(ii) Access will be provided to any location where:
(A) Ethanol is produced;
(B) Documents related to ethanol producer operations are kept; and
(C) RFS-FRETH is stored or transported between the foreign producer and the United States, including storage tanks, vessels and pipelines.
(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 must 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 the following:
(A) The volume of RFS-FRETH.
(B) The proper classification of gasoline as being RFS-FRETH;
(C) Transfers of title or custody to RFS-FRETH.
(D) Work performed and reports prepared by independent third parties and by independent auditors under the requirements of this section, including work papers.
(vi) Inspections and audits by EPA may include interviewing employees.
(vii) Any employee of the foreign producer must 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 must be provided to an EPA inspector or auditor, on request, within 10 working days.
(ix) English language interpreters must be provided to accompany EPA inspectors and auditors, on request.
(2) An agent for service of process located in the District of Columbia shall be named, and service on this agent constitutes service on the foreign producer or any employee of the foreign producer for any action by EPA or otherwise by the United States related to the requirements of this subpart.
(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 producer or any employee of the foreign producer related to the provisions of this section.
(5) Applying to be an approved foreign producer under this section, or producing or exporting ethanol under such approval, and all other actions to comply with the requirements of this subpart relating to such approval constitute actions or activities covered by and within the meaning of the provisions of 28 U.S.C. 1605(a)(2), but solely with respect to actions instituted against the foreign producer, its agents and employees in any court or other tribunal in the United States for conduct that violates the requirements applicable to the foreign producer under this subpart, including conduct that violates the False Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413).
(6) The foreign producer, 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 (f) shall be signed by the owner or president of the foreign producer company.
(8) In any case where RFS-FRETH produced at a foreign producer facility is stored or transported by another company between the refinery and the vessel that transports the RFS-FRETH to the United States, the foreign producer shall obtain from each such other company a commitment that meets the requirements specified in paragraphs (f)(1) through (7) of this section, and these commitments shall be included in the foreign producer's application to be an approved foreign producer under this subpart.
(g)
(h)
(1) The foreign producer shall post a bond of the amount calculated using the following equation:
(2) Bonds shall be posted by any of the following methods:
(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 producer, provided EPA agrees in advance as to the third party and the nature of the surety agreement.
(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) Bonds posted under this paragraph (h) 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, including where such conduct violates the False Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
(ii) Be provided by a corporate surety that is listed in the United States
(iii) Include a commitment that the bond will remain in effect for at least five years following the end of the latest annual reporting period that the foreign producer produces ethanol pursuant to the requirements of this subpart.
(4) On any occasion a foreign producer bond is used to satisfy any judgment, the foreign producer shall increase the bond to cover the amount used within 90 days of the date the bond is used.
(5) If the bond amount for a foreign producer increases, the foreign producer 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.
(i)
(j)
(2) No foreign producer or other person may cause another person to commit an action prohibited in paragraph (j)(1) of this section, or that otherwise violates the requirements of this section.
(k)
(1) Each batch of imported RFS-FRETH shall be classified by the importer as being RFS-FRETH.
(2) Ethanol shall be classified as RFS-FRETH according to the designation by the foreign producer if this designation is supported by product transfer documents prepared by the foreign producer as required in paragraph (c) of this section.
(3) For each ethanol batch classified as RFS-FRETH, any United States importer shall have an independent third party do all the following:
(i) Determine the volume of gasoline in the vessel.
(ii) Use the foreign producer's RFS-FRETH certification to determine the name and EPA-assigned registration number of the foreign producer that produced the RFS-FRETH.
(iii) Determine the name and country of registration of the vessel used to transport the RFS-FRETH to the United States.
(iv) Determine the date and time the vessel arrives at the United States port of entry.
(4) Where the importer is required to retire RINs under paragraph (e)(2) of this section, the importer must report the retired RINs in the applicable reports under § 80.1152.
(5) Any importer shall submit reports within 30 days following the date any vessel transporting RFS-FRETH arrives at the United States port of entry to the following:
(i) The Administrator containing the information determined under paragraph (k)(3) of this section.
(ii) The foreign producer containing the information determined under paragraph (k)(3)(i) of this section, and including identification of the port at which the product was off loaded, and any RINs retired under paragraph (e)(2) of this section.
(6) Any United States importer shall meet all other requirements of this subpart for any imported ethanol or other renewable fuel that is not classified as RFS-FRETH under paragraph (k)(2) of this section.
(l)
(i) Certification under paragraph (c)(2) of this section.
(ii) Load port and port of entry testing under paragraphs (d) and (e) of this section.
(iii) Importer testing under paragraph (k)(3) of this section.
(2) These alternative procedures must ensure RFS-FRETH remains segregated from Non-RFS-FRETH until it is imported into the United States. The petition will be evaluated based on whether it adequately addresses the following:
(i) Contracts with any facilities that receive and/or transport RFS-FRETH that prohibit the commingling of RFS-FRETH with Non-RFS-FRETH or RFS-FRETH from other foreign producers.
(ii) Attest procedures to be conducted annually by an independent third party that review loading records and import documents based on volume reconciliation to confirm that all RFS-FRETH remains segregated.
(3) The petition described in this section must be submitted to EPA along with the application for approval as a foreign producer under this subpart.
(m)
(1) Obtain listings of all tenders of RFS-FRETH. Agree the total volume of tenders from the listings to the volumes determined by the third party under paragraph (d) of this section.
(2) For each tender under paragraph (m)(1) of this section, where the ethanol is loaded onto a marine vessel, report as a finding the name and country of registration of each vessel, and the volumes of RFS-FRETH loaded onto each vessel.
(3) Select a sample from the list of vessels identified in paragraph (m)(2) of this section used to transport RFS-FRETH, 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 (d) of this section, and of the United States importer under paragraph (k) of this section.
(A) Agree the information in these reports with regard to vessel identification and ethanol volume.
(B) Identify, and report as a finding, each occasion the load port and port of entry volume results differ by more than the amount allowed in paragraph (e) of this section, and determine whether the importer retired the appropriate amount of RINs as required under paragraph (e)(2) of this section, and submitted the applicable reports under § 80.1152 in accordance with paragraph (k)(4) of this section.
(ii) Obtain the documents used by the independent third party to determine transportation and storage of the RFS-FRETH from the foreign producer's facility to the load port, under paragraph (d) of this section. Obtain tank activity records for any storage tank where the RFS-FRETH is stored, and activity records for any mode of transportation used to transport the RFS-FRGAS prior to being loaded onto the vessel. Use these records to determine whether the RFS-FRETH was produced at the foreign producer's facility that is the subject of the attest engagement, and whether the RFS-FRETH was mixed with any Non-RFS-FRETH or any RFS-FRETH produced at a different facility.
(4) Select a sample from the list of vessels identified in paragraph (m)(2) of this section used to transport RFS-FRETH, in accordance with the guidelines in § 80.127, and for each vessel selected perform the following:
(i) 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.
(ii) 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.
(5) Obtain a separate listing of the tenders under this paragraph (m)(5) 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 ethanol was off loaded for the selected vessels. Determine and report as a finding the country where the ethanol was off loaded for each vessel selected.
(6) In order to complete the requirements of this paragraph (m) an auditor shall:
(i) Be independent of the foreign producer;
(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 80.127, 80.130, 80.1164, and this paragraph (m); and
(iii) Sign a commitment that contains the provisions specified in paragraph (f) of this section with regard to activities and documents relevant to compliance with the requirements of §§ 80.125 through 80.127, 80.130, 80.1164, and this paragraph (m).
(n)
(1) A foreign producer fails to meet any requirement of this section.
(2) A foreign government fails to allow EPA inspections as provided in paragraph (f)(1) of this section.
(3) A foreign producer asserts a claim of, or a right to claim, sovereign immunity in an action to enforce the requirements in this subpart.
(4) A foreign producer fails to pay a civil or criminal penalty that is not satisfied using the foreign producer bond specified in paragraph (g) of this section.
(o)
(1) Submitted in accordance with procedures specified by the Administrator, including use of any forms that may be specified by the Administrator.
(2) Signed by the president or owner of the foreign producer 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 producer] 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 K, 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 K, including 40 CFR 80.1165 apply to [insert name of foreign producer]. Pursuant to Clean Air Act section 113(c) and 18 U.S.C. 1001, the penalty for furnishing false, incomplete or misleading information in this certification or submission is a fine of up to $10,000 U.S., and/or imprisonment for up to five years.
(a)
(b)
(c)
(1) Any United States Environmental Protection Agency inspector or auditor must be given full, complete and immediate access to conduct inspections and audits of the foreign RIN owner's place of business.
(i) Inspections and audits may be either announced in advance by EPA, or unannounced; and
(ii) Access will be provided to any location where documents related to RINs the foreign RIN owner has obtained, sold, transferred or held are kept.
(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 must 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 the following:
(A) Transfers of title to RINs.
(B) Work performed and reports prepared by independent auditors under the requirements of this section, including work papers.
(vi) Inspections and audits by EPA may include interviewing employees.
(vii) Any employee of the foreign RIN owner must 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 must be provided to an EPA inspector or auditor, on request, within 10 working days.
(ix) English language interpreters must be provided to accompany EPA inspectors and auditors, on request.
(2) An agent for service of process located in the District of Columbia shall be named, and service on this agent constitutes service on the foreign RIN owner or any employee of the foreign RIN owner for any action by EPA or otherwise by the United States related to the requirements of this subpart.
(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 RIN owner or any employee of the foreign RIN owner related to the provisions of this section.
(5) Submitting an application to be a foreign RIN owner, and all other actions to comply with the requirements of this subpart constitute actions or activities covered by and within the meaning of the provisions of 28 U.S.C. 1605(a)(2), but solely with respect to actions instituted against the foreign RIN owner, its agents and employees in any court or other tribunal in the United States for conduct that violates the requirements applicable to the foreign RIN owner under this subpart, including conduct
(6) The foreign RIN owner, 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 (c) shall be signed by the owner or president of the foreign RIN owner business.
(d)
(e)
(1) The foreign entity shall post a bond of the amount calculated using the following equation:
(2) Bonds shall be posted by doing any of the following:
(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 RIN owner, provided EPA agrees in advance as to the third party and the nature of the surety agreement.
(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) Bonds posted under this paragraph (e) 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, including where such conduct violates the False Statements Accountability Act of 1996 (18 U.S.C. 1001) and section 113(c)(2) of the Clean Air Act (42 U.S.C. 7413);
(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
(iii) Include a commitment that the bond will remain in effect for at least five years following the end of latest reporting period in which the foreign RIN owner obtains, sells, transfers or holds RINs.
(4) On any occasion a foreign RIN owner bond is used to satisfy any judgment, the foreign RIN owner shall increase the bond to cover the amount used within 90 days of the date the bond is used.
(f)
(g)
(2) Any RIN that is sold, transferred or held that is in excess of the number for which the bond requirements of this section have been satisfied is an invalid RIN under § 80.1131.
(3) Any RIN that is obtained from a person located outside the United States that is not an approved foreign RIN owner under this section is an invalid RIN under § 80.1131.
(4) No foreign RIN owner or other person may cause another person to commit an action prohibited in this paragraph (g), or that otherwise violates the requirements of this section.
(h)
(1) The attest auditor must be independent of the foreign RIN owner.
(2) The attest auditor must 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 80.127, 80.130, and 80.1164.
(3) The attest auditor must sign a commitment that contains the provisions specified in paragraph (c) of this section with regard to activities and documents relevant to compliance with the requirements of §§ 80.125 through 80.127, 80.130, and 80.1164.
(i)
(1) A foreign RIN owner fails to meet any requirement of this section, including, but not limited to, the bond requirements.
(2) A foreign government fails to allow EPA inspections as provided in paragraph (c)(1) of this section.
(3) A foreign RIN owner asserts a claim of, or a right to claim, sovereign immunity in an action to enforce the requirements in this subpart.
(4) A foreign RIN owner fails to pay a civil or criminal penalty that is not satisfied using the foreign RIN owner bond specified in paragraph (e) of this section.
(j)
(1) Submitted in accordance with procedures specified by the Administrator, including use of any forms that may be specified by the Administrator.
(2) Signed by the president or owner of the foreign RIN owner company, or
I hereby certify: (1) That I have actual authority to sign on behalf of and to bind [insert name of foreign RIN owner] 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 K, 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 K, including 40 CFR 80.1167 apply to [insert name of foreign RIN owner]. Pursuant to Clean Air Act section 113(c) and 18 U.S.C. 1001, the penalty for furnishing false, incomplete or misleading information in this certification or submission is a fine of up to $10,000 U.S., and/or imprisonment for up to five years.
Environmental Protection Agency (EPA).
Notice.
The Safe Drinking Water Act (SDWA), as amended in 1996, requires the Environmental Protection Agency (EPA) to make regulatory determinations on at least five unregulated contaminants and decide whether to regulate these contaminants with a national primary drinking water regulation (NPDWR). SDWA requires that these determinations be made every five years. These unregulated contaminants are typically chosen from a list known as the Contaminant Candidate List (CCL), which SDWA requires the Agency to publish every five years. EPA published the second CCL (CCL 2) in the
Comments must be received on or before July 2, 2007.
Submit your comments, identified by Docket ID No. EPA-HQ-OW-2007-0068, by one of the following methods:
•
•
•
Wynne Miller, Office of Ground Water and Drinking Water, Standards and Risk Management Division, at (202) 564-4887 or e-mail
None of these preliminary regulatory determinations or the final regulatory determinations, when published, will impose any requirements on anyone. Instead, this action notifies interested parties of the availability of EPA's preliminary regulatory determinations for 11 of the 51 contaminants listed on CCL 2 and seeks comment on these preliminary determinations. This action also provides an update on the Agency's review of perchlorate and methyl tertiary butyl ether (MTBE).
You may find the following suggestions helpful for preparing your comments:
1. Explain your views as clearly as possible.
2. Describe any assumptions that you used.
3. Provide any technical information and/or data you used that support your views.
4. If you estimate potential burden or costs, explain how you arrived at your estimate.
5. Provide specific examples to illustrate your concerns.
6. Offer alternatives.
7. Make sure to submit your comments by the comment period deadline.
8. To ensure proper receipt by EPA, identify the appropriate docket identification number in the subject line on the first page of your response. It would also be helpful if you provided the name, date, and
This section briefly summarizes the purpose of this action, the statutory requirements, previous activities related to the Contaminant Candidate List and regulatory determinations, and the approach used and outcome of these preliminary regulatory determinations.
The Safe Drinking Water Act (SDWA), as amended in 1996, requires EPA to publish a list of currently unregulated contaminants that may pose risks for drinking water (referred to as the Contaminant Candidate List, or CCL) and to make determinations on whether to regulate at least five contaminants from the CCL with a national primary drinking water regulation (NPDWR)
The 11 regulatory determination contaminants candidates discussed in this action are boron, the dacthal mono- and di-acid degradates, 1,1-dichloro-2,2-bis(p-chlorophenyl)ethylene (DDE), 1,3-dichloropropene, 2,4-dinitrotoluene, 2,6-dinitrotoluene, s-ethyl propylthiocarbamate (EPTC), fonofos, terbacil, and 1,1,2,2-tetrachloroethane.
1. Statutory Requirements for CCL and Regulatory Determinations. The specific statutory requirements for the CCL and regulatory determinations can be found in SDWA section 1412(b)(1). The 1996 SDWA Amendments require EPA to publish the CCL every five years. The CCL is a list of contaminants that are not subject to any proposed or promulgated NPDWRs, are known or anticipated to occur in public water systems (PWSs), and may require regulation under SDWA. The 1996 SDWA Amendments also direct EPA to determine whether to regulate at least five contaminants from the CCL every five years (within three and one-half years after publication of the final list). In making regulatory determinations, SDWA requires EPA to publish a Maximum Contaminant Level Goal
(a) The contaminant may have an adverse effect on the health of persons;
(b) the contaminant is known to occur or there is a substantial likelihood that the contaminant will occur in public water systems with a frequency and at levels of public health concern; and
(c) In the sole judgment of the Administrator, regulation of such contaminant presents a meaningful opportunity for health risk reduction for persons served by public water systems.
If EPA determines that all three of these statutory criteria are met and makes a final determination that a national primary drinking water regulation is needed, the Agency has 24 months to publish a proposed MCLG and NPDWR. After the proposal, the Agency has 18 months to publish and promulgate a final MCLG and NPDWR (SDWA section 1412(b)(1)(E)).
2. The First Contaminant Candidate List (CCL 1). Following the 1996 SDWA Amendments, EPA sought input from the National Drinking Water Advisory Council (NDWAC) on the process that should be used to identify contaminants for inclusion on the CCL. For chemical contaminants, the Agency developed screening and evaluation criteria based on recommendations from NDWAC. For microbiological contaminants, NDWAC recommended that the Agency seek external expertise to identify and select potential waterborne pathogens. As a result, the Agency convened a workshop of microbiologists and public health experts who developed criteria for screening and evaluation and subsequently developed an initial list of potential microbiological contaminants.
The first CCL process benefited from considerable input from the NDWAC, the scientific community, and the public through stakeholder meetings and the public comments received on the draft CCL published on October 6, 1997 (62 FR 52193 (USEPA, 1997a)). EPA published the final CCL, which contained 50 chemical and 10 microbiological contaminants, on March 2, 1998 (63 FR 10273 (USEPA, 1998a)). A more detailed discussion of how EPA developed CCL 1 can be found in the 1997 and the 1998
3. The Regulatory Determinations for CCL 1. EPA published its preliminary regulatory determinations for a subset of contaminants listed on CCL 1 on June 3, 2002 (67 FR 38222 (USEPA, 2002a)). The Agency published its final regulatory determinations on July 18, 2003 (68 FR 42898 (USEPA, 2003a)). EPA identified 9 contaminants from the 60 contaminants listed on CCL 1 that had sufficient data and information available to make regulatory determinations. The 9 contaminants were
The decision-making process that EPA used to make its regulatory determinations for CCL 1 was based on substantial expert input and recommendations from different groups including stakeholders, the National Research Council (NRC) and NDWAC. In June 2002, EPA consulted with the Science Advisory Board (SAB) Drinking Water Committee and requested its review and comment on whether the protocol EPA developed, based on the NDWAC recommendations, was consistently applied and appropriately documented. SAB provided verbal feedback regarding the use of the NRC and NDWAC recommendations in EPA's decision criteria for making its regulatory determinations. SAB recommended that the Agency provide a transparent and clear explanation of the process for making regulatory determinations. The Agency took SAB's recommendation into consideration and further explained the CCL 1 regulatory determination evaluation process in the July 18, 2003 (68 FR 42898 (USEPA, 2003a)) notice and in the supporting documentation.
EPA has used the same approach to develop the regulatory determinations discussed in this action. While this action includes a short description of the decision process used to make regulatory determinations (section II.C), a more detailed discussion can be found in the 2002 and the 2003
4. The Second Contaminant Candidate List (CCL 2). The Agency published its draft CCL 2
5. The Regulatory Determinations for CCL 2. This current action discusses EPA's preliminary determinations for 11 of the 51 contaminants listed on the CCL 2.
Figure 1 provides a brief overview of the process EPA used to identify which CCL 2 contaminants are candidates for regulatory determinations and the SDWA statutory criteria considered in making the regulatory determinations.
In identifying which CCL 2 contaminants are candidates for regulatory determinations, the Agency considered whether sufficient information and/or data were available to characterize the potential health effects and the known/likely occurrence in and exposure from drinking water. With regards to sufficient health effects information/data, the Agency considered whether an Agency-approved health risk assessment
If EPA chose a contaminant as a candidate for regulatory determination, the Agency used an approach similar to the first regulatory determination process to answer the three statutory criteria (listed in section II.B.1).
For the current regulatory determination process, the Agency considered the following in evaluating each of the three statutory criteria.
(1) First statutory criterion—Is the contaminant likely to cause an adverse effect on the health of persons? The Agency evaluated the best available, peer-reviewed assessments and studies to characterize the human health effects that may result from exposure to the contaminant when found in drinking water. Based on this characterization, the Agency estimated a health reference level (HRL) for each contaminant. Section III.A provides more detailed information about the approach used to evaluate and analyze the health information.
(2) Second statutory criterion—Is the contaminant known or likely to occur in public water systems at a frequency and level of concern? To evaluate known occurrence in PWSs, the Agency compiled, screened, and analyzed data from several occurrence data sets to develop representative occurrence estimates for public drinking water systems. EPA used the HRL estimates for each contaminant as a benchmark against which to conduct an initial evaluation or screening of the occurrence data. For each contaminant, EPA estimated the number of PWSs (and the population served by these PWSs) with detections greater than one-half the HRL (> 1/2 HRL) and greater than the HRL (> HRL). To evaluate the likelihood of a contaminant to occur in drinking water, the Agency considered information on the use and release of a contaminant into the environment and supplemental information on occurrence in water (
(3) Third statutory criterion—In the sole judgment of the Administrator, does regulation of the contaminant present a meaningful opportunity for health risk reduction for persons served by public water systems? EPA evaluated the potential health effects and the results of the occurrence and exposure estimates (i.e., the population exposed and the sources of exposure) at the health level of concern to determine if regulation presents a meaningful opportunity for health risk reduction. EPA has made a preliminary determination regarding the meaningful opportunity for health risk reduction for 11 contaminants based upon the population exposed to these contaminants at levels of concern.
If the answers to all three statutory criteria are affirmative for a particular contaminant, then the Agency makes a determination that a national drinking water regulation is necessary and proceeds to develop an MCLG and a national primary drinking water regulation for that contaminant. It should be noted that this regulatory determination process is independent of the more detailed analyses needed to develop a national primary drinking water regulation. Thus, a decision to regulate is the beginning of the Agency regulatory development process, not the end.
If the answer to any of the three statutory criteria is negative, then the Agency makes a determination that a national drinking water regulation is not necessary for that contaminant.
EPA has made preliminary determinations that no regulatory actions are appropriate for the 11 contaminants evaluated for this second round of regulatory determinations. EPA will make final determinations on these 11 contaminants after a 60-day comment period. EPA is making preliminary regulatory determinations only on those CCL 2 contaminants that have sufficient information to support such a determination at this time. The Agency continues to conduct research and/or to collect information on the remaining CCL 2 contaminants to fill identified data gaps. The Agency is not precluded from taking action when information becomes available and will not necessarily wait until the end of the next regulatory determination cycle before making other regulatory determinations.
For this action, EPA prepared several support documents that are available for review and comment in the EPA Water Docket and at
• A comprehensive regulatory support document entitled, “Regulatory Determinations Support Document for Selected Contaminants from the Second Drinking Water Contaminant Candidate List” (CCL 2) (USEPA, 2006a). This support document summarizes the information and data on the physical and chemical properties, uses and environmental release, environmental fate, potential health effects, occurrence and exposure estimates, the preliminary determination for each contaminant candidate, and the Agency's rationale for its determination. The technical health and occurrence support documents listed next served as the basis for the health information and the drinking water occurrence estimates summarized in this comprehensive regulatory support document.
• Technical health support documents. These documents address exposure from drinking water and other media, toxicokinetics, hazard identification, and dose-response assessment, and provide an overall characterization of the risk from drinking water for the contaminants considered for regulatory determination. These documents are listed in the reference section as “USEPA, 2006j” through “USEPA, 2006r.”
• Technical occurrence support documents (USEPA, 2006b and USEPA, 2006c). These documents include more detailed information about the sources of the data, how EPA assessed the data quality, completeness, and representativeness, and how the data were used to generate estimates of drinking water contaminant occurrence in support of these regulatory determinations. Section III.B.3 provides more information about the title and content of these technical support documents.
Sections III.A and B of this action outline the health effects and occurrence/exposure evaluation process EPA used to support these preliminary determinations.
Section 1412(b)(1)(A)(i) of SDWA requires EPA to determine whether each
There are two different approaches to the derivation of an HRL. One approach is used for chemicals that cause cancer and exhibit a linear response to dose and the other applies to noncarcinogens and carcinogens evaluated using a non-linear approach.
1. Use of Carcinogenicity Data for the Derivation of a Health Reference Level. For those contaminants considered to be likely or probable human carcinogens, EPA evaluated data on the mode of action of the chemical to determine the method of low dose extrapolation. When this analysis indicates that a linear low dose extrapolation is appropriate or when data on the mode of action are lacking, EPA uses a low dose linear extrapolation to calculate risk-specific doses. The risk-specific doses are the estimated oral exposures associated with lifetime excess risk levels that range from one cancer in ten thousand (10
2. Use of Non-carcinogenic Health Effects Data for Derivation of an HRL. For those chemicals not considered to be carcinogenic to humans, EPA generally calculates a reference dose (RfD). A RfD is an estimate of a daily oral exposure to the human population (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during a lifetime. It can be derived from either a “no-observed-adverse-effect level” (NOAEL), a “lowest-observed-adverse-effect level” (LOAEL), or a benchmark dose, with uncertainty factors applied to reflect limitations of the data used.
The Agency uses uncertainty factors (UFs) to address uncertainty resulting from incompleteness of the toxicological database. The individual UFs (usually applied as integers of 1, 3, or 10) are multiplied together and used to derive the RfD from experimental data. Individual UFs are intended to account for:
(1) The variation in sensitivity among the members of the human population (
(2) the uncertainty in extrapolating animal data to humans (
(3) the uncertainty in extrapolating from data obtained in a study with less-than-lifetime exposure to lifetime exposure (
(4) the uncertainty in extrapolating from a LOAEL rather than from a NOAEL; and/or
(5) the uncertainty associated with an incomplete database.
For boron, the dacthal (DCPA) mono and di acid degradates, s-ethyl dipropylthiocarbamate (EPTC), fonofos and terbacil, EPA derived the HRLs using the RfD approach as follows:
As discussed in section IV.B.2 and 3, the HRL for the two dacthal degradates is based on the HRL value derived for the DCPA parent following the guidance provided by EPA's Office of Pesticide Programs.
3. Sources of Data/Information for Health Effects. EPA used the best available peer-reviewed data and analyses in evaluating adverse health effects. Peer-reviewed health-risk assessments were available for all chemicals considered for regulatory determinations from the Agency's Integrated Risk Information System (IRIS) Program
In March 2005, EPA updated and finalized the Cancer Guidelines and a Supplementary Children's Guidance,
The cancer assessment for 1,3-dichloropropene was done by OPP and IRIS (USEPA, 1998b and 2000a) under the Proposed Guidelines for Carcinogen Risk Assessment (61 FR 17960 (USEPA, 1996a)). The Administrator (USEPA, 2005d) has directed that current completed assessments can be considered to be scientifically sound based on the guidance used when the assessment was completed until a new assessment is performed by one of the responsible program offices.
As noted in section II.E, EPA has prepared several technical health effects support documents for the contaminants considered for this round of regulatory determinations. These documents address the exposure from drinking water and other media, toxicokinetics, hazard identification, and dose-response assessment, and provide an overall characterization of risk from drinking water.
EPA used data from several sources to evaluate occurrence and exposure for the 11 contaminants considered in these regulatory determinations. The major or primary sources of the drinking water occurrence data used to support these determinations include the following sources:
• The first Unregulated Contaminant Monitoring Regulation (UCMR 1),
• The Unregulated Contaminant Monitoring (UCM) program, and
• The National Inorganic and Radionuclide Survey (NIRS).
In addition to these primary sources of occurrence data, the Agency also evaluated supplemental sources of occurrence information. Section III.B.1 of this action provides a brief summary of the primary sources of drinking water occurrence data and section III.B.2 provides brief summary descriptions of the supplemental sources of occurrence information and/or data. A summary of the occurrence data and the results or findings for each of the 11 contaminants considered for regulatory determination is presented in Section IV.B, the contaminant profiles section.
1. Primary Data Sources. As previously mentioned, the primary sources of the drinking water occurrence data used to support this action are the UCMR 1, the UCM program, and NIRS. The following sections provide a brief summary of the data sources and the approach used to estimate a given contaminant's occurrence. Table 2 lists the primary data sources the Agency used for each of the 11 contaminants considered for regulatory determinations.
a.
EPA designed the UCMR 1 data collection with three parts (or tiers) primarily based on the availability of analytical methods. Occurrence data for 8 of the 9 contaminants listed in the preceding paragraph are from the first tier of UCMR (also known as UCMR 1 List 1 Assessment Monitoring). Occurrence data for fonofos are from the second tier of UCMR 1 (also known as the UCMR 1 List 2 Screening Survey). EPA has not collected data as part of the third tier due to the lack of adequate analytical methods.
The UCMR 1 List 1 Assessment Monitoring was performed for a specified number of chemical contaminants for which analytical methods have been developed. EPA required all large
In total, 370,312 sample results have been collected under the UCMR 1 List 1 Assessment Monitoring program at approximately 3,083 large systems and 797 small systems. Approximately 33,600 samples were collected for each contaminant. The UCMR 1 List 1 Monitoring program included systems from all 50 States, the District of Columbia, 4 U.S. Territories, and Tribal lands in 5 EPA Regions. An additional 3,719 samples were collected for 1,3-DCP at all small systems that conducted UCMR 1 List 1 Assessment Monitoring.
In addition to the UCMR 1 List 1 Assessment Monitoring, EPA required monitoring for selected contaminants (including fonofos) for which analytical methods were developed but not widely used. Known as the UCMR 1 List 2 Screening Survey, EPA randomly selected 300 public water systems (120 large and 180 small systems) from the pool of systems required to conduct UCMR 1 List 1 Assessment Monitoring. In total, 29,765 sample results have been collected under the UCMR 1 List 2 Screening Survey from the participating large and small systems. Approximately 2,300 samples were collected for each contaminant. The UCMR 1 List 2 Screening Survey included systems from 48 States, 2 U.S. Territories, and Tribal lands in 1 EPA Region. EPA used the occurrence data from this survey to evaluate fonofos.
EPA analyzed the UCMR 1 List 1 Assessment Monitoring and List 2 Screening Survey data to generate the following initial occurrence and exposure summary statistics:
• The total number of systems and the total population served by these systems,
• The number and percentage of systems with at least 1 observed detection that has a concentration greater than
• The number of people and percentage of the population served by systems with at least one observed detection greater than
The initial UCMR 1 summary occurrence statistics for dacthal mono- and di-acid degradates, DDE, 1,3-dichloropropene, 2,4-dinitrotoluene, 2,6-dinitrotoluene, EPTC, fonofos, and terbacil are presented in section IV.B of this action.
b.
EPA implemented the UCM program in two phases or rounds. The first round of UCM monitoring generally extended from 1988 to 1992 and is referred to as UCM Round 1 monitoring. The second round of UCM monitoring generally extended from 1993 to 1997 and is referred to as UCM Round 2 monitoring.
UCM Round 1 monitored for 34 volatile organic compounds (VOCs), including 1,3-dichloropropene and 1,1,2,2-tetrachloroethane (52 FR 25720 (USEPA, 1987)). UCM Round 2 monitored for 13 synthetic organic compounds (SOCs), sulfate and the same 34 VOCs from UCM Round 1 monitoring (57 FR 31776 (USEPA, 1992a)).
The UCM Round 1 database contains contaminant occurrence data from 38 States, Washington, DC, and the U.S. Virgin Islands. The UCM Round 2 database contains data from 34 States and several Tribes. Due to incomplete State data sets, national occurrence estimates based on raw (unedited) UCM Round 1 or Round 2 data could be skewed to low-occurrence or high-occurrence settings (e.g., some States only reported detections). To address potential biases in the data,
Because UCM Round 1 and Round 2 data represent different time periods and include occurrence data from different States, EPA developed separate national cross-sections for each data set. The UCM Round 1 national cross-section consists of data from 24 States, with approximately 3.3 million total analytical data points from approximately 22,000 unique PWSs. The UCM Round 2 national cross-section consists of data from 20 States, with approximately 3.7 million analytical data points from slightly more than 27,000 unique PWSs. The UCM Round 1 and 2 national cross-sections represent significantly large samples of national occurrence data. Within each cross-section, the actual number of systems and analytical records for each contaminant varies. The support document, “The Analysis of Occurrence Data from the Unregulated Contaminant Monitoring (UCM) Program and National Inorganics and Radionuclides Survey (NIRS) in Support of Regulatory Determinations for the Second Drinking Water Contaminant Candidate List” (USEPA, 2006c), provides a description of how the national cross-sections for the Round 1 and Round 2 data sets were developed.
EPA constructed the national cross-sections in a way that provides a balance and range of States with varying pollution potential indicators, a wide range of the geologic and hydrologic conditions, and a very large sample of monitoring data points. While EPA recognizes that some limitations exist, the Agency believes that the national cross-sections do provide a reasonable estimate of the overall distribution and the central tendency of contaminant occurrence across the United States.
EPA analyzed the UCM Round 1 and 2 National Cross-Section data to generate the following initial occurrence and exposure summary statistics:
• The total number of systems and the total population served by these systems,
• The number and percentage of systems with at least 1 observed detection that has a concentration greater than
• The number of people and percentage of the population served by systems with at least 1 observed detection that has a concentration greater than
The initial UCM summary occurrence statistics for 1,3-dichloropropene and 1,1,2,2-tetrachloroethane are presented in section IV.B of this action.
c.
The NIRS database includes 36 radionuclides and inorganic compounds (IOCs), including boron. The NIRS provides contaminant occurrence data from 989 ground water CWSs covering 49 States (all except Hawaii) and does not include surface water systems. The survey focused on ground water systems, in part because IOCs tend to occur more frequently and at higher concentrations in ground water than in surface water. Each of the 989 randomly selected CWSs was sampled at a single time between 1984 and 1986.
EPA analyzed the NIRS data to generate the following occurrence and exposure summary statistics for boron:
• The total number of systems and the total population served by these systems,
• The number and the percentage of systems with at least 1 detection that has a concentration greater than
• The number of people and percentage of the population served by systems with at least 1 observed detection that has a concentration greater than
Similar to the treatment of the UCM cross-section data, the actual values for the NIRS analyses of boron are reported in section IV.B. Because the NIRS data were collected in a randomly designed sample survey, these summary statistics are representative of national occurrence in ground water CWSs.
One limitation of the NIRS is a lack of occurrence data for surface water systems. To provide perspective on the occurrence of boron in surface water systems relative to ground water systems, EPA reviewed and took into consideration a recent boron occurrence survey funded by American Water Works Association Research Foundation (AWWARF) (Frey
d.
While both UCMR 1 and UCM data could support more involved statistical modeling to characterize occurrence based on mean (rather than peak) concentrations, EPA chose not to perform this step for the regulatory determinations proposed in this action. EPA believes that presenting the actual results of the occurrence monitoring is straight-forward and the use of an analysis based on peak concentrations provides conservative estimates of occurrence and potential exposure from drinking water. Given that the preliminary determinations for the 11 contaminants discussed in this action are negative, it is not necessary to go beyond the conservative (peak concentration) approach used for this analysis.
2. Supplemental Data. The Agency evaluated several sources of supplemental occurrence information to augment the primary drinking water occurrence data, to evaluate the likelihood of contaminant occurrence, and/or to more fully characterize a contaminant's presence in the environment. Sections II.B.2.a through II.B.2.f provide brief descriptions of the main supplemental information/data sources cited in this action. Summarized occurrence findings from these supplemental sources are presented in Section IV.B, the contaminant profiles section. While the following descriptions cover the more commonly referenced supplemental sources of information/data, they do not include every study and survey cited in the contaminant discussions. A more detailed discussion of the supplemental sources of information/data that EPA evaluated for each contaminant can be found in the comprehensive regulatory determination support document (USEPA, 2006a).
a.
(1) The NAWQA Pesticide National Synthesis Project. In 2003, USGS posted the preliminary results from the first cycle of monitoring for pesticides in streams and ground water. USGS considers these results to be provisional. The results and the data can be accessed at
(2) The National Survey of MTBE and Other VOCs in Community Drinking Water Sources (part of the VOC National Synthesis Project). In 2003, USGS published the survey findings for MTBE, other ether gasoline oxygenates, and other volatile organic compounds (VOCs) in source water used by CWSs in the United States. The survey was funded by AWWARF and performed by USGS in collaboration with the Metropolitan Water District of Southern California and the Oregon Health and Science University. USGS performed the survey in two independent stages designed to provide representative sampling of all CWSs in the United States (Random Source-Water Survey) and to improve understanding of the temporal variability of MTBE and other compounds in selected water sources (Focused Source-Water Survey). Participating water utilities provided samples that were analyzed for 66 VOCs. The random survey design selected 954 CWSs to be nationally representative of surface and ground waters sources used by CWSs. The focused survey studied source waters from 134 CWSs suspected or known to contain MTBE. The reports/results and data sets from the survey can be accessed at
b.
c.
Facilities are required to report releases and other waste management activities related to TRI chemicals if they manufacture, process, or otherwise use more than established threshold quantities of these chemicals. Currently
d.
e.
f.
3. Supporting Documentation for Occurrence. As mentioned in section II.E, EPA prepared several technical occurrence documents to support this action. These technical occurrence documents include the following:
• “The Analysis of Occurrence Data from the Unregulated Contaminant Monitoring (UCM) Program and National Inorganics and Radionuclides Survey (NIRS) in Support of Regulatory Determinations for the Second Drinking Water Contaminant Candidate List” (USEPA, 2006c), which this action refers to as the “UCM and NIRS Occurrence Report.”
• “The Analysis of Occurrence Data from the First Unregulated Contaminant Monitoring Regulation (UCMR 1) in Support of Regulatory Determinations for the Second Drinking Water Contaminant Candidate List” (USEPA, 2006b), which this action refers to as the “UCMR 1 Occurrence Report.”
The “UCM and NIRS Occurrence Report” provides more detailed information about the UCM and the NIRS data, how EPA assessed the data quality, completeness, and representativeness, and how the data were used to generate estimates of contaminant occurrence. The “UCMR 1 Occurrence Report” provides more detailed information about the UCMR 1 data, how EPA assessed the data quality, completeness, representativeness, and how the data were used to generate estimates of contaminant occurrence.
The comprehensive regulatory support document (USEPA, 2006a) provides a summary of the results from the drinking water occurrence analyses discussed in the aforementioned technical support documents, as well as information on production and use, environmental releases, and/or occurrence in ambient water, potential health effects, the Agency's preliminary determination, and the rationale for the determination.
The Agency has made a preliminary determination that each of the 11 contaminants listed in Table 3 do not meet all three of the SDWA criteria (discussed in section II.C) and thus do not warrant regulation with an NPDWR. Table 3 also summarizes the primary information used to make these regulatory determinations. Section IV.B of this action provides a more detailed summary of the information and the rationale used by the Agency to reach its preliminary decisions. The Agency solicits public comment on the preliminary determinations for these 11 contaminants.
This section provides further details on the background, health, and occurrence information that the Agency used to evaluate each of the 11 candidate contaminants considered for regulatory determination. For each candidate, the Agency evaluated the available human and toxicological data, derived a health reference level, and evaluated the potential and/or likely occurrence and exposed population for the contaminant in public water systems. The Agency used the findings from these evaluations to determine whether the three SDWA statutory requirements were satisfied.
As discussed in section II.E, the Agency has also prepared a regulatory support document (USEPA, 2006a) that provides more details on the background, health, and occurrence information/analyses used to evaluate and make preliminary determinations for these 11 candidates.
a.
Natural processes such as the weathering of rocks, volcanic activity, and geothermal steam contribute to the release of boron in the environment. Releases to the environment from human activities occur through the production, use, and disposal of boron-containing compounds (e.g., industrial emissions, fertilizer and herbicide runoff, hazardous waste deposits, and municipal sewage) (HSDB, 2004a; ATSDR, 1992).
Although quantitative data are not available on the man-made releases of most borates in the United States, two boron halide compounds, boron trichloride and boron trifluoride, are listed as Toxics Release Inventory (TRI) chemicals. TRI data for boron trichloride and boron trifluoride are reported for the years 1995 to 2003 (USEPA, 2006d). The TRI data show boron trichloride releases from facilities in 6 States and indicate that air emissions account for all of the total releases of boron trichloride (on- and off-site), which generally fluctuated in the range of hundreds of pounds per year during the period of record. The TRI data show boron trifluoride releases from facilities in 14 States and indicate that air emissions also account for nearly all of the boron trifluoride releases, which ranged in the tens of thousands of pounds annually.
b.
Some human oral data are available from cases where boron was ingested as a medical treatment. When the amount ingested was less than 3.68 mg/kg, subjects were asymptomatic, while doses of 20 and 25 mg/kg resulted in nausea and vomiting. Case reports and surveys of accidental poisonings indicate that the lethal doses of boron range from 15 to 20 grams (approximately 200 to 300 mg/kg) for adults, 5 to 6 grams (approximately 70 to 85 mg/kg) for children, and 2 to 3 grams (approximately 30 to 45 mg/kg) for infants (USEPA, 2004b).
The primary adverse effects seen in animals after chronic exposure to low doses of boron generally involve the testes and developing fetus. Chronic effects of dietary boron exposure in two-year studies included testicular atrophy and spermatogenic arrest in dogs, decreased food consumption,
In developmental studies with rats, mice, and rabbits, oral exposure to boric acid resulted in decreased pregnancy rate, increased prenatal mortality, decreased fetal weights, and increased malformations in fetuses and pups. However, these reproductive effects were associated with maternal toxicity including changes in maternal organ weights, body weights, weight gain, and increased renal tubular dilation and/or regeneration (Price
The EPA RfD for boron is 0.2 mg/kg/day (USEPA, 2004c) based on developmental effects in rats from two studies (Price
EPA also evaluated whether health information is available regarding the potential effects on children and other sensitive populations. Studies in rats, mice, and rabbits identify the developing fetus as potentially sensitive to boron. Price
c.
Because NIRS did not contain data for surface water systems, the Agency evaluated the results of a survey funded by the American Water Works Association Research Foundation (Frey
d.
The Agency encourages those States with public water systems that have boron at concentrations above the HRL to evaluate site-specific protective measures and to consider whether State-level guidance (or some other type of action) is appropriate. The Agency also plans to update the Health Advisory for boron to provide more recent health information. The updated Health Advisory will provide information to any States with public water systems that may have boron above the HRL.
a.
DCPA is not especially mobile or persistent in the environment. Biodegradation and volatilization are the primary dissipation routes. Degradation of DCPA forms two breakdown products, the mono-acid degradate (or monomethyl tetrachloroterephthalate or MTP) and the di-acid degradate (tetrachloroterephthalic acid or TPA). The di-acid, which is the major degradate, is unusually mobile and persistent in the field, with a potential to leach into water (USEPA, 1998c).
Several studies and reports provide estimates of the amount of DCPA used during the 1990s in the United States. The Agency estimated that 1.6 million pounds of DCPA active ingredient a.i. were used annually in the early 1990s (USEPA, 1998c). USGS estimated that approximately 998 thousand pounds of DCPA a.i. were used annually circa 1992 (Thelin and Gianessi, 2000). The National Center for Food and Agricultural Policy (NCFAP, 2004) estimates that approximately 1.7 million
b.
The present toxicity database for MTP and TPA is not sufficient to derive RfDs for these two chemicals. However, since the available data indicate that neither MTP nor TPA are more toxic than their parent compound, DCPA, the Agency suggests that the RfD for the DCPA parent would be protective against exposure from these two DCPA metabolites (USEPA, 1998c). Both compounds are formed in the body from the DCPA parent and therefore, the toxicity of these degradates is reflected in the toxicity of the parent. The RfD for DCPA is 0.01 mg/kg/day based on a chronic rat study (ISK Biotech Corporation, 1993) with a NOAEL of 1.0 mg/kg/day and an uncertainty factor of 100 for rat to human extrapolation and intra-species variability.
No carcinogenicity studies have been performed using either TPA or MTP. Based on the cancer data for the parent and lack of mutagenicity for TPA and DCPA, the Agency (USEPA, 2004d) concludes that TPA is unlikely to pose a cancer risk. Klopman
Using the DCPA RfD of 0.01 mg/kg/day (USEPA, 1994) and a 20 percent screening relative source contribution, the Agency calculated an HRL of 0.07 mg/L or 70 μg/L for DCPA and used this HRL for TPA and MTP.
EPA also evaluated whether health information is available regarding the potential effects on children and other sensitive populations. There are no data that identify a particular sensitive population for DCPA exposure. Results of a single developmental study indicate that exposure to pregnant dams with doses less than or equal to 2,500 mg/kg/day of TPA via gavage did not have an adverse effect on the fetus. EPA did not identify any data that suggest gender-related differences in toxicity or sensitivity in the elderly.
c.
EPA also evaluated several sources of supplemental occurrence information for the DCPA parent, the mono-acid degradate and/or the di-acid degradate. These supplemental sources include:
• The National Pesticide Survey (NPS),
• The provisional pesticide results from the 1992-2001 USGS NAWQA survey of ambient surface and ground waters across the U.S., and
• Studies performed by the DCPA or dacthal registrant.
As part of the National Pesticide Survey, EPA collected samples from approximately 1,300 community water systems and rural drinking water wells between 1988 and 1990. The NPS included monitoring for the DCPA parent and the di-acid degradate. The DCPA parent was not detected in any wells (using a detection limit of 0.06 μg/L). While the di-acid degradate was detected in 49 of 1,347 wells (using a detection limit of 0.1 μg/L), the maximum reported concentration of 7.2 μg/L did not exceed the HRL of 70 μg/L (USEPA, 1990a).
The USGS NAWQA program included the DCPA parent and the mono-acid degradate as analytes in its 1992-2001 monitoring survey of ambient surface and ground waters across the United States. EPA evaluated the results of the provisional data, which are available on the Web (Martin
Beginning in 1992, the registrant for DCPA performed two small-scale ground water occurrence studies in New York and California over a period of 17 and 22 months, respectively. The registrant monitored for the DCPA parent and both of its degradates. The average reported values, which are the sum of the parent and its degradates, were 50.36 μg/L in New York and 12.75 μg/L in California. Neither average value exceeded the HRL of 70 μg/L (USEPA, 1998c).
d.
The Agency encourages those States with public water systems that have detects for these degradates to evaluate site-specific protective measures and to consider whether State-level guidance (or some other type of action) is appropriate. The Agency also plans to update the Health Advisory for the DCPA parent to include the mono and di acid degradates, as well as any recent health information related to these compounds. The updated Health Advisory will provide information to any States with public water systems that may have DCPA degradates at levels above the HRL.
a.
b.
Based on animal studies DDE is likely to be carcinogenic to humans. This classification is based on increases in the incidence of liver tumors, including carcinomas, in two strains of mice and in hamsters after dietary exposure to DDE. Some epidemiological studies suggest a possible association of the levels of DDE in serum with breast cancer. However, other studies with similar methodologies do not show any association. DDE was mutagenic in mouse lymphoma L5178Y and Chinese hamster V79 cells but negative in the Ames assay. In the 1988 IRIS, EPA calculated an oral slope factor of 0.34 (mg/kg/day)
There are some indications that DDE has an adverse impact on the immune system (Banerjee
EPA evaluated whether health information is available regarding the potential effects on children and other sensitive populations. Children and adolescents may be sensitive populations for exposure to DDE due to its endocrine disruption properties. Some data suggest that DDE can delay puberty in males (ATSDR, 2002).
c.
The USGS NAWQA program included DDE as an analyte in its 1992-2001 monitoring survey of ambient surface and ground waters across the United States. EPA evaluated the results of the provisional data, which are available on the Web (Martin
d.
EPA recognizes that DDE is listed as a probable human carcinogen. For this reason, the Agency encourages those States with public water systems that might have DDE above the HRL to evaluate site-specific protective measures and to consider whether State-level guidance (or some other type of action) is appropriate.
a.
• In areas with shallow ground water and vulnerable soils in certain northern tier States (ND, SD, WI, MN, NY, ME, NH, VT, MA, UT, and MT);
• In fields within 100 feet of a drinking water well; and
• In areas overlying karst
Estimates of national annual use during the 1990s vary widely, from approximately 23 to 40 million pounds of active ingredient a.i. Based on information from a 1991 data call-in and other sources, EPA estimates that approximately 23 million pounds of 1,3-DCP a.i. were used annually from 1990 to 1995 (USEPA, 1998b). NCFAP (2004) estimates that approximately 40 million pounds a.i. were used in 1992 and approximately 35 million pounds a.i. were used in 1997.
1,3-Dichloropropene is listed as a TRI chemical and releases are reported from facilities in 17 States over a time period covering 1988 to 2003 (although not all States had facilities reporting releases every year) (USEPA, 2006e). Air emissions appear to account for most of the on-site (and total) releases and generally declined between 1988 and 2003. A sharp decrease in air emissions is evident between 1995 and 1996. Surface water discharges are minor compared to air emissions and no obvious trend is evident between 1988 and 2003. Reported underground injection, releases to land, and off-site releases are generally insignificant.
b.
An RfD of 0.03 mg/kg/day for 1,3-DCP (USEPA, 2000a) has been established using a benchmark dose (BMD) analysis based on a two-year chronic bioassay (Stott
Under the proposed cancer risk assessment guidelines, the weight of evidence for evaluation of 1,3-DCP's ability to cause cancer suggest that it is likely to be carcinogenic to humans (USEPA, 2000a). This characterization is supported by tumor observations in chronic animal bioassays for both inhalation and oral routes of exposure.
The oral cancer slope factors calculated from chronic dietary, gavage and inhalation data ranged from 5 × 10
EPA also evaluated whether health information is available regarding the potential effects on children and other sensitive populations. No human or animal studies are available that have examined the effect of 1,3-DCP exposure on juvenile subjects. Therefore, its effects on children are unknown. Developmental studies in rats and rabbits show no evidence of developmental effects and therefore it is unlikely that 1,3-DCP causes developmental toxicity.
c.
The UCM Round 1 Cross Section data indicate that approximately 0.16 percent (or 15) of the 9,164 PWSs sampled had detections of 1,3-DCP at levels greater than 0.2 μg/L (
The UCM Round 2 Cross Section data indicate that approximately 0.30 percent (or 50) of the 16,787 PWSs sampled had detections of 1,3-DCP at levels greater than 0.2 μg/L (
Because the sample preservative used may have resulted in potential underestimates of occurrence for the UCM Rounds 1 and 2 data, EPA subsequently analyzed for 1,3-DCP using the samples provided by 796 of the small systems included in the recent UCMR 1 survey. None of the 3,719 samples from these 796 small systems (serving a population of 2.8 million) had detects of 1,3-DCP at levels greater than 0.5 μg/L (the minimum reporting limit used for the analysis of 1,3-DCP and a level that is slightly higher than the HRL).
EPA also evaluated several sources of supplemental information, which included:
• The National Pesticide Survey,
• The Pesticides in Ground Water Database,
• A well water survey submitted by the registrant of Telone (1,3-DCP),
• The USGS VOC National Synthesis Random Source Water Survey, and
• The USGS VOC National Synthesis Focused Source Water Survey.
As part of the National Pesticide Survey, EPA collected samples from approximately 1,300 community water systems and rural drinking water wells between 1988 and 1990. The NPS included
The Pesticides in Ground Water Database (USEPA, 1992b) indicates that 1,3-DCP was found in 6 of 21,270 ground water wells sampled in 7 States. The 6 wells with positive detections for 1,3-DCP included 3 wells in California (at concentrations ranging from 0.890 to 31.0 μg/L), 2 wells in Florida (at concentrations of 0.279 to 7.83 μg/L), and 1 well in Montana (at concentrations of 18 to 140 μg/L). While most or all of these 6 wells had
In 1998, the registrant for Telone (1,3-DCP) submitted a private well water study to the Agency. The well water survey covered 5 regions where Telone was used intensively and evaluated 518 wells (~5,800 samples) for the presence of 1,3-DCP. Of the 518 wells, 65 had detectable levels of 1,3-DCP and/or its metabolites at levels greater than 0.015 μg/L (the detection limit for 1,3-DCP was 0.015 μg/L and the metabolites were 0.023 μg/L). None of the wells exceeded 0.2 μg/L (a level half the EPA-derived HRL for 1,3-DCP) (USEPA, 2004e and 2004f).
For the Random Source Water Survey, the USGS collected samples from 954 source waters that supply community water systems between 1999 and 2000. For the Focused Source Water Survey, the USGS collected 451 samples from 134 source waters that supply community water systems between 1999 and 2001. The USGS included 1,3-DCP as an analyte in both surveys. The USGS did not detect 1,3-DCP in any of the source water samples from the Random Source Water Survey using a reporting limit of 0.2 μg/L (a level that is one-half the HRL for 1,3-DCP). In addition, the USGS did not detect 1,3-DCP in any of the source water samples in the Focused Source Water Survey using a detection limit of 0.024 μg/L for cis-1,3-dichloropropene and 0.026 μg/L for trans-1,3-dichloropropene (levels that are about 16 times lower than the HRL for 1,3-DCP) (Ivahnenko
d.
EPA recognizes that 1,3-dichloropropene is listed as a probable human carcinogen. For this reason, the Agency encourages those States with public water systems that may have 1,3-dichloropropene above the HRL to evaluate site-specific protective measures and to consider whether State-level (or some other type of action) is appropriate. The Agency also plans to update the Health Advisory document for 1,3-DCP to provide more recent health information. The updated Health Advisory will provide information to any States with public water systems that may have 1,3-DCP above the HRL.
a.
No recent quantitative estimates of DNT production or use are available. The Hazardous Substances Data Bank (HSDB, 2004b) cites a 1980 EPA Ambient Water Quality Criteria Document that places combined 2,4- and 2,6-DNT production at 272,610,000 pounds in 1975.
Both 2,4-DNT and 2,6-DNT are listed as TRI chemicals. TRI data for 2,4-DNT are reported from facilities in 21 States over a time period covering 1988 to 2003. Total releases nationally in 2003 were 14,899 lbs. Releases of all kinds (off-site releases and on-site air, surface, underground injection, and land releases) declined in the early 1990s, and then peaked again around 1999-2001. On-site air emissions and surface water releases of 2,4-DNT were generally the most consistent (least fluctuating) types of releases, with surface water releases generally declining over the period on record (USEPA, 2006f).
TRI data for 2,6-DNT are reported from facilities in 10 States over a time period covering 1988 to 2003 (with no more than 9 States having reporting facilities in any one year). Total reported releases for 2003 were 10,937 lbs. Trends for 2,6-DNT are similar to those for 2,4-DNT. The TRI data for 2,6-DNT show a trend of declining releases in the late 1980s and early 1990s, and a subsequent peak around 1999-2001. On-site air emissions and surface water discharges are the most consistent types of release for 2,6-DNT and surface water discharges exhibit a declining trend (USEPA, 2006f).
In addition, TRI lists mixed DNT isomer releases as a separate category over the same time period (1990-2003). TRI releases of mixed isomers were reported from facilities in 9 States, with no more than 7 States having reporting facilities in any one year. Total releases in 2003 were 13,790 lbs. Underground injections made up the bulk of on-site releases during the 1990s, but diminished thereafter. Air emissions remained relatively constant. Surface water discharges and releases to land were generally insignificant but peaked in 2003. Off-site releases varied widely. Total releases peaked in 1993 and 1997, and generally diminished in recent years (USEPA, 2006f).
b.
Subchronic studies in mice, rats, and dogs that administered 2,4- and 2,6-DNT in the diet produced similar effects in all species. All species exposed to 2,4-DNT exhibited methemoglobinemia, anemia, bile duct hyperplasia sometimes accompanied by hepatic degeneration, and depressed spermatogenesis. Neurotoxicity and renal degeneration occurred in dogs at a dose level of 20 mg/kg/day of 2,6-DNT (Lee
2,4-DNT has been shown to cause reproductive effects in rats, mice, and dogs (Ellis
Some studies evaluated the effects of DNT in the form of a technical mixture (tg-DNT). In a study by Price
In chronic exposures, oral dietary administration of 2,4-DNT to dogs primarily affected the nervous system, erythrocytes, and biliary tract (Ellis
EPA established an RfD of 0.001 mg/kg/day for 2,6-DNT (USEPA, 1992c). This RfD was also based on neurotoxicity, Heinz body formation, biliary tract hyperplasia, liver and kidney histopathology, and death in beagle dogs that were fed gelatin capsules containing 2,6-DNT daily for up to 13 weeks (Lee
DNT is likely to be carcinogenic to humans (classified as a B2 carcinogen; USEPA, 1990c). This is based on significant increases in hepatocellular carcinoma and mammary gland tumors in female rats fed DNT (98 percent 2,4-DNT with 2 percent 2,6-DNT) in the diet in a two-year study (Ellis
c.
EPA also evaluated the results of a USGS review of 3 highway and urban runoff studies (Lopes and Dionne, 1998). These studies showed no detects for either 2,4- or 2,6-DNT using a reporting limit of 5 μg/L (a value within the 10
d.
EPA recognizes that 2,4- and 2,6-DNT are listed as probable human carcinogens. For this reason, the Agency encourages those States with public water systems that may have either 2,4- or 2,6-DNT above the HRL to evaluate site-specific protective measures and to consider whether State-level guidance (or some other type of action) is appropriate. The Agency's original Health Advisories for 2,4- and 2,6-DNT were developed for military installations. Because the Agency recognizes that 2,4- and 2,6-DNT may still be found at some military sites, the Agency has updated the Health Advisories to reflect recent health effects publications. The Health Advisories are available for review in the docket. The updated Health Advisories will provide information to any States with public water systems that may have either 2,4- or 2,6-DNT above the HRL.
a.
Estimates of EPTC usage in the United States suggest a decline from approximately 17 to 21 million pounds active ingredient in 1987 to approximately 7 to 9 million pounds active ingredient in 1999. TRI data from 1995 to 2003 indicate that most on-site industrial releases of EPTC tend to be releases to air and underground injections. Surface water discharges are
Environmental fate data indicate that EPTC would not be persistent under most environmental conditions. Volatilization into the atmosphere and degradation by soil organisms appear to be the primary dissipation routes. EPTC has a low affinity for binding to the soil so the potential to leach to ground water does exist. If EPTC reaches ground water, volatilization is less likely to occur (USEPA, 1999c).
b.
In subchronic and chronic studies performed in both rats and dogs, there was a dose-related increase in the incidence and severity of cardiomyopathy, a disorder of the heart muscle (Mackenzie, 1986; USEPA, 1999c). An increase in the incidence and severity of degenerative effects (neuronal and/or necrotic degeneration) in both the central and peripheral nervous system was observed in rats and dogs following exposure to EPTC (USEPA, 1999c).
EPA derived an RfD of 0.025 mg/kg/day for EPTC (USEPA, 1990d; USEPA, 1999c). This value was calculated using a NOAEL of 2.5 mg/kg/day from a study by Mackenzie (1986). An uncertainty factor of 100 was applied for inter- and intraspecies differences. The critical effect associated with the RfD is cardiomyopathy (disease of the heart muscle). In the reregistration of EPTC, the application of a ten-fold Food Quality Protection Act (FQPA) factor was recommended in order to be protective against residential exposures of infants and children. The Agency derived the HRL for EPTC using the RfD of 0.025 mg/kg/day and a 20 percent relative source contribution. The HRL is calculated to be 0.175 mg/L or 175 μg/L.
The Agency used long-term studies in mice and rats and short-term studies of mutagenicity to evaluate the potential for carcinogenicity (USEPA, 1990d). Based on these data and using EPA's 1999 Guidelines for Carcinogen Risk Assessment, EPTC is not likely to be carcinogenic to humans (USEPA, 1999a).
EPA also evaluated whether health information is available regarding the potential effects on children and other sensitive populations. Data do not suggest increased pre- or post-natal sensitivity of children and infants to EPTC exposure. In animal studies, adverse developmental effects (i.e., decreased fetal body weight and decreased litter size) were only seen at doses that were toxic to the mother (USEPA, 1999c). Results from both developmental and reproductive studies indicate that there are only minimal adverse effects. The behavior patterns of children that lead to heightened opportunities for exposure in the indoor environment and the need for a developmental neurotoxicity study lead OPP to recommend the application of a ten-fold FQPA factor for EPTC. However, EPA did not apply this factor in the screening analysis because it does not apply to programs other than the pesticide registrations.
c.
EPA also evaluated several sources of supplemental information, which included:
• The National Pesticide Survey,
• The Pesticides in Ground Water Database, and
• The provisional pesticide results from the 1992-2001 USGS NAWQA survey of ambient surface and ground waters across the U.S.
As part of the National Pesticide Survey, EPA collected samples from approximately 1,300 community water systems and rural drinking water wells between 1988 and 1990. The NPS included EPTC as an analyte in the monitoring survey. EPTC was not detected using a minimum reporting limit of 0.15 μg/L (USEPA, 1990a).
The Pesticides in Ground Water Database (USEPA, 1992b) indicates that EPTC was found in 2 of 1,752 ground water wells that were sampled in 10 States. Both contaminated wells were in Minnesota. The detected concentrations ranged from 0.01 to 0.33 μg/L. All of these positive detections are less than the HRL of 175 μg/L, as well as 87.5 μg/L (
The USGS NAWQA program included EPTC as an analyte in its 1992-2001 monitoring survey of ambient surface and ground waters across the United States. EPA evaluated the results of the provisional data, which are available on the Web (Martin
d.
a.
Fonofos was scheduled for a reregistration decision in 1999. However, before the review was completed, the registrant requested voluntary cancellation. The cancellation was announced in the
NCFAP data indicate that fonofos use declined significantly during the 1990s (NCFAP, 2004). According to NCFAP,
Fonofos is moderately persistent in soil and its persistence depends on soil type, organic matter, rainfall, and sunlight. Since fonofos adsorbs moderately well to soil, it is not readily leached or transported to ground water but it can be transported to surface waters in runoff. Fonofos is rapidly degraded by soil microorganisms (Extoxnet, 1993). Fonofos tends to volatilize from wet soil and water surfaces, but the process is slowed by adsorption to organic material in soil, suspended solids, and sediment (HSDB, 2004d).
b.
In animals, clinical signs of exposure included tremors, salivation, diarrhea, and labored breathing (USEPA, 1996c). Chronic exposure studies also indicated that oral administration of fonofos inhibits cholinesterase (Banerjee
Fonofos is classified as an unlikely human carcinogen (Group E) because there is no evidence of carcinogenic potential in the available long-term feeding studies in rats and mice (Banerjee
EPA evaluated whether health information is available regarding the potential effects on children and other sensitive populations. In the available developmental studies with rabbits (Sauerhoff, 1987) and mice (Minor
The Agency believes that the current RfD is adequately protective of children. The current fonofos RfD of 0.002 mg/kg/day is 1000-fold lower than the NOAEL observed in the Woodard
Using the RfD of 0.002 mg/kg/day for fonofos and a 20 percent screening relative source contribution, the Agency derived an HRL of 0.014 mg/L and rounded to 0.01 mg/L (or 10 μg/L).
c.
The USGS NAWQA program included fonofos as an analyte in its 1992-2001 monitoring survey of ambient surface and ground waters across the United States. EPA evaluated the results of the provisional data, which are available on the Web (Martin
d.
a.
In 1998, EPA estimated that agricultural usage of terbacil consumed approximately 221,000 to 447,000 pounds of active ingredient annually and non-agricultural usage consumed approximately 9,000 to 14,000 pounds. These estimates are based on data collected mostly between 1990 and 1995, and in some cases as early as 1987 (USEPA, 1998e). According to NCFAP (2004), approximately 298,000 pounds of terbacil a.i. were applied annually in agriculture around 1992 and approximately 342,000 pounds a.i. were applied around 1997.
Terbacil is listed as a TRI chemical and data are reported from one or more facilities in a single state, Texas, for the time period covering 1995 to 1997. During this three-year period, all reported releases were on-site releases to surface water that varied between 3,000 to 10,000 pounds annually (USEPA, 2006h).
Terbacil is considered a persistent and potentially mobile herbicide in terrestrial environments. Because of its low affinity to soils, it can potentially leach into ground and/or surface waters (USEPA, 1998e; Extoxnet, 1994).
b.
A primary target organ in rats following exposure to terbacil is the liver. Chronic effects of dietary terbacil exposure in two-year studies included increases in thyroid-to-body weight ratios, slight increases in liver weights and elevated alkaline phosphatase levels in beagle dogs, significant decreases in body weight in rats, increases in serum cholesterol levels and increases in liver to body weight ratios in rats (Wazeter
Terbacil is not considered to be a developmental or reproductive toxicant. In developmental studies, maternal effects were generally seen prior to or at the same levels as developmental effects. Haskell Laboratories (1980) reported maternal effects (
Terbacil is not mutagenic. Terbacil was tested and found negative in a chromosomal aberration study in rat bone marrow cells, found negative in a gene mutation assay (with and without S9 activation), and found negative for DNA synthesis when tested up to cytotoxic levels in rats (Cortina, 1984; Haskell Laboratories,1984). Terbacil shows no evidence of carcinogenicity and is unlikely to be carcinogenic to humans (Group E) (USEPA, 1998e).
The RfD of 0.013 mg/kg/day for terbacil (USEPA, 1998e) is calculated from a two-year chronic study in beagle dogs. The LOAEL of 6.25 mg/kg/day was based on increased thyroid-to-body weight ratios, slight increases in liver weights, and elevated alkaline phosphatase levels with a NOAEL of 1.25 mg/kg/day. In deriving the RfD, the Agency applied an uncertainty factor of 100 to account for interspecies and intraspecies differences. Using the RfD of 0.013 mg/kg/day and applying a 20 percent screening relative source contribution, the Agency derived an HRL of 0.090 mg/L (or 90 g/L) for terbacil.
EPA also evaluated whether health information is available regarding the potential effects on children and other sensitive populations. In the case of terbacil, the Agency determined that there was no need to apply an FQPA factor to the RfD in order to protect children (USEPA, 1998e). Other potentially sensitive subpopulations have not been identified.
c.
EPA also evaluated several sources of supplemental information, which included:
• The National Pesticide Survey,
• The Pesticides in Ground Water Database, and
• The provisional pesticide results from the 1992-2001 USGS NAWQA survey of ambient surface and ground waters across the U.S.
As part of the National Pesticide Survey, EPA collected samples from approximately 1,300 community water systems and rural drinking water wells between 1988 and 1990. The NPS included terbacil as an analyte in the monitoring survey. Terbacil was not detected using a minimum reporting limit of 1.7 μg/L (USEPA, 1990a).
The Pesticides in Ground Water Database (USEPA, 1992b) indicates that terbacil was found in 6 of the 288 ground water wells tested for this contaminant in 6 States. Terbacil was found in 1 ground water well in Oregon (at a concentration of 8.9 μg/L) and 5 ground water wells in West Virginia (with concentrations ranging from 0.3 to 1.2 μg/L). All of the positive detections are less than the HRL of 90 μg/L, as well as 45 μg/L (
The USGS NAWQA program included terbacil as an analyte in its 1992-2001 monitoring survey of ambient surface and ground waters across the United States. EPA evaluated the results of the provisional data, which are available on the Web (Martin
d.
a.
Production of 1,1,2,2-tetrachloroethane in the U.S. was approximately 440 million pounds in 1967 (Konietzko, 1984). Production declined to an estimated 34 million pounds by 1974 (ATSDR, 1996). Although U.S. commercial production ceased in the 1980s, 1,1,2,2-tetrachloroethane is still generated as a byproduct and/or intermediate in the production of other chemicals. TRI data indicate that environmental releases have generally declined from a high of about 175,000 pounds in 1988 to a low of 3,500 pounds in 2003. Most releases took the form of air emissions, though surface water discharges were also documented nearly every year (USEPA, 2006i).
Volatilization from water or soil surfaces to the atmosphere appears to be the primary dissipation route for 1,1,2,2-tetrachloroethane. In subsurface soils and ground water, 1,1,2,2-tetrachloroethane is subject to biodegradation by soil organisms and/or chemical hydrolysis by water (ATSDR, 1996).
b.
There have been a variety of animal studies in rats and mice using both the inhalation and oral exposure routes. Recent studies by the National Toxicology Program (NTP, 2004) provide a detailed evaluation of the short-term and subchronic oral toxicity of 1,1,2,2-tetrachloroethane and confirm many of the observations from earlier studies. In rats and mice exposed orally, the liver appears to be the primary target organ. The RfD (10 μg/kg/day) for 1,1,2,2-tetrachloroethane was derived from the BMDL for a 1 standard deviation change in relative liver weight, a biomarker for liver toxicity. A 1,000-fold uncertainty factor was applied in the RfD determination.
A National Cancer Institute (1978) bioassay of 1,1,2,2-tetrachloroethane found clear evidence of carcinogenicity in male and female B6C3F1 mice based on a dose-related statistically significant increase in liver tumors. There was equivocal evidence for carcinogenicity in Osborn Mendel rats because of the occurrence of a small number of rare-for-the species neoplastic and preneoplastic lesions in the livers of the high dose animals. The Agency used the slope factor of 8.5 x 10
Developmental range-finding studies conducted for NTP (1991a and b) found that 1,1,2,2-tetrachloroethane was toxic to the dams and pups of Sprague Dawley rats and CD-1 Swiss mice. Rats were more sensitive than mice. The NOAEL in the rats for both maternal toxicity and associated fetal toxicity was 34 mg/kg/day with a LOAEL of 98 mg/kg/day. In mice, the NOAEL was 987 mg/kg/day and the LOAEL was 2,120 mg/kg/day.
EPA also evaluated whether health information is available regarding the potential effects on children and other sensitive populations. Individuals with preexisting liver and kidney damage would likely be sensitive to 1,1,2,2-tetrachloroethane exposure. Low intake of antioxidant nutrients (e.g., Vitamin E, Vitamin C, and selenium) could be a predisposing factor for liver damage. In addition, individuals with a genetically low capacity to metabolize dichloroacetic acid (the primary metabolite of 1,1,2,2-tetrachloroethane) may be at greater risk than the general population as a result of 1,1,2,2-tetrachloroethane exposure.
c.
Analysis of UCM Round 1 Cross Section data indicates that approximately 0.22 percent (or 44) of the 20,407 PWSs sampled had detections of 1,1,2,2-tetrachloroethane at levels greater than 0.20 μg/L (
Analysis of the UCM Round 2 Cross Section data indicate that approximately 0.07 percent (or 18) of the 24,800 PWSs sampled had detections of 1,1,2,2-tetrachloroethane at levels greater than 0.2 μg/L (
EPA also evaluated several sources of supplemental information, which included the USGS VOC National Synthesis Random Source Water Survey and the Focused Source Water Survey. For the Random Source Water Survey, the USGS collected samples from 954 source waters that supply community water systems between 1999 and 2000. For the Focused Source Water Survey, the USGS collected 451 samples from 134 source waters that supply community water systems between 1999 and 2001. The USGS included 1,1,2,2-tetrachloroethane as an analyte in both surveys and did not detect it in any of the source water samples using a reporting limit of 0.2 μg/L (a level that is less than the 1,1,2,2-tetrachloroethane HRL). In addition, USGS did not detect 1,1,2,2-tetrachloroethane when using a detection level of 0.026 μg/L (a level that is over 10 times lower than the 1,1,2,2-tetrachloroethane HRL) in the focused survey (Ivahnenko
d.
EPA recognizes that 1,1,2,2-tetrachloroethane is listed as a likely human carcinogen. For this reason, the Agency encourages those States with public water systems that may have 1,1,2,2-tetrachloroethane above the HRL to evaluate site-specific protective measures and to consider whether State-level guidance (or some other type of action) is appropriate. The Agency also plans to update the Health Advisory document for 1,1,2,2-tetrachloroethane to provide more recent health information. The updated Health Advisory will provide information to any States with public water systems that may have 1,1,2,2-tetrachloroethane at levels above the HRL.
At this time, the Agency is not making a preliminary determination as to whether a national primary drinking water regulation is needed for perchlorate. However, the Agency has placed a high priority on making a regulatory determination for perchlorate and will publish a preliminary determination as soon as possible. EPA is not able to make a preliminary determination at this time because, in order to evaluate perchlorate against the three SDWA statutory criteria, the Agency believes additional information may be needed to more fully characterize perchlorate exposure and determine whether regulating perchlorate in drinking water presents a meaningful opportunity for health risk reduction. This is particularly true if the Agency uses food exposure data to first calculate a relative source contribution (RSC) and corresponding health reference level (HRL) below the drinking water equivalent level (DWEL)
The following sections explain why EPA is not making a preliminary regulatory determination for perchlorate at this time, and discusses the information the Agency has collected to date (that may be relevant to making a preliminary regulatory determination), the additional information the Agency is soliciting in this action, and options for additional analyses that the Agency may conduct to support a regulatory determination. Sections V.A through V.D provide a summary of the available and relevant information/data that the Agency has collected and reviewed regarding the sources of perchlorate in the environment, its potential health effects, and its occurrence in drinking water, food, human urine, breast milk, and amniotic fluid. Section V.E explains the Agency's basis for not making a preliminary regulatory determination for perchlorate at this time and Section V.F. presents the options the Agency is considering to better characterize perchlorate exposure and the alternate approaches that EPA is considering for making a preliminary regulatory determination. This action provides an opportunity for the public to submit other relevant data that may further characterize exposure to perchlorate through the consumption of foods and/or through other pathways and to comment on these alternate approaches. The Agency in particular seeks comment on the use of urine biomonitoring data in estimating perchlorate exposure. The Agency will consider any relevant information/data provided in response to this action as the Agency determines whether to regulate perchlorate with a national primary drinking water regulation and how best to proceed to address perchlorate.
Perchlorate (ClO
While perchlorate has a wide variety of industrial uses, it is primarily used in the form of ammonium perchlorate as an oxidizer in solid fuels used to power rockets, missiles, and fireworks. Approximately 90 percent of perchlorate is manufactured for this application (Wang
Perchlorate can also occur naturally in the environment. Chile possesses caliche ores rich in sodium nitrate (NaNO
Perchlorate has also been found in other geologic materials. Orris
Texas Tech University Water Resources Center conducted a large-scale sampling program to determine the source and distribution of perchlorate in northwest Texas groundwater (Jackson
After a limited investigation, the Massachusetts Department of Environmental Quality (MA DEP, 2005) found that perchlorate may be present in sodium hypochlorite solutions used in water and wastewater treatment plants, and that the level of occurrence depends upon storage conditions and the initial purity of the stock solution (MA DEP, 2005). According to MA DEP (2005), the Town of Tewksbury conducted a small study to evaluate the impact of storage conditions (temperature and light) on a new shipment of sodium hypochlorite stock solution. Tewksbury found that the perchlorate concentration in the new stock solution increased from 0.2 g/L to levels ranging from 995 to 6,750 g/L depending on the storage conditions. Accounting for the large dilution factor (
It is not clear at this time what proportion of perchlorate found in public water supplies or entering the food chain comes from these various anthropogenic and natural sources. The significance of different sources probably varies regionally. A study by Dasgupta
Perchlorate can interfere with the normal functioning of the thyroid gland by competitively inhibiting the transport of iodide into the thyroid. Iodide is an important component of two thyroid hormones, T4 and T3, and the transfer of iodide from the blood into the thyroid is an essential step in the synthesis of these two hormones. Iodide transport into the thyroid is mediated by a protein molecule known as the sodium (Na+)—iodide (I-) symporter (NIS). NIS molecules bind iodide with very high affinity, but they also bind other ions that have a similar shape and electric charge, such as perchlorate. The binding of these other ions to the NIS inhibits iodide transport into the thyroid, which can result in intrathyroidal iodide deficiency and consequently decreased synthesis of T4 and T3. There is compensation for iodide deficiency, however, such that the body maintains the serum concentrations of thyroid hormones within narrow limits through feedback control mechanisms. This feedback includes increased secretion of thyroid stimulating hormone (TSH) from the pituitary gland, which has among its effects the increased production of T4 and T3 (USEPA, 2005e). Sustained changes in thyroid hormone and TSH secretion can result in thyroid hypertrophy and hyperplasia (abnormal growth or enlargement of the thyroid) (USEPA, 2005e).
In January 2005, the National Research Council (NRC) of the National Academies of Science (NAS) published “Health Implications of Perchlorate Ingestion,” a review of the current state of the science regarding potential adverse health effects of perchlorate exposure and mode-of-action for perchlorate toxicity (NRC, 2005). Based on recommendations of the NRC, EPA chose data from the Greer
The NRC recommended that EPA apply an intraspecies uncertainty factor of 10 to the NOEL to account for differences in sensitivity between the healthy adults in the Greer
Blount
1. Sources of Perchlorate. Section V.A. summarizes the potential sources of perchlorate in the environment.
2. Studies on Perchlorate Occurrence in Public Drinking Water Systems and/or Drinking Water Sources. EPA included perchlorate as an analyte in the 1999 Unregulated Contaminant Monitoring Regulation (UCMR 1) and collected drinking water occurrence data for perchlorate from 3,858 public water systems (PWSs) between 2001 and 2005. EPA analyzed the available UCMR 1 data on perchlorate at concentrations greater than or equal to 4 μg/L, the minimum reporting limit (MRL) for EPA Method 314.0.
These 160 PWSs (with at least 1 analytical detection for perchlorate at levels greater than or equal to 4 μg/L) serve approximately 7.5 percent (or 16.8 million) of the 225 million people served by the 3,858 PWSs that sampled and reported results under UCMR 1. The 16.8 million population-served value represents the total number of people served by the 160 PWSs with at least one detect. Not all people served by these systems necessarily have perchlorate in their drinking water. Some of these 160 public water systems have multiple entry points to the distribution system and not all of the entry points sampled had positive detections for perchlorate in the UCMR 1 survey. An alternative approach to the system-level assessment of populations served is to use an assessment at the entry (sampling) point level.
The California Department of Health Services (CA DHS) began monitoring for perchlorate in 1997. In 1999, CA DHS began requiring monitoring for perchlorate for drinking water sources that were identified as vulnerable to perchlorate contamination under California's own State monitoring program (i.e., Unregulated Chemicals for which Monitoring is Required). About 60 percent (or 7,100) of all drinking water sources in California (about 12,000) were monitored for perchlorate under the State monitoring program. Between June 2001 and June 2006, CA DHS (2006) reports that 284 (about 4%) of the approximately 7,100 water sources that monitored had at least 2 or more positive detections for perchlorate at concentrations greater than or equal to 4 μg/L (the reporting limit). These 284 sources supply water for 77 drinking water systems (CA DHS, 2006) and represent active and standby sources (and exclude inactive, destroyed, and abandoned sources, and monitoring and agricultural wells) (CA DHS, 2006).
In 2005, the State of Massachusetts's Department of Environment Protection (MA DEP) reported monitoring results for 85 percent (379 of 450) of its community water systems and 86 percent (212 of 250) of its non-transient, non-community water systems. MA DEP found that 9 (1.5%) of the 591 public water systems detected perchlorate at levels greater than or equal to 1 μg/L (the reporting limit used for a modified version of EPA Method 314.0). MA DEP found that the occurrence of perchlorate for these water systems could be traced to the use of blasting agents, military munitions, fireworks, and, to a lesser degree, sodium hypochlorite disinfectant (MA DEP, 2005).
3. Studies on Perchlorate Occurrence in Foods, Plants, Beverages, and Dietary Supplements. The Food and Drug Administration (FDA), the United States Department of Agriculture (USDA), and researchers from academia and industry have studied perchlorate in foods. Some of these studies are described briefly in this section, and also summarized in Table 4. EPA has concluded that the sampling results described in this section and Table 4 are too limited to characterize food-borne exposure to perchlorate on a national scale. The sampling data are limited in the types of foods sampled, sample sizes, geographic coverage, and/or analytical method adequacy and many were targeted to foods or areas known or likely to have elevated levels of perchlorate. Section V.F of this action describes the limitations of the food sampling data and also describes plans for including perchlorate as part of the FDA's Total Diet Study. EPA requests that commenters provide the Agency with any additional data that may further characterize the concentrations of perchlorate in foods commercially available in the U.S. When providing data to the Agency, please describe the specific locations where the samples were collected, including geographic location, type of location (e.g., grocery store, farmer's market, commercial field, home garden), and the methodologies used to select, collect, prepare, and analyze the samples. Please include available laboratory data reports as well as all relevant quality assurance/quality control information.
a.
b.
Sanchez
As shown in Table 4, Sanchez (2004) also detected perchlorate in samples of melons, tomatoes, and peppers, but at levels below the method reporting limit. Perchlorate was not detected in carrots, onions, sweet corn, squash, and durum wheat. Concentrations of perchlorate in 10 samples of alfalfa ranged from 109 to 668 μg/kg FW. Six of the 10 alfalfa samples were sent to FDA for confirmatory analysis by IC-MS/MS. The FDA results were generally lower than those of the corresponding samples by Sanchez (2004), ranging from 121 to 382 μg/kg FW.
Sanchez
Citrus samples were collected during 2004-2005 from the lower Colorado River Valley, the University of Arizona Research Farm, the Coachella Valley, and Los Angeles County. All analyses of fruit pulp were conducted using IC-MS/MS with an approximate MRL of 2.5 μg/kg FW. For the 86 citrus samples collected, the perchlorate concentration in the fruit pulp ranged from below detection to 37.6 μg/kg FW. Mean concentrations in lemons (33 samples), grapefruit (15 samples), and oranges (28 samples) were 2.3, 3.3, and 7.4 μg/kg FW, respectively.
Sanchez
While not shown in Table 4, Sanchez
Researchers at Texas Tech University analyzed samples of dairy and soy milk using IC and/or IC/MS analytical methods with detection limits of 1 μg/L or better (Kirk
Jackson
Aribi
Snyder
Martinelango
Recently researchers have used the results of the analysis of urine samples to estimate human exposure to perchlorate. Ingested perchlorate is not metabolized by humans and is excreted largely in the urine (Merrill
Valentin-Blasini
Valentin-Blasini
The analytical method developed by Valentin-Blasini
In the largest study of its kind, Blount
Valentin-Blasini
Martinelango
Other studies have investigated perchlorate in human breast milk. Kirk
Blount and Valentin-Blasini (2006) developed a sensitive and selective method for quantifying iodide, perchlorate, thiocyanate, and nitrate in human amniotic fluid. The analytical limit of detection for perchlorate was calculated to be 0.020 μg/L. Samples of amniotic fluid at 15 to 20 weeks gestation were collected from 48 healthy women in an Eastern U.S. city for analysis. Perchlorate was found in all samples tested and exhibited a log-normal distribution. The perchlorate concentrations ranged from 0.057 to 0.71 μg/L with a median value of 0.18 μg/L.
As stated earlier, the Agency is not making a preliminary regulatory determination for perchlorate in this notice. The Agency believes that additional information is needed on the sources of human exposure if it decides to base its determination regarding health risk reduction potential on a health reference level (HRL) derived from the RfD and the relative source contribution (RSC) for drinking water. Under this approach, the Agency would use the RfD and RSC to estimate an HRL and then use this HRL as a benchmark against which to conduct an evaluation of the occurrence data. In conducting such an assessment for the 6 non-carcinogens discussed previously in this action, EPA used a 20 percent RSC, which is the lowest and most conservative RSC used to estimate an HRL. Since the initial screening of the occurrence data against the HRL resulted in a preliminary negative determination, the Agency found that it
Table 5 shows the number of systems and population served that would exceed the HRL under various RSC scenarios and the sensitivity of this estimate to relatively small changes in the estimated RSC. For example, increasing the RSC from 20 to 30 percent would lower the estimated number of systems impacted by about a third and the estimated population served by about half. Hence, the choice of an appropriate RSC and resulting HRL could impact EPA's determination of whether regulation of perchlorate represents a meaningful opportunity for health risk reduction if it uses this approach.
EPA recognizes that system-level population estimates shown in Table 5 may be conservative because some systems have multiple entry points to the distribution system and not all entry points had a positive detection for perchlorate in the UCMR 1 survey. Hence, to derive a less conservative population estimate (last column in Table 5), EPA assumed that the population for each system is equally distributed over all of the entry (or sampling) points and estimated a population-served value based on entry points that had at least 1 analytical detection for perchlorate at levels greater than each of the HRL thresholds.
Table 5 also includes information on the effects of using an RSC of 100% (that is, using an HRL set at the DWEL of 24.5 μg/L, rounded to a whole number). Crawford-Brown
While several States have recommended guidelines or public health goals for perchlorate, EPA recognizes that at least 1 state, Massachusetts,
While the Agency recognizes that food and other pathways may be important sources of perchlorate exposure, the Agency believes the currently available food data (summarized in section V.C.3) are inadequate to develop a better informed RSC (and HRL). First, some of the existing data are limited in their sample numbers, geographic coverage, and analytical method adequacy. Second, the current studies provide little or no data for several food groups (
This section presents and requests comment on data EPA might use to estimate an RSC based on food-borne exposure as well as on several other options that the Agency is considering to better characterize perchlorate exposure and assist the Agency in making its regulatory determination for perchlorate. These options could serve as a supplement or an alternative to developing an HRL based on a better informed RSC derived from food concentration and consumption data. The Agency specifically seeks comment on the use of urine biomonitoring data in estimating perchlorate exposure. If the Agency decides to use any of the approaches discussed in V.F.2, EPA will need to determine what statistics (
The Agency also invites the public to submit relevant data that may further characterize exposure to perchlorate through consumption of foods and/or through other pathways. The Agency will consider any new, relevant information/data provided in response to this action as the Agency determines whether to regulate perchlorate with a national primary drinking water regulation.
1. Use of Food Concentration and Consumption Data to Estimate an RSC. In the past, the Agency has relied on dietary exposure information from the FDA Total Diet Study (TDS) to determine the RSC allowed for drinking water and to set health goals (
FDA is including perchlorate as an analyte in the 2006 TDS. EPA believes that a comprehensive dietary intake estimate for perchlorate will be useful in evaluating dietary exposure relative to drinking water. When sufficient quantitative exposure data are available (such as the data published by FDA in conjunction with the TDS), EPA can use the procedure used previously for several regulated inorganic compounds (
The Agency invites the public to submit relevant data that may further characterize exposure to perchlorate through consumption of foods and/or through other pathways. This information may help the Agency in the evaluation of currently available food data and the 2006 TDS.
2. Use of Urinary Biomonitoring Data to Evaluate Exposure to Perchlorate. Researchers at CDC's National Center for Environmental Health (NCEH) have conducted a large national study of total perchlorate exposure through analysis of urine samples collected for NHANES 2001-2002 (Blount
• Perchlorate is not metabolized in the body and is excreted unchanged primarily via the renal pathway (Merrill
• Perchlorate does not bioaccumulate, that is, it is excreted essentially completely (Merrill
• Perchlorate has a short half-life in the human body (approximately 8 hours), simplifying the estimation of daily exposure (Greer
• A methodology exists that allows estimation of daily perchlorate intake from all sources (
The Agency could use the 2001-2002 NHANES urine data in several ways as described in the following paragraphs. The Agency welcomes comment from the public on these approaches, as well as suggestions for other analyses that may inform the preliminary regulatory determination for perchlorate.
One potential approach is to use the 2001-2002 NHANES urine data to directly determine whether regulation of perchlorate in drinking water presents a meaningful opportunity for health risk reduction. More specifically, we could use the urine data (as in Blount
EPA could also use the 2001-2002 NHANES urine data to qualitatively evaluate the importance of the water contribution to overall exposure. For this approach, the Agency could merge data from the 2001-2002 NHANES and UCMR 1 and compare the total perchlorate exposure values (based on the urine data) for the population of individuals whose drinking water contains perchlorate at various concentration levels, ranging from non-detect to the upper end of the occurrence distribution. The intent of this analysis would be to permit the Agency to determine whether total perchlorate exposure (as measured in urine) is meaningfully correlated with concentrations in local public drinking water supplies, though EPA would only use these results qualitatively because it is not possible to match up individual urine samples with individual drinking water exposures. However, the results could be useful in determining at least qualitatively the potential significance of drinking water exposure for total exposure. If there were not a significant correlation between public water system perchlorate occurrence and individual exposure as measured through biomonitoring, this might suggest that there is not a meaningful opportunity for health risk reduction through regulation of drinking water.
The Agency could also potentially use the 2001-2002 NHANES urine data to derive an RSC to use for drinking water. This could potentially be done in several different ways as follows.
a.
b.
c.
After the Agency evaluates and thoroughly reviews public comments and any new information/data on perchlorate obtained following this notice, and performs the necessary analyses, the Agency intends to move expeditiously to publish a preliminary regulatory determination for perchlorate. Depending on how quickly the Agency is able to complete the necessary analyses and determine the best approach for making this determination, EPA may be able to publish the preliminary determination in time to include a final determination for perchlorate as part of the final CCL 2 regulatory determination, which is due by July, 2008. If not, the Agency will publish its final determination for perchlorate as soon thereafter as possible. EPA does not intend to wait until the CCL 3 regulatory determination cycle to complete its determination for perchlorate.
As previously stated, EPA is only making regulatory determinations on CCL 2 contaminants that have sufficient information to support a regulatory determination at this time. Section V discusses the status of EPA's review of perchlorate. For the 30 remaining chemicals and the 9 microbial pathogens, the Agency lacks adequate information in the areas of health effects or occurrence or both.
The Agency continues to conduct research and/or to collect information
Because the focus of this action is to announce and solicit public comment on the Agency's preliminary determinations for 11 of the 51 CCL 2 contaminants, this action primarily provides information on these 11 contaminants. The Agency recognizes that the public may have a particular interest in metolachlor, methyl tertiary butyl ether (MTBE), and the microbial contaminants. Therefore, this action includes some additional information for these contaminants in the following sections and requests public comment on any further data, information and/or analyses that the Agency should be aware of.
1. Background. Metolachlor is a broad spectrum herbicide used for general weed control in many agricultural food and feed crops (primarily corn, soybeans and sorghum), on lawns and turf, ornamental plants, trees, shrubs and vines, rights of way, fencerows and hedgerows, and in forestry. Metolachlor appears to be moderately persistent to persistent and depending on the type of soil, can be highly mobile. Degradation of metolachlor in the environment is dependent on microbially-mediated and abiotic processes. Metolachlor has at least 5 major degradates. Two of the more common degradates are metolachlor ethane sulfonic acid (ESA) and metolachlor oxanilic acid (OA).
2. Health. The Agency established an RfD for metolachlor of 0.1 mg/kg/day based on an NOAEL of 9.7 mg/kg/day and a UF of 100 (USEPA, 1995). The Agency derived the NOAEL from a one-year chronic feeding study in beagle dogs where the critical effect was decreased body weight gain. Metolachlor shows some evidence of causing developmental toxicity effects in rats but none in rabbits. The doses associated with the developmental effect in rats are greater than the NOAEL and therefore the NOAEL would be protective against developmental toxicity.
Metolachlor has been evaluated for carcinogenic activity in both rats and mice. No treatment-related cancer effects were observed in 2 studies using mice. In studies using rats, metolachlor caused a significant increase in liver nodules and carcinomas in high dose females. Negative results from mutagenicity studies suggest that tumors may result from a nonmutagenic mode of action. In 1991, a peer review committee recommended that metolachlor be classified as a possible human carcinogen based on increases in liver tumors in the female rat. However, a peer review conducted in July 1994 recommended that the evidence for cancer was suggestive and should not be quantified. This recommendation was supported by negative mutagenicity data and recent metabolism data indicating that the formation of the metabolite presumed to be the ultimate carcinogen is very low (USEPA, 1995).
3. Occurrence. EPA included metolachlor as an analyte in the UCM Round 2 survey. EPA evaluated the UCM Round 2 Cross Section data and found that metolachlor was detected at or above the reporting limit of 0.1 μg/L in 0.83% of the 12,953 systems that sampled for metolachlor (USEPA, 2006a).
The USGS NAWQA program included metolachlor as an analyte in its 1992-2001 monitoring survey of ambient surface and ground waters across the United States. EPA evaluated the results of the provisional data, which are available on the Web at
4. Consideration of the ESA and OA degradates. While EPA has health and occurrence information for metolachlor itself, the Agency believes it is prudent to also consider the occurrence and exposure of the ESA and OA degradates as well. At this time, there is no finished water occurrence and exposure information for these 2 degradates from a nationally representative sample of PWSs. However, a few small-scale studies indicate that the ESA and the OA degradates may be occurring at greater frequencies and at higher concentrations than the metolachlor parent (Phillips
In addition, the Agency requests answers to the following questions and any available data:
• Are States collecting data on the co-occurrence of metolachlor and its degradates in source waters on a state-wide basis? In drinking water on a state-wide basis?
• If available, are States willing to provide data on the co-occurrence of metolachlor and its ESA and OA degradates in community and public water systems? What analytical method and reporting limit were used to gather these data?
• Do States have any information on the number of PWSs impacted by metolachlor and/or its degradates?
• Have States seen an increase or decrease in the number of PWSs impacted by metolachlor and/or its degradates?
• How many systems have taken wells or sources offline due to impacts from metolachlor and/or its degradates?
Methyl tertiary-butyl ether (MTBE) is a volatile organic compound synthesized for use as a gasoline additive. First used as an octane enhancer to improve engine performance, MTBE is also used to reduce emissions that form carbon monoxide and ozone. Leaking underground storage tanks, gasoline distribution facilities, and even recreational boating can release MTBE into the environment.
In 1997, EPA issued a drinking water advisory of 20 to 40 μg/L based on taste and odor (USEPA, 1997b). EPA is currently revising its health risk assessment for MTBE, and thus, will not be making a regulatory determination for MTBE as part of this action. The IRIS Chemical Assessment Tracking System
The Agency collected data on MTBE occurrence as part of the UCMR 1 survey. In addition, EPA evaluated several sources of supplemental occurrence information described in the supporting documentation for this action entitled “Regulatory Determinations Support Document for Selected Contaminants from the Second Drinking Water Contaminant Candidate List (CCL 2)” (USEPA, 2006a). Section VI.B.2 provides a summary of some of the data and information on MTBE occurrence collected to date.
a.
Of the PWSs reporting detections at or above 5 μg/L (the MRL), 15 were ground water systems and 4 were surface water systems. One small ground water system (49 μg/L) and 3 large ground water PWSs (48 μg/L, 36 μg/L, and 33.2 μg/L) reported MTBE at levels greater than 20 μg/L (the lower end of the taste and odor threshold). One large surface water system (33 μg/L) reported MTBE at levels greater than 20 μg/L. The remaining 14 systems had detects between 5 μg/L and 20 μg/L (USEPA, 2006a).
b.
USGS also reviewed the literature for national, regional, and State MTBE information (Delzer and Ivahnenko, 2003b), including 13 state-wide assessments. This information is summarized in Table 6. USGS noted that because study objectives varied, information varied in terms of reporting levels, sampling frequencies, and sources (e.g., ambient water, public and homeowner wells, treated drinking water).
Previously, USGS (Grady and Casey, 2001) studied MTBE occurrence in the drinking water of 12 States (New England and the Mid-Atlantic). The study found less than 1 percent of the CWSs had drinking water samples at or above 20 μg/L, while 7.8 percent of the CWSs had MTBE at 1 μg/L or higher.
c.
d.
e.
As discussed earlier, EPA is not making a regulatory determination for MTBE; however, EPA is presenting this information because of ongoing interest in MTBE. And as noted earlier, additional information is presented in the regulatory support document for this action (
• Are there additional occurrence data for MTBE in community and non-community public water systems on a state-wide or more local basis? As noted in the previous section, the State data submitted to EWG lack some elements needed to assess the quality of the data, as required in EPA's guidance for information quality guidelines (USEPA, 2003c), and project state-wide occurrence.
• What analytical method and reporting limit were used to gather these data?
• Has there been an increase or decrease in the number of impacted PWSs? Over what time frame?
• For those PWSs whose water supplies have been impacted, has there been an increase or a decrease in the concentration of MTBE?
• How many systems have taken wells or sources offline, consolidated with other PWSs, or added customers due to impacts from MTBE?
• What treatments are being used in the field? What range of treatment effectiveness is being achieved?
• Is the listing of State bans for MTBE shown in Table 7 complete? Have state-wide bans decreased MTBE contamination in drinking water?
1. Evaluation of Microbial Contaminants for Regulatory Determination. The 9 microbial contaminants listed on CCL 2 include:
• Four virus groups—Caliciviruses, Echoviruses, Coxsackieviruses, and Adenoviruses
• Four bacteria/bacterial groups-
• One group of protozoa—Microsporidia (
In addition to considering if the Agency had sufficient information to address the three statutory criteria listed in section II.B.1 (i.e., adverse health effects, known/likely occurrence, and meaningful opportunity for health risk reduction), the Agency also considered whether sufficient information was available to determine whether current treatment requirements adequately controlled for any of the 9 microbial contaminants. After consideration of these factors, the Agency determined that none of the 9 microbial contaminants have sufficient information at this time to address the three statutory criteria to make a regulatory determination. Table 8 identifies the specific areas for which information is insufficient.
2. Research and Other Ongoing Activities. EPA has supported an active research program to fill the information gaps on the CCL 2 microorganisms. While several examples of the ongoing research activities are listed below, further information on these and other projects can be found on EPA's Drinking Water Research Information Network (DRINK). DRINK is a publicly-accessible, Web-based system that tracks over 1,000 ongoing research projects and can be accessed at:
a.
b.
EPA has funded projects to evaluate the effect of disinfectants on cyanotoxins, and on the removal of algal cells and cyanotoxins in a pilot scale treatment plant. EPA is developing analytical methods for potential use for future monitoring and has available analytical chemistry standards for the toxins of most concern in the United States—microcystin, cylindrospermopsin, and anatoxin-a. EPA has conducted several small-scale preliminary occurrence surveys for cyanotoxins using a screening method followed by confirmation by instrumental analysis. A number of health effects studies are also in progress on several high priority cyanotoxins. These include behavioral studies in mice, acute and subacute effects in neonatal mice, and biomarkers of human exposure. Risk assessments are being conducted at EPA on the cyanotoxins to determine reference doses where possible. The Agency has organized and participated in several workshops on cyanotoxins to assess the state-of-the-science.
As an interim measure to assist public water utilities, the Agency is planning to develop an information sheet that discusses pertinent information on cyanobacteria and some of its key toxins. The document will discuss the state of the knowledge on the prevention and treatment of cyanobacteria and its toxins, as well as the available information on the potential health effects of some of the toxins. EPA requests comment from the public as to whether such a document would be useful for public water utilities.
c.
EPA intends to respond to the public comments it receives on the 11
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USEPA. 1997b. Drinking Water Advisory: Consumer Acceptability Advice and Health Effects Analysis on Methyl Tertiary-Butyl Ether (MTBE). EPA Report 822-F-97-009. December 1997. Available on the Internet at:
USEPA. 1998a. Announcement of the Draft Drinking Water Contaminant Candidate List; Notice.
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USEPA. 1998d. Notice of Receipt of Requests to Voluntarily Cancel Certain Pesticide Registrations.
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USEPA. 1999b. Revisions to the Unregulated Contaminant Monitoring Regulation for Public Water Systems.
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USEPA. 2003a. Announcement of Regulatory Determinations for Priority Contaminants on the Drinking Water Contaminant Candidate List.
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Environmental Protection Agency (EPA).
Final rule.
This final rule finalizes proposed changes made to the definition of “major emitting facility” in the Prevention of Significant Deterioration (PSD), Nonattainment New Source Review (NSR) and Title V regulations. Two of the regulatory changes proposed addressed the major source threshold for PSD sources. The remaining proposed regulatory changes finalized in this action address when fugitive emissions are counted for purposes of determining whether a source is a major source under the PSD, nonattainment NSR or Title V programs. The proposal solicited comment on whether wet and dry corn milling facilities that produce ethanol for fuel should continue to be considered a part of the chemical process plants source category, and whether other types of facilities that produce ethanol fuel should be considered for exclusion from the definition of chemical process plants. Based on comments received and evaluated, we have included additional changes to this final rule that exclude other facilities that produce ethanol by natural fermentation and are classified in North American Industry Classification System (NAICS) code 325193 or 312140 from the definition of “chemical process plants.”
This final rule is effective on July 2, 2007.
Ms. Joanna Swanson, Air Quality Policy Division, (C339-03), Environmental Protection Agency, Research Triangle Park, NC 27711, telephone number: (919) 541-5282; fax number: (919) 541-5509, e-mail address:
The title of this final rule has been changed from the proposed rule title to better reflect the final rule. The proposed rule was entitled “Prevention of Significant Deterioration, Nonattainment New Source Review, and Title V: Treatment of Corn Milling Facilities Under the “Major Emitting Facility” Definition.”
The information presented in this preamble is organized as follows:
Entities affected by this final rule are facilities that produce ethanol by a natural fermentation process that are classified under NAICS codes 325193 and 312140; and State/local/Tribal governments. Categories and entities potentially affected by this action are expected to include:
In addition to being available in the docket, an electronic copy of this preamble and final amendments will also be available on the World Wide Web. Following signature by the EPA Administrator, a copy of this notice will be posted on the EPA's NSR Web site, under Regulations & Standards, at
These regulatory changes affect the applicability provisions of two separate permitting programs: the major NSR
Title V of the CAA required EPA to promulgate regulations governing the establishment of operating permit programs. The current regulations are codified at 40 CFR parts 70 and 71.
The CAA, as implemented by our regulations, defines the applicability of these different programs based, in part, on whether a stationary source is “major.” For purposes of implementing the PSD program, Congress defined the term “major emitting facility” in section 169(l) of the CAA. This definition contains a specific list of source categories for which an individual source will be considered a major source if it has the potential to emit 100 tons per year (tpy) of any pollutant for which the local area is in attainment with the NAAQS. This is referred to as the 100 tpy threshold. For any source not otherwise listed, a 250 tpy threshold applies. For purposes of implementing the nonattainment major NSR program, we do not apply different applicability thresholds based on the type of source category. All sources are subject to a 100 tpy threshold or less depending on the severity of the nonattainment problem.
All major sources, as the term is defined for title V purposes, are required to obtain title V operating permits. Sources required to obtain title V permits include those sources subject to PSD and nonattainment NSR. Therefore, title V relies in part on the definition of “major emitting facility” for the PSD program.
In addition to the determining which applicability threshold applies to a given source, the determination of whether a source is “major” is also partly dependent on whether the stationary source must count both fugitive and stack emissions in determining whether it exceeds the threshold. Section 302(j) provides that
(j) Except as otherwise expressly provided, the terms “major stationary source” and “major emitting facility” mean any stationary facility or source of air pollutants which directly emits, or has the potential to emit, one hundred tons per year or more of any air pollutant (including any major emitting facility or source of fugitive emission of any pollutant, as determined by rule by the Administrator).
In 1980, we established a list of source categories that must consider fugitive emissions in source applicability determinations. We used the section 169(1) list of categories in developing our 302(j) list of categories.
This final rule involves changes to the “major stationary source” and “major source” definitions in the NSR and title V programs as this definition relates specifically to the manufacturing of ethanol through natural fermentation processes. These changes affect both the applicability threshold and whether this industry must count fugitive emissions in determining its major source status.
On March 9, 2006 (71 FR 12240), we proposed to reinterpret the component term “chemical process plants” within the statutory definition of “major emitting facility” in section 169(1) of the CAA to exclude wet and dry corn milling facilities which produce ethanol fuel (Option 1). We requested comment on another option in which we would continue to include wet and dry corn milling facilities that produce ethanol fuel within the definition of “chemical process plants.” (Option 2). We also proposed similarly to reinterpret the regulatory term “chemical process plants” on the list of source categories for which fugitive emissions must be included in determining whether the source is a “major stationary source.”
To implement these proposed changes, we proposed to revise the definition of “major stationary source” under 40 CFR parts 51 and 52, and the definition of “major source” under 40 CFR parts 70 and 71. (See 71 FR 12240, March 9, 2006). Finally, we also requested information on other types of ethanol production facilities and comment on whether other types of facilities including those that produce potable ethanol or ethanol fuel should be considered for exclusion from the “chemical process plants” definitions.
This rule finalizes Option 1 and reinterpret the component term “chemical process plants” within the statutory definition of “major emitting facility” and regulatory definitions of “major stationary source” and “major source” to exclude wet and dry corn milling facilities that produce ethanol for fuel or ethanol for food. Moreover, based on comments we received, we are extending the exclusion to all facilities that produce ethanol through a natural fermentation process that involves the use of such things as corn, sugar beets, sugar cane or cellulosic biomass as a feedstock regardless of whether the ethanol is produced for human consumption, fuel or for an industrial purpose. This includes denatured alcohol, nonpotable ethanol, nonpotable grain alcohol, potable ethyl alcohol and grain alcohol beverages. We are also reinterpreting the term “chemical process plants” on the list of source categories that must count fugitives emissions in determining whether a source is a major source to be consistent with the way we now interpret that term for purposes of determining the major source threshold.
As proposed, we are changing the PSD and nonattainment NSR regulations that we are amending with this action to include amendments to 40 CFR 51.165, 51.166, 52.21, and appendix S. We are also amending the 40 CFR parts 70 and 71 title V regulations. We are not making changes to 52.24 as proposed because we revised that section. Paragraph (f) now cross-references the provisions of 40 CFR 51.165 for definitions of terms under 40 CFR 52.24, and paragraph (h) no longer lists source categories.
These final rule amendments define “chemical process plants” under the regulatory definition of “major emitting facility” to exclude ethanol manufacturing facilities that produce ethanol by natural fermentation processes. In addition, we have changed our approach to defining the sources within the exclusion as explained below. As explained in the preamble to the proposed rule (71 FR at 12243), in 1981, when we originally interpreted the “chemical process plants” term by guidance, we did so in reference to SIC 28. Since the time we defined the chemical process plant based solely on reference to SIC 28, the Federal Government replaced the SIC code manual with the NAICS. Under the NAICS, as compared to the SIC system, there are over 350 more industries classified. Federal Government agencies have adopted the NAICS to collect
Ethanol fuel and industrial ethanol fall within NAICS 325193 (Ethyl Alcohol Manufacturing) which includes denatured alcohol, nonpotable ethanol, and nonpotable grain alcohol. The NAICS 312140 (Distilleries) includes potable ethyl alcohol and grain alcohol beverages. Even though NAICS 325193 (ethyl alcohol manufacturing) has been classified under NAICS' Chemical Manufacturing subsector, unlike under the SIC classification of 2869 (Industrial Organic Chemicals, Not Elsewhere Classified), ethyl alcohol manufacturing is within its own narrowly defined category.
The Agency has considered whether, and in what way, we might transition from use of the SIC to the NAICS for purposes of determining the scope of a stationary source in general and for other purposes such as source category determinations. We have not reached any universal conclusions. Notably, however, some commenters expressed concern that by refining the “chemical process plants” definition such that we no longer rely solely on SIC code 28, we would be embroiling the Agency in the “fine grain” analysis we sought to avoid under our initial guidance, negating the objectivity of the current approach. In view of this comment, we think it useful to consider the NAICS codes as a potential tool to address the commenters' concerns. At proposal, we did not use SIC codes to define the facilities that are subject to these changes. We have decided to use NAICS codes to define these facilities in the final rule because the narrow classification of the NAICS codes for ethyl alcohol manufacturing (NAICS code 325193) and distilleries (NAICS code 312140) under the NAICS is useful and eliminates the problem of having to do a “fine grain” analysis.
Accordingly, in response to commenters, our final rule references the NAICS codes 325193 and 312140 to exclude facilities using a natural fermentation process to produce ethanol from the definition of “chemical process plants.” We believe that by defining the “chemical process plants” in this way, we retain the objectivity and ease of implementation inherent in our original guidance.
The remaining regulatory changes address when fugitive emissions are counted for purposes of determining whether a source is a major source under the PSD, nonattainment NSR, or title V programs. Our final rule treats the term “chemical process plants” in those regulations in the same manner as we treat it for purposes of determining the major source threshold.
In our proposed rule, we expressed several reasons to support our proposal to change the definition of “chemical process plants.” First, we cited concerns related to the disparate treatment of ethanol fuel production verses production of ethanol intended for human consumption by applying two different major source thresholds. Because the two manufacturing processes are substantially similar, we believed that the process should be treated identically for purposes of the PSD and title V regulations regardless of the intended product. We also cited concerns that continuing to regulate the ethanol fuel industry, under the 100 tpy major source threshold, regardless of the production method could stymie the growth of the industry, and hamper our nation's efforts toward energy independence. Some commenters agreed with our general approach. Other commenters asserted that a mere similarity in processes did not justify our proposed redefinition of the “chemical process plant” category. Other commenters questioned whether permitting agencies treated the two types of ethanol production differently for regulatory purposes.
After reviewing the comments, we re-examined whether our policy concerns remain valid, and affirm our conclusion that a change in the “chemical process plant” category definition is warranted. Although we received conflicting information as to how permitting authorities regulate ethanol intended for human consumption, especially at plants that also produce ethanol for fuel, we maintain the fundamental premise for our proposal, that ethanol, regardless of intended use, is produced through substantially similar processes, and that similar processes should be regulated in a similar way. Although there may be jurisdictional differences in the way these industries are regulated, we believe this further supports the need to clarify the definition of “chemical process plants” relative to the ethanol production industry as a whole and does not negate the fundamental basis on which we proposed the rule.
We continue to believe that supporting our nation's efforts toward energy independence is an important national goal, and that this consideration is appropriate in deciding how to balance our nations economic growth with environmental protection. The Energy Policy Act of 2005 (Pub. L. 109-58) established a renewable fuel standard (RFS) that requires an increasing use of renewable fuels in our nation. It is clear that continued growth of the ethanol industry will play a vital role in achieving our nation's energy and environmental objectives.
While we are uncertain what impact this regulatory action may have on furthering our progress toward the goal of energy independence, we believe that including ethanol fuel in the “chemical process plants” presented potential obstacles for growth in the industry. These obstacles primarily include the time it takes to obtain a preconstruction permit, and, in some cases, the potential costs that may be incurred as a result of having to apply additional emissions controls. As we discuss, in section V, we conclude that this rule is not likely to result in significant net environmental harm. Nonetheless, even if our consideration of potential environmental consequences understates potential negative environmental consequences, we believe that the potential for other environmental benefits and the desire to support our nation's energy policy objectives outweigh any potential negative environmental consequences that could potentially result from this rule.
We maintain, as we did in the proposal preamble, that we have the discretion to define “chemical process plants” to exclude wet and dry corn milling facilities. As stated above, we based our proposed rule on the premise that ethanol production should be treated similarly regardless of whether it is produced using either the wet or dry corn milling process, and regardless of whether the end product is used as fuel or for human consumption because the process steps involved are essentially the same. As we noted in the proposal, the only difference is the final step where a small amount of denaturant (such as gasoline) is added to render the ethanol unfit for human consumption. This rationale also supports expansion of the exclusion to all facilities that produce ethanol through a natural fermentation process. We received numerous comments supporting this finding. Although some commenters pointed to differences in the production process, we are not persuaded that the differences justify disparate regulatory treatment. We also received comments justifying the expansion of our regulatory exclusion to other feedstock and end product uses. We discuss our
Some commenters assert that we are not entitled to deference because such facilities fall within the plain meaning of the term “chemical processing plant.” Others assert that section 169(1) shows Congress’ intent to focus on a facility's finished product and economic sector in which an industry competes.
We do not believe that the term “chemical process plant” is subject to a “plain meaning interpretation.” There is not a universally accepted definition of chemical process, and accepted definitions differ depending on whether you view the term from a purely scientific sense or from an engineering sense, or for economic purposes. The scope of the chemical industry is in part shaped by custom rather than by logic and excludes industries that nevertheless engage in chemical processes,
We also disagree that section 169 clearly shows Congress's intent on what factors we must consider in making source category determinations. As discussed below, we have used a variety of considerations in making source category determinations. We generally have not conducted economic analysis in making these decisions, nor have we based our decision solely on the end product produced or strictly followed an SIC approach for all categories.
Significant comments received on, and our responses to, the proposed amendments to the “major emitting facility” definition are presented in the following paragraphs.
The
Several commenters on the proposal argued that there was insufficient explanation as to why we proposed the change for only one type of facility (
This final rule finalizes the exclusion for wet and dry corn milling ethanol production facilities and expands that exclusion to include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 and 312140 (includes denatured alcohol, nonpotable ethanol, nonpotable grain alcohol, potable ethyl alcohol, and grain alcohol beverages).
The following subparagraphs present greater detail on the comments received on the proposed “major emitting facility” definition and whether the “chemical process plants” exclusion for corn milling ethanol fuel production facilities should be expanded to facilities that produce ethanol fuel from cellulosic biomass, sugar beets, and sugar cane; and facilities that produce industrial ethanol from corn, cellulosic biomass, sugar beets, and sugar cane.
Importantly, contrary to some commenters' assertions, EPA explicitly rejected the use of the “primary activity test” as the decisive means of defining source categories listed under section 169(1).
As one commenter properly pointed out, we use the SIC code manual only as the starting point for determining which pollutant-emitting activities should be considered as part of the same source category, but rely on case-by-case assessments to determine whether a particular stationary source belongs in a given source category. (Docket No. EPA-OAR-HQ-2006-0089-0086).
Using this case-by-case approach, we applied different rationales for determining if a particular stationary source falls in a given source category. For example, we relied on the existing NSPS definition of municipal waste combustor in determining whether a source falls within a listed category.
For the chemical process plant category, EPA took a much more straightforward approach. Instead of specifically considering the pollutant emitting activity, the feedstocks, process steps, end products, or application of existing NSPS definition to making case-by-case determinations, EPA chose to specifically define the category based on SIC 28. We based this decision on a desire to promote consistency with source scope determinations, and for ease of implementation and objectivity.
Because of limited resources, EPA could not feasibly set NSPS requirements for all categories of stationary sources simultaneously. Therefore, the goal of the Research Corp. study was to identify sources for which NSPS controls would have the greatest impact on reducing the quantity of atmospheric emissions. Research Corp. examined approximately 190 different types of stationary sources that potentially could be determined to be major emitting facilities, and provided information on the types of air pollutants that those sources emitted. The Research Corp. study was used by EPA in setting priorities for the order in which it would promulgate NSPS requirements for categories of stationary sources.
The Research Corp. study was also relied on by Congress in identifying the 28 categories of stationary sources specifically listed in the definition of the term “major emitting facility” in section 169(1) of the CAA. 122 Cong. Rec. 24,520-23 (1976). As explained by Senator McClure in the Congressional Record, the EPA Administrator examined the data from the draft Research Corp. study and determined that 19 of the stationary source categories examined should initially be classified as major emitting facilities. Senator McClure further explained that the Senate Committee added nine more categories of stationary sources to the 19 selected by EPA for a total of 28 source categories. 122 Cong. Rec. at 24,521.2
As discussed in the proposal preamble, in discussing the specific sources identified in section 169(1), Senator McClure stated:
Mr. President, I ask unanimous consent that an extract from that report of the Research Corp. of New England, listing the 190 types of sources, from which the EPA took 19, and the committee took 28, be printed in the Record at this point as an illustration of what the committee examined and the kinds of sources the committee intended to include and exclude, recognizing that it is neither exclusive nor invariable. There is administrative discretion to add to the list, to change the list. But the committee spoke very clearly on its intent on that question.
As a result of Senator McClure's action, the table from the draft Research Corp. report containing the list of 190
For the chemical process industry grouping, the Research Corp. study considered 24 different source categories and their associated pollutants. Notably, within the chemical process industry listings in the 1977 final report and in the 1976 draft report (as incorporated into the Congressional Record) there is no listing which refers to ethanol production, ethanol fuel production, or corn milling operations.
Given this history, we agree with commenters that Congress' silence on the matter can not be taken as an intent to exclude ethanol, nor however, do we believe that the silence can be taken as an intent to include ethanol within the chemical process plant definition. It is precisely because Congress did not express an intent, and because the Congressional record shows that Congress recognized that the list was neither “exclusive or inclusive” that we believe we have discretion to determine whether or not the ethanol industry belongs in the chemical process plants source category.
We are not persuaded that the mere fact that chemical reactions occur or that toxic chemical are added would have compelled Congress to include the industry within the category. These factors are too broad and too common in a multitude of industries to be effective criteria for categorizing sources.
Conversely, one commenter provided that the production of ethanol for fuel involves processes that are different in character than production of ethanol for human consumption, involving more steps and additional distillation that is necessary, among other things, to produce 100% ethanol (200 proof) needed for use as a fuel. This commenter pointed out that the closer the distillation process gets to producing 100% ethanol, the more energy/fuel is consumed, the more steps required, and the more pollutants emitted from the chemical processing plant.
One commenter explained that while the two processes are theoretically the same, ethanol fuel is produced on a much larger scale, and competes with other fuel markets. They provided that alcohol for human consumption does not contain as much alcohol as ethanol fuel after the distillation process (40-50% compared to 90-100% ethanol), and is subject to different regulations (
Finally, one commenter asked EPA to explain in greater detail its conclusion that the two processes are the same.
One commenter stated that ethanol fuel production facilities are more like refineries than an alcohol for consumption facility. They argued that ethanol fuel production facilities should be regulated similarly to a chemical process plant as that is what they are producing.
In the dry mill process, the grain or feedstock is not separated into its constituent parts prior to cooking. Both wet and dry milling operations produce ethanol as well as other coproducts. “Co-products from the dry mill process, separated from the ethanol in the distillation step, include distiller's dried grain (DDG) and solubles (S), which are often combined and referred to as DDGS. DDGS is used as an animal feed. In the wet mill process, co-products are separated from the ethanol production process in the initial grinding or milling step. Coproducts from the wet milling process include fiber and gluten, which are used for animal feed and corn oil.”
Most new ethanol production capacity comes from dry mill processing facilities. Wet milling operations, on the other hand, can produce ethanol, including ethanol for fuel, but are typically primarily engaged in producing starch, syrup, oil, sugar, and by-products, such as gluten feed and meal. For ethanol which will be used as fuel, toxic solvents (typically gasoline) are added to the ethanol to render it unfit for human consumption (denatured). This additional step is required to develop ethanol fuel regardless of whether the dry or wet mill process was employed to develop the initially potable ethanol.
We recognize that though the corn milling ethanol production processes for ethanol fuel and ethanol for human consumption are theoretically the same, ethanol fuel is produced on a much larger scale, and competes with other fuel markets. We also acknowledge that alcohol for human consumption does not typically contain as much alcohol as ethanol fuel (or some other denatured ethanol products (
One commenter noted that there are facilities other than corn milling which are capable of producing ethanol, notably molasses processing plants, and they should also be excluded from the definition of “major source” under the PSD, NSR, and title V programs. They provided that processes for both the production of ethanol from sugarcane molasses and from corn are similar, and because the processes are similar, the air emissions from the production of either product would also be similar.
One commenter stated that EPA's proposed rulemaking specifically requested public comments with respect to how future technological developments in the ethanol industry may be affected by the proposed rulemaking. They explained that while the current ethanol industry is dominated by the wet and dry corn milling process, the future of the ethanol industry could involve additional grain feedstocks such as wheat, barely, or rice as well as cellulosic feedstock's such as wood waste, switchgrass, and municipal solid waste. This commenter provided that they believed since EPA's proposal is rather narrowly focused on wet and dry corn milling newer ethanol production technologies currently under development could fall into the same regulatory quandary EPA is trying to correct through their proposal. They recommended that EPA's final rulemaking be expanded to also cover the other ethanol production technologies that may be developed in the future. They suggested that the EPA modify the currently proposed rule language to adopt language more consistent with the various NSPS rules (such as the synthetic organic chemical manufacturing industry (SOCMI) wastewater NSPS Subpart YYY standard) and exclude any process that uses “natural fermentation” to produce ethanol from the definition of a “chemical processing plant” under section 169.
One commenter stated that they believed that it is appropriate to treat all other types of facilities which produce ethanol from cellulosic biomass feed stocks similarly to how corn milling facilities are being proposed to be treated under Option 1.
One State commenter provided that other environmental rules have made distinctions with regard to applicability between ethanol by fermentation/biological processes and synthetic ethanol production:
1. NSPS subparts NNN and RRR—excludes ethanol by fermentation. The commenter stated that EPA has previously determined that ethanol-manufacturing facilities may be exempt from NSPS subparts RRR and NNN on a case-by-case basis. The commenter explained that in this instance, the ethanol facilities in question use a biological process to ferment the converted starches in corn into ethanol. These NSPS subparts did not envision unit operations for biological processes.
2. Categorical waste water effluent limits for Organic Chemicals, Plastics and Synthetic Fibers, part 414—excludes ethanol by fermentation. The provisions of this part do not apply to any process wastewater discharges from the manufacture of organic chemical compounds solely by extraction from plant and animal raw materials or by fermentation processes.
The commenter argued that EPA's proposal of Option 1 would be consistent with the above programs and that the exclusion should not be limited to “corn” wet and dry milling to make ethanol fuel. They supported their position by stating that several plants currently use milo along with corn to make ethanol fuel, and that the future of ethanol appears to be in the use of biomass,
One commenter stated that it should not matter what biomass or carbohydrate feedstock is used in the ethanol production process as the natural fermentation and distillation steps would be the same as they are for corn milling ethanol production.
One commenter provided that chemical feed stocks made from renewable sources should all be excluded as many of the products subject to the definition of chemical process plant were originally synthetically produced when SIC codes were established (
One commenter opposed any suggestion to exclude “other types of facilities which produce ethanol fuel, such as those using cellulosic biomass feedstocks,
In cellulosic ethanol production, acid is introduced to the feedstock at high temperatures to release hemicellulose sugars (depending on the type of cellulose used). If acids are toxic, they are removed prior to saccarification (break down of starches) and fermentation steps. Enzymatic hydrolysis to produce sugars from cellulose is another alternative being researched in pilot and demonstration commercial plants. The result is a “beer” with 4 to 5 percent alcohol content by weight. The distillation step is employed to produce ethanol at about 92 to 93 percent alcohol which must be processed by a vapor-molecular sieve (to further dehydrate the ethanol) to create fuel (the last step involving the adding of a denaturant). It is important to note that the use of a molecular sieve is not unique to cellulosic biomass ethanol production facilities as it is something that is used at many corn milling ethanol production facilities. Molecular sieves have become a popular means to dehydrate ethanol as they are low cost, environmentally friendly, and require less energy. Facilities that use molecular sieves replace azeotropic distillation systems that use cyclohexane or benzene (HAP), which were expensive, costly to operate, and energy intensive.
Based on the process diagrams and information received from commenters that indicate that the fermentation and distillation processes are similar (included as part of the technical record), even though the pre-steps and after-steps may differ, we are expanding the exclusion of the definition of “major emitting facilities” to include ethanol production facilities that produce ethanol through natural fermentation processes included in NAICS codes 325193 or 312140.
We are not excluding other chemicals (
Several commenters provided input on the historic regulatory treatment of wet and dry corn milling facilities which produce ethanol fuel. Some of the commenters stated that EPA's proposal to exclude wet and dry corn milling facilities from the definition of “chemical process plants” was consistent with historic regulatory treatment, while others argued that it was inconsistent with historic regulatory treatment.
• One commenter requested clarification of rule applicability, with regards to ethanol production, of numerous NSPS and MACT standards.
• Two industry commenters suggested that the rule include changes to the relevant NSPS under 40 CFR part 60 since alcohol production facilities are potentially subject to several standards of performance for new stationary sources, including 40 CFR part 60, subparts Kb (volatile organic liquids storage vessels), VV (equipment leaks of volatile organic compounds (VOC) in the SOCMI), NNN (SOCMI distillation operations), and RRR (VOC emissions from SOCMI reactor processes.
• Two State commenters provided examples where wet and dry corn milling facilities which produce ethanol fuel are treated as chemical process plants (40 CFR part 60, subparts VV, NNN, RRR (in Minnesota); 40 CFR part 63, subpart FFFF Miscellaneous Organic NESHAP (the MON Rule); AP-42 (Chapter 9.9.7 for Corn Wet Milling)).
• Two environmental consultants, two industry commenters, and one State noted that EPA rulemakings and associated interpretive guidance have either established exemptions (or allow sources to seek exemptions on a case-by-case basis) for chemicals produced through fermentation (as with corn milling ethanol production) from various SOCMI industry regulations, including the NSPS subparts RRR (SOCMI process reactors) and YYY (SOCMI wastewater units).
• One State commenter stated that categorical wastewater effluent limits for Organic Chemicals, Plastics, and Synthetic Fibers found in 40 CFR part 414 (promulgated under the Clean Water Act) excludes ethanol manufacturing by fermentation.
• Two industry commenters were concerned that the 27th listed source category in the NSR and title V programs also regulates ethanol plants as a result of the NSPSs captured under this source category.
• One environmental commenter stated that EPA has treated “ethanol blending facilities”—facilities that mix ethanol into gasoline—as refineries. 40 CFR 80.2(u). (“Ethanol blending plant means any refinery at which gasoline is produced solely through the addition of ethanol to gasoline, and at which the quality or quantity of gasoline is not altered in any other manner.”) (emphasis added). Additionally, the commenter argued that EPA has referenced the distinction between “chemical grade” ethanol that is used in transportation fuel and other kinds of ethanol. See 40 CFR 79.55(e)(1)-(2).
For example, ethanol is listed as a SOCMI chemical for which 40 CFR part 60, subpart YYY (SOCMI wastewater units) applies, however, the supplemental proposed rule (63 FR 67988; September 12, 1994) excludes certain processes from the definition of chemical process unit (CPU) because they were not considered SOCMI processes, but are sometimes associated with SOCMI processes. Organic chemicals extracted from natural sources or totally produced from biological synthesis such as pinene and beverage alcohol were specifically excluded from the CPU definition. Under 40 CFR part 60, subpart YYY, the determination for excluding biological processes was based on the designation for the process unit, in contrast to the plant site. Under the 40 CFR part 63, subpart FFFF (the Miscellaneous Organic National Emission Standards for Hazardous Air Pollutants (NESHAP) (the MON)) standards, the applicable miscellaneous organic chemical process unit for which standards apply includes all equipment that collectively function to produce a product or material described in the standard (including denatured alcohol). The pollutant to be controlled (
As for the commenters' concern that the 27th listed source category in the NSR and title V programs regulates ethanol plants as a result of the NSPSs captured under this source category, this concern would not be valid as all of the NSPSs listed by the commenters (40 CFR part 60, subparts Kb, VV, NNN, and RRR) were proposed and promulgated after August 7, 1980. The 27th listed source category referenced by the commenters includes “[a]ny other stationary source category which, as of August 7, 1980, is being regulated under section 111 or 112 of the CAA.”
As noted in the proposal preamble, when we promulgated the list of source categories relative to the definition of “major emitting facility” in the NSR regulations on August 7, 1980 (45 FR 52676), we adopted this same list to identify source categories for which fugitive emissions were to be counted in determining whether a source was a major source. We promulgated the 28 source categories as a result of the decision in
Another commenter stated that the EPA must specifically evaluate whether eliminating this requirement is appropriate based on criteria that relate to the intent of the PSD program and the air quality impact of such emissions. The commenter explained that the EPA has adopted criteria for the very purpose of determining whether to consider fugitive emissions—those criteria require EPA to examine (1) Whether sources in the category could degrade air quality; and (2) whether the cost of controlling fugitives are unreasonable compared to the expected benefits. The commenter argued that it would be arbitrary and irrational for EPA to affirmatively change its treatment of these sources without subjecting that decision to a meaningful substantive evaluation. The commenter asserts that because the initial classification imputed a need to address fugitive emissions from these plants, and because nothing in EPA's proposal functions to counter that expectation, the commenter believes that it was not rational for EPA to exclude ethanol fuel plants from the fugitive emissions requirements without conducting an appropriate assessment.
Nonetheless, even if this action triggers the section 302(j) rulemaking requirement, we believe this rulemaking constitutes a sufficient section 302(j) rule that is consistent with the way we interpreted that requirement in 1980 and re-affirmed in 1984. (45 FR 52676, 52690 (Aug. 7, 1980) and 49 FR 43202 (Oct. 28, 1984)). Specifically, we determined that our action to list a category under section 302(j) may be based on a policy decision after considering certain criteria, that we do not need extensive technical analysis to support our determination, and that the purpose of rulemaking is to afford the public an opportunity to comment on the Administrator's decision.
In 1979, when we initially proposed to use the section 169(1) source category list, our stated rationale for the proposal was only that we decided to focus first on the listed sources because of our experience in quantifying the “fugitive emissions” from these sources. (44 FR 51924, 51931 (Sept. 5, 1979)). Similar to comments received on this proposed rule, we received comments then that our rulemaking then was inadequate, and that we should have conducted technical analysis to support our proposed rule. We rejected commenters assertions. We also stated that the purpose of the rulemaking was to afford the public the opportunity to comment on the Administrator's decision, and to allow commenters to present factual or policy arguments that it would not be appropriate to include fugitive emissions in threshold calculations.
In 1984, after re-examining our interpretation of the section 302(j) requirements, we affirmed that the rulemaking requirements of section 302(j) were intended to afford the public an opportunity to comment on the Administrator's decision to list a category, and that we were not required to undertake extensive technical analysis to support our determination. That 1984 preamble discussion addressed two criteria relevant to the Administrator's decision to require sources to include fugitive emissions in threshold applicability determinations. We note that commenters
[a] determination by EPA that the sources in a category pose a threat of significant air quality degradation in effect establishes a presumption that the sources should be subject to PSD and nonattainment review * * *. Commenters then may seek to rebut this presumption by producing a record that unreasonable social or economic costs relative to the anticipated benefits would occur if PSD or nonattainment review were applied to a particular category of sources * * *
Importantly, we discussed these criteria in light of our overall belief that listing a category involved the Agency's exercise of policy discretion for which we carry a very low analytical burden in deciding to list a source category. Under this interpretation, section 302(j) functions as a useful “safety valve,” while at the same time minimizing the expenditure of Agency resources. 49 FR 43202, 43208 (October 26, 1984). Notably, the 1984 final rule preamble did not address how or whether that requirement applies to EPA's decision to interpret a category already on the list to exclude a narrow set of sources.
Consistent with the “safety valve” purpose served by a section 302(j) rulemaking, we believe that it is not necessary to require a negative finding with respect to the same criteria before we interpret a category on the list to exclude certain types of sources. In sum, having made a policy decision based on a limited technical finding, we do not believe that our technical burden now in acting to refine a category on the list, should be greater than the technical analyzes we undertook in listing the categories in the first instance.
Notably, as we stated, when EPA added “chemical processing plants” to the section 302(j) list in 1980, it did so based on a very general finding that sources within the category could were considered major polluters. We did not make any specific determination as to the appropriateness of counting fugitive emissions from any particular type of stationary sources within that category. At the time we conducted the section 302(j) rulemaking, few ethanol facilities existed and inclusion of ethanol manufacturers was not specifically analyzed in our section 302(j) rule. When we examined the issue more closely in 1981, we made a policy decision without conducting technical analysis, to include ethanol fuel manufacturing within the chemical processing plant category. We based this decision on a desire to maintain consistency with use of SIC 28 and ease of implementation. Thus, before now, we considered this industry to be a source within the listed category. However, we find that the category should not include these sources or others who engage in natural fermentation process to produce ethanol. We believe that it is not necessary to require a negative finding with respect to the criteria that apply to list a category under section 302(j) before we interpret a category on the list to exclude certain types of sources. We believe that the economic and policy rational for the exclusion of certain ethanol production facilities from the chemical processing plant category for purposes of defining major emitting facility that we present elsewhere in the preamble to the proposed rule and in this preamble also provides ample support for a section 302(j) determination not to count fugitive emissions from such facilities.
This decision is precisely the kind of “flexibility to provide industry-by-industry consideration and appropriate tailoring of coverage” envisioned by the
Specifically, this commenter indicated that the Federal government has argued in some of these complaints that ethanol production plants are facilities for synthetic organic chemical manufacturing and are affected facilities under part 60, subpart VV, 40 CFR 60.480, and are subject to the leak detection and monitoring requirements on 40 CFR 60.482-1 through 60-489, which govern the synthetic organic chemical manufacturing industry.
The commenter stated that the EPA formally charged that ethanol fuel facilities were chemical plants in 2002, when the EPA and the State of Minnesota filed complaints against all 12 Minnesota ethanol plants. Those complaints stated that the plants were major emitting sources under section 169 (1) of the CAA, 42 U.S.C. 7479 (1). Those cases were settled when these plants agreed to install thermal oxidizers and other additional pollution control equipment on their plants to bring their emissions per criteria pollutant to below 100 tpy. The companies were also fined from $18-42,000 a piece. A companion complaint was also filed, and settled, against Ace Ethanol in Wisconsin.
The commenter expressed that the DOJ stated in a December, 2005 press release that 83% of the ethanol industry is under consent decrees. The decrees were all imposed to enforce the PSD provisions of the CAA under the legal theory that the ethanol plants were synthetic organic chemical manufacturing plants. All of these consent decrees required the plants to keep their emissions of each criteria pollutant below 100 tpy. Some decrees also required compliance with the leak detection and monitoring requirements found at 40 CFR 60.482-1 through 60-489, which govern the synthetic organic chemical manufacturing industry.
In sum, the commenter stated that DOJ and EPA have consistently stated in court documents on nineteen separate occasions over the last 4 and one-half years that ethanol plants are chemical manufacturing plants. The commenter further stated that the DOJ and EPA have committed countless thousands of hours of staff and attorney time, laboring to advance this position. The commenter argued that the proposed preferred Option 1 could produce a situation where some or all of these companies, especially those who have been charged within the last several months (Cargill, MGP, Golden Triangle, AGP, and others) could claim that the consent decree terms, such as the 100 tpy limit per pollutant, no longer applies to their plants. Any plant who has not had their consent decree discharged could immediately apply to have the decree dissolved since the decrees' emissions limits no longer apply to ethanol plants. Additionally, the commenter asserts that these companies could ask the EPA to pay them back the millions in fines that they paid. The commenter is concerned that under Option 1, companies would be entitled to remove their thermal
One commenter representing State and local governments opposed the EPA's preferred option (Option 1). They argued that if new facilities are allowed to construct without controls options, then EPA may face future lawsuits from existing facilities, insisting on a level playing field, for removal or relaxation of their control strategies. The commenter expressed that the EPA should uphold their previous decisions to enforce installation of pollution control technologies at all ethanol facilities.
The conditions for termination of the consent decrees are specified expressly in each consent decree. Such consent decrees can only be terminated after the source completes its consent decree obligation and demonstrates compliance with the consent decree terms to the satisfaction of the United States. One of those terms is that a source obtains a Federally-enforceable operating permit incorporating the terms of the consent decree.
Our rationale for this final rule is explained in detail elsewhere in the preamble to the final rule. That we took actions to enforce the requirements in place before this rule does not undermine the basis for this rule. Existing facilities located in attainment areas would be required to maintain their existing permit limits and other permit requirements unless and until revised through a permitting procedure which, to be consistent with CAA section 110(a)(2)(C) and 40 CFR 51.160, must be shown not to cause or contribute to a violation of the NAAQS. We believe that raising the threshold from 100 tpy to 250 tpy in attainment areas will likely encourage facility expansions and construction of larger, more economically efficient plants, which in turn, will emit less emissions per gallon of ethanol produced. The 100 tpy threhold on the other hand encourages the construction of more numerous, less economically efficient smaller facilities. In addition, as noted below, the environmental and health impacts of this rule are limited.
Several comments were received concerning the potential negative impacts to the environment based on our proposed change. Some of the significant comments and concerns are provided in the following paragraphs.
We acknowledge that there may be some emissions increases as a result of this rulemaking. Over the past 25 years, domestic ethanol fuel production has steadily increased due to changing environmental regulation, Federal and State tax incentives, and market demand, including an increasing number of State ethanol mandates, the phase out of MBTE, and elevated crude oil prices. In order to meet current and future demand, new facilities may be constructed or existing facilities may need to be expanded. However, we do not expect many new facilities to be constructed (other than those already planned) in the short-term (
There are an estimated 114 facilities that currently exist in the U.S. that produce ethanol by natural fermentation as of March, 2007. Of these, an estimated 7 of the facilities are planning expansions. Eighty additional ethanol production facilities are currently under construction. Existing ethanol production capacity is estimated at 5,600 million gallons year (mgy). New construction and expansions will add an estimated 6,400 mgy to existing capacity. The estimated total capacity (inclusive of expansions and new constructions) will be about 12,000 mgy (12 billion gallons year (bgy)) once expansions and new constructions are completed.
Commenters expressed concern that this rule would result in emissions increases because (1) The rule increases the PSD major source threshold from 100 tpy to 250 tpy for the subject ethanol production facilities (new or existing facilities) in attainment areas; and (2) that, for new sources, fugitive emissions will no longer be included in calculations to determine whether a source is a major PSD source in attainment areas or to determine nonattainment NSR applicability. Section 2 of this response section discusses our consideration of the potential for emissions increases due to the increased threshold, section 3 discusses our consideration of the potential for emissions increases due to facilities no longer needing to count fugitives when determining whether they are a major source, and section 4 presents our overall conclusions.
Volatile organic compounds (VOC) emissions occur from the cooling system baghouses, dryers, CO
Estimates provided include estimates for emissions of nitrogen oxides that result from fuel combustion in the thermal oxidizers and dryers. The
Carbon monoxide (CO) emissions are also attributed to fuel combustion at the thermal oxidizers and dryers. As such, CO emissions were also included in their potential to emit estimates.
Emissions of particulate matter less than 10 microns (PM
Haul road emissions are generally dependent on the amount of vehicle miles traveled on the roads (more miles traveled equate to higher emissions). Grain fugitives are assumed to be controlled by a choked flow system, which reportedly is the typical control for fugitive particulate emissions.
Carbon monoxide and VOC emissions are typically the largest source of emissions from these facilities and are the likely pollutants that would trigger major PSD/NSR review.
Several commenters have provided that there are many ethanol production facilities that take on BACT controls in order to be permitted as “synthetic minor” sources or are subject to controls or PTE restrictions that may be similar to BACT controls because of other existing regulations (
Based on this rulemaking, existing facilities located in attainment areas would be required to maintain their existing permit limits and other permit requirements unless and until revised through a permitting procedure which, to be consistent with CAA section 110(a)(2)(C) and 40 CFR 51.160, must be shown not to cause or contribute to a violation of the NAAQS. In addition, any expansion would also have to comply with any applicable NSPS, NESHAP, or State regulation.
Most of the existing ethanol production facilities in attainment areas have current production capacities less than 110 mgy and would, therefore, likely be either synthetic minor or actual minor source facilities, with a few facilities likely being permitted as major PSD sources. Given a worst-case scenario, the maximum these facilities could emit as a result of a change or modification and solely by the threshold being increased to 250 tpy is 249 tpy (up to the major source threshold).
New facilities located in attainment areas would be subject to a 250 tpy major source applicability threshold when determining major source applicability. Therefore, these new facilities would be allowed to emit up to 249 tpy (and produce up to 250 mgy) VOC and/or CO as minor sources as a result of the major source threshold being increased from 100 tpy to 250 tpy.
Although other factors may influence the construction of new ethanol production facilities in the future, we do not expect many additional facilities to be constructed over the next 5 years as a result of this rule.
Over the past 25 years, domestic ethanol fuel production has steadily increased due to changing environmental regulation, Federal and State tax incentives, and market demand, including an increasing number of State ethanol mandates, the phase out of MBTE, and elevated crude oil prices. We assume, and commenters have supported that, under a 250 tpy threshold, there is incentive to construct more efficient facilities with larger capacities. (EPA-HQ-OAR-2006-0089-0086). Therefore, in the future, economies of scale will potentially drive the expansion and construction of facilities with capacities equal to or greater than 250 mgy with actual emissions being less than 250 tpy. Thus, under this scenario, production of ethanol would result in less emissions per gallon of ethanol produced today.
New facilities located in attainment areas would be subject to a 250 tpy major source applicability threshold and would no longer need to count fugitives when determining major source applicability. Therefore, these new facilities would be allowed to emit up to an additional 33 tpy (and produce up to 250 mgy) VOC and/or CO (assuming VOC and/or CO fugitives account for 13% of facility wide VOC and/or CO emissions) as minor sources as a result of this rulemaking.
As we noted previously, we do not expect many new facilities to be constructed over the next 5 years. However, provided that there is construction of more facilities over the next 5 years, such a facility would be able to emit 33 tpy more VOC and/or CO emissions (assuming 13% of 250 tpy are fugitive emissions no longer required to be included in the major source applicability calculations) than it would have prior to this rulemaking.
Of the estimated facilities located in ozone nonattainment areas, 4 of the facilities have reported capacities below 6 mgy. These types of facilities produce ethanol from waste beverages, waste beer, and/or cheese whey and more than likely produce ethanol secondary to other processes at the facility (
Existing facilities subject to a nonattainment NSR permit will need to continue to include their fugitive emissions, as permitted, in nonattainment areas. This is because existing permit limits and other permit requirements remain in effect and enforceable unless and until revised through a permitting procedure which, to be consistent with CAA section 110(a)(2)(C) and 40 CFR 51.160, must be shown not to cause or contribute to a violation of the NAAQS and to comply with all applicable requirements. When determining whether an emissions increase is significant, these sources would still be required to count their fugitives.
We believe that very few ethanol production facility constructions in nonattainment areas will occur in the near future and that future facilities (as with existing facilities) will likely be located near an applicable feedstock (such as corn). Currently, and in the near foreseeable future, corn is the primary feedstock used in ethanol production in this country and the bulk of the corn grown in this country is located in attainment areas, and transportation costs may influence decision makers to locate such plants close to the feedstock. In the future, where cellulosic materials will be used as a feedstock for ethanol production on a commercial scale, agricultural and other waste may be used. We believe that this rulemaking, which increases the PSD major source threshold to 250 tpy, will provide decision makers with additional incentives to locate these facilities in attainment areas.
However, if a new facility did locate in a nonattainment area to meet future demand for ethanol, it is assumed that it would be a 110 mgy facility that would have the potential to emit an additional 16 tpy of VOC and/or CO fugitive emissions.
It is important to note that most, if not all, ethanol fuel plants employ an active leak detection and repair (LDAR) program to minimize VOC emissions from tanks, valves, pumps and piping. (Docket No. EPA-HQ-OAR-2006-0089-0074). Fugitive particulate emissions from vehicular traffic are often controlled by a combination of paving and cleaning plant roads and other dust suppression methods. (Docket No. EPA-HQ-OAR-2006-0089-0074). Based on the assumption that there will be few, if any, facilities that will expand or be constructed in nonattainment areas in the future, and in light of the fugitive control measures that are employed at these facilities, we do not believe that this rulemaking will result in significant emissions increases in nonattainment areas.
As stated previously, we believe that a larger, more economically efficient plant that is able to produce more ethanol fuel could result in significantly more fuel production without a corresponding increase in energy use or pollutant emissions, thereby resulting in a net reduction of environmental impacts as compared to the greater number of smaller, less efficient ethanol fuel production facilities that would be needed to achieve the same level of production. Given the likelihood of larger capacity facilities being better able to reduce emissions per gallon of ethanol produced than a greater number of smaller facilities, it is more logical to increase the capacity at a larger facility than locating additional smaller capacity facilities in an area. Similarly, it is more logical to allow the construction of larger capacity facilities in an area than locating numerous smaller capacity facilities in an area.
In conclusion, the effect of this rule is limited given that other emissions requirements continue to apply and will be unaffected by this rulemaking. As we have noted in our discussion, VOC and/or CO emissions (and other increases in emissions for NO
However, even if there is an increased use of coal, these facilities will be subject to the same PSD major source limit requirements as facilities that use natural gas, and will continue to be subject to other regulations (State and Federal). We also acknowledge that the use of coal could result in increases in CO
One State commenter expressed that the proposed Option 1 would result in a negative impact on growth due to the projected increment consumption. They said that although some States could deal with this locally by making their regulations stricter than the Federal regulations, others are restricted because they have rules that limit them from having laws in their States that are stricter than the Federal rules.
A commenter representing State and local governments provided that even current minor sources—under the existing 100 tpy threshold, including fugitive emissions—are known to contribute significantly to potential violations of the NAAQS. They stated that permit data from STAPPA and ALAPCO members show that emissions from some ethanol fuel production facilities contribute to an area exceeding the 24-hour PM
Another commenter stated that EPA and North Dakota have not resolved the issue of sulfur dioxide PSD exceedances in Class I areas of North Dakota and Montana, and that if Option 1 is promulgated for ethanol plants, there is potential for an increase of more than double the allowable sulfur dioxide emissions from proposed and existing ethanol plants.
We also acknowledge that there are local and Regional concerns that this rule is contrary to the purposes of the PSD program. It is true that one purpose of the PSD program is to ensure that new sources do not cause or contribute to an area that is in attainment becoming a nonattainment area. However, we believe that, in part, this directive will continue to be addressed by a State's minor NSR permit program and various Federal, State and Local air quality requirements. Federal regulations that apply and will continue to apply to ethanol production facilities include numerous NSPS (
In addition to the currently available Reference Methods, EPA works with industry groups to develop their own test methods as an alternative to using existing EPA Reference Methods, provided that the alternative methods produce accurate results. One example of an alternative method by an industry is the method developed by the Corn Refiners Association for measuring VOC emissions from the wet corn milling industry. This method was developed by the wet corn milling industry specifically to measure VOC mass emissions from processes within their facilities. It is a systematic approach for developing a specific list of target organic compounds and determining the appropriate sampling procedure to collect those target compounds during subsequent VOC emissions testing. This method is currently available on EPA's Emission Measurement Center Web page (
Recently, the U.S. Court of Appeals for the D.C. Circuit ruled on our interpretation of a similar, but not identical term “controls” as used in section 172(e), and found that “NSR is a control.”
Nonetheless, this action does not in and of itself modify any requirements applicable to nonattainment areas. We believe the appropriate time to determine the applicability of and compliance with section 193 is when a control requirement in a nonattainment area is changed. For States that undertake a SIP revision, we will address the applicability of section 193 in our future actions to approve the SIP revisions. To the extent States can implement this approach consistent with their existing SIPs, the SIP requirements are not changing, and section 193 does not apply.
Similarly, we disagree with commenters that state that existing sources would simply be able to lift existing permit limits upon promulgation of this rule. These existing permit limits and other permit requirements remain in effect and enforceable unless and until revised through a permitting procedure which, to be consistent with CAA section 110(a)(2)(C) and 40 CFR 51.160, must be shown not to cause or contribute to a violation of the NAAQS and to comply with all applicable requirements.
As explained previously, section 116 of the CAA allows States to enforce their own emissions limitation and standards if such requirements are not less stringent than the approved SIP and Federal regulations under sections 111 and 112 of the CAA. However, nothing in section 116 prevents a State from revising its SIP to make its requirements less stringent, provided the new requirements are not less stringent than Federal regulations under sections 111 and 112 and meet all other applicable requirements. Nothing in this rule authorizes States to adopt changes that are less stringent than what is required under sections 111 and 112, and therefore section 116 does not limit a State's ability to revise its SIP to adopt these changes.
Finally, in response to comments, we have analyzed the impact of this rule and discussed our findings in section IV.E. of this preamble.
These changes will take effect in the Federal PSD and part 71 permit programs on July 2, 2007. This means that we will apply these rules in any area without a SIP-approved PSD program or title V program, for which we are the permitting authority, or for which we have delegated our authority to issues permits to a State, local, or tribal permitting authority.
We are establishing these requirements as minimum program elements of the PSD, nonattainment NSR, and title V programs. Notwithstanding this requirement, it may not be necessary for a State, local or tribal authority to revise its SIP or title V programs to begin to implement these changes. Some State, local or tribal authorities may be able to adopt these changes through a change in interpretation of the term “chemical process plant” without the need to revise the SIP or the title V program.
For any State, local or tribal agency that can implement the changes without revising its approved NSR or title V program, the changes will become effective when the permitting authority publicly announces that it has accepted these changes by interpretation. Although we find that no SIP or title V program revisions may be necessary in certain areas that are able to adopt these changes by interpretation, we encourage such State, local and tribal authorities in such areas to make such SIP or title V
For areas that revise their SIPs or title V programs to adopt these changes, the changes are not effective in such area until we approve the SIP revision or title V program as meeting all applicable requirements. Revisions to title V programs to reflect the changes in this rule should be submitted to EPA for approval within 3 years. State, local, or tribal authorities may adopt or maintain NSR program elements that have the effect of making their regulations more stringent than these rules.
Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), the Agency must determine whether the regulatory action is “significant” and therefore subject to Office of Management and Budget (OMB) review and the requirements of the Executive Order. Pursuant to the terms of Executive Order 12866, it has been determined that this rule is a “significant regulatory action” because it raises policy issues arising from the President's priorities. Also, this rule is not “economically significant.”
Accordingly, the EPA submitted this action to OMB for review under Executive Order 12866 and any changes made in response to OMB's recommendations have been documented in the docket for this action.
This action does not impose any new information collection burden as the burden imposed by this rule has already been taken into account in previously-approved information collection requirement actions under both the NSR and title V programs. The OMB has previously approved the information collection requirements contained in the existing 40 CFR parts 51 and 52 regulations under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501
It is necessary that certain records and reports be collected by a State or local agency (or the EPA Administrator in non-delegated areas), for example, to: (1) Confirm the compliance status of stationary sources, including identifying any stationary sources subject/not subject to the rule, and (2) ensuring that the stationary source control requirements are being achieved. The information is then used by the EPA or State enforcement personnel to ensure that the subject sources are applying the appropriate control technology and that the control requirements are being properly operated and maintained on a continuous basis. Based on the reported information, the State, local, or tribal agency can decide which plants, records, or processes should be inspected. Such information collection requirements for sources and States are currently reflected in the approved ICR's referenced above for the NSR and title V programs.
Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, disclose, or provide information to or for a Federal agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information; processing and maintaining information; disclosing and providing information; adjusting the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transmit or otherwise disclose the information.
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 numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9.
The Regulatory Flexibility Analysis (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the Agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of this action on small entities, a small entity is defined as: (1) A small business that is a small industrial entity as defined in the U.S. Small Business Administration (SBA) size standards (see 13 CFR 121.201); (2) a small governmental jurisdiction that is a government of a city, county, town, school district, or special district with a population of less than 50,000; or (3) a small organization that is any not-for-profit enterprise that is independently owned and operated and is not dominant in its field. There are an estimated 114 ethanol production facilities in the U.S. and an estimated 70 more under construction with several more being planned. Most of these facilities use corn as the primary feedstock. It is estimated that farmer-owned cooperatives make up nearly half of the ethanol plants in the U.S. with an additional percentage of facilities under construction that are locally-controlled. (
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 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,
The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of EPA regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements. This rule contains no Federal mandates (under the regulatory provisions of Title II of the UMRA) for State, local, or tribal governments or the private sector.
The EPA has determined that this rule does not contain a Federal mandate that may result in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, or the private sector in any one year. Thus, this rule is not subject to the requirements of sections 202 and 205 of the UMRA.
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(b) 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. Under section 6(c) of Executive Order 13132, EPA 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.
EPA has concluded that this final rule will not have federalism implications. It will not impose substantial direct compliance costs on State or local governments, nor will it preempt State law. Thus, the requirements of sections 6(b) and 6(c) of the Executive Order do not apply to this rule.
In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and State and local governments, the EPA specifically solicited comment on the proposed rule from State and local officials.
Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (65 FR 13175, November 9, 2000), requires EPA to develop an accountable process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.” This final rule does not have tribal implications, as specified in Executive Order 13175, as there are no tribal authorities currently issuing PSD, major nonattainment NSR, title V permits, or synthetic minor limits to ethanol plant which process carbohydrate feedstocks. Thus, Executive Order 13175 does not apply to this rule.
Although Executive Order 13175 does not apply to this final rule, EPA specifically solicited comment on the proposed rule from tribal officials.
Executive Order 13045, entitled “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, the Agency must 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.
EPA interprets Executive Order 13045 as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5-501 of the Executive Order has the potential to influence the regulation. This final rule is not subject to Executive Order 13045 because it is not “economically significant” as defined in Executive Order 12866 and because the Agency does not have reason to believe the environmental health or safety risks addressed by this action present a disproportionate risk to children.
These final amendments do not constitute a “significant energy action” as defined in Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001), because they will not likely have a significant adverse effect on the supply, distribution, or use of energy.
As noted in the proposed rule, section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law 104-113, 12(d) (15 U.S.C. 272 note), directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical.
Voluntary consensus standards are technical standards (for example, materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. The NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards.
These final rule amendments do not involve technical standards. Therefore, EPA did not consider the use of any voluntary consensus standards.
Executive Order 12898 (59 FR 7629 (Feb. 16, 1994)) establishes Federal executive policy on environmental justice. Its main provision directs Federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, any disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States.
The EPA has determined that this final rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations. The reason for EPA's determination is because the final rule does not affect the level of protection provided to human health or the environment as it does not change a permitting authority's obligation to maintain the NAAQS, even though changes are being made to the PSD, major nonattainment NSR, and title V programs.
The Congressional Review Act, 5 U.S.C. 801
Under section 307(b)(1) of the Act, judicial review of this final action is available by filing of a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit by July 2, 2007. Any such judicial review is limited to only those objections that are raised with reasonable specificity in timely comments. Under section 307(b)(2) of the Act, the requirements of this final action may not be challenged later in civil or criminal proceedings brought by us to enforce these requirements.
Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Nitrogen dioxide, Ozone, Particulate matter, Reporting and recordkeeping requirements, Sulfur oxides.
Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements.
23 U.S.C. 101; 42 U.S.C. 7401-7671q.
(a) * * *
(1) * * *
(iv) * * *
(C) * * *
(
(4) * * *
(xx) Chemical process plants—The term chemical processing plant shall not include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 or 312140;
(b) * * *
(1)(i) * * *
(
(iii) * * *
(
(i) * * *
(1) * * *
(ii) * * *
(
II. * * *
A. * * *
4. * * *
(iii) * * *
(
F. * * *
(20) Chemical process plants—The term chemical processing plant shall not include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 or 312140;
42 U.S.C. 7401,
(b) * * *
(1)(i) * * *
(
(iii) * * *
(
(i) * * *
(1) * * *
(vii) * * *
(
42 U.S.C 7401,
(2) * * *
(xx) Chemical process plants—The term chemical processing plant shall not include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 or 312140;
42 U.S.C 7401,
(2) * * *
(xx) Chemical process plants—The term chemical processing plant shall not include ethanol production facilities that produce ethanol by natural fermentation included in NAICS codes 325193 or 312140;
Office of the Assistant Secretary for Public and Indian Housing, HUD.
Proposed rule.
This proposed rule would revise the low-income housing tax credit (LIHTC) rent provisions of HUD's final Project-Based Voucher (PBV) program rule, which was published on October 13, 2005, and took effect on November 14, 2005. The October 13, 2005, final rule capped the PBV rents at the LIHTC rent in buildings with LIHTC units, even in cases where HUD formerly permitted such units to receive the higher rents permitted under the PBV program. After giving the issue further consideration, HUD now proposes to revert to the regulations that address this specific issue and were in effect prior to issuance of the October 13, 2005, final rule. The regulations in effect prior to the October 13, 2005, final rule did not necessarily require public housing agencies (PHAs) to cap section 8 maximum rents at the tax credit rent. PHAs may not enter into assistance contracts until HUD or an independent entity approved by HUD has conducted the required subsidy layering review and determined that the assistance is in accordance with HUD requirements.
Interested persons are invited to submit comments regarding this proposed rule to the Regulations Division, Office of General Counsel, Department of Housing and Urban Development, 451 Seventh Street, SW., Room 10276, Washington, DC 20410-0500. Interested persons may also submit comments electronically through the federal electronic rulemaking portal at:
Facsimile (FAX) comments are not acceptable. All communications must refer to the docket number and title. All comments and communications submitted will be available, without revision, for public inspection and copying between 8 a.m. and 5 p.m. weekdays at the above address. Due to security measures at the HUD Headquarters building, an advance appointment to review the public comments must be scheduled by calling the Regulations Division at (202) 708-3055 (this is not a toll-free number). Copies of the public comments submitted electronically are also available for inspection and downloading at
David Vargas, Director, Office of Voucher Programs, Department of Housing and Urban Development, 451 Seventh Street, SW., Room 4210, Washington, DC 20410; telephone (202) 708-2815 (this is not a toll-free number). Persons with hearing or speech impairments may access these numbers via TTY by calling the Federal Information Relay Service at (800) 877-8339.
On October 13, 2005, HUD published a final rule that comprehensively revised the regulations for HUD's PBV program, found in 24 CFR part 983. (See 70 FR 59892
Prior to the November 14, 2005, effective date of the October 13, 2005, final rule, PBV units with LIHTCs located outside of qualified census tracts could have rents set at the higher of 110 percent of the area fair market rent (FMR) or the LIHTC rent charged for comparable units in the same building that receive the tax credit and no other assistance. In other words, in areas where the tax credit rent was higher (
The October 13, 2005, final rule changed this practice, in place for several years, under section 8(o)(13)(H) of the 1937 Act (42 U.S.C. 1437f(o)(13)(H)). The October 13, 2005, final rule provided, under § 983.304(c)(1)(v) and § 983.304(c)(2), that rent for units with tax credit may not exceed the tax credit rent in those cases where formerly, if the FMR-based rent were higher, that higher rent could be used.
Since the publication of the October 13, 2005, final rule, HUD received additional comments from PHAs and housing industry representatives expressing concern that the policy change regarding LIHTC units would impede rather than promote HUD's goal of increasing and preserving affordable housing, and requesting that HUD return to its original policy and position regarding LIHTC units. Some PHA and housing industry representatives also advised that the policy change may make many projects relying on LIHTCs non-viable because it could inhibit the financing of new projects by reducing the potential project rent, and thereby reduce the supply of low-income housing using LIHTCs.
After further consideration of this issue, HUD has determined that the policy change in the October 13, 2005, final rule concerning LIHTCs may not further HUD's mission to increase affordable housing as effectively as contemplated. While the change would cap federal subsidies, HUD hears the concerns that the change may inhibit the financing of new projects and possibly reduce, not increase, the supply of low-income housing using LIHTCs. HUD believes that concerns about excess federal subsidy may be adequately addressed using subsidy layering analysis. In this regard, HUD has determined that it would benefit by further public input on this issue.
This rule therefore proposes to reinstate the former policy in § 983.304(c) with respect to LIHTCs. In response to the public feedback received on the October 13, 2005, final rule, HUD has decided not to enforce § 983.304(c) as revised by the October 13, 2005, final rule. Instead, HUD will await further comment on this issue, as provided by this proposed rule, and will implement the final rule that results from this proposed rulemaking. In the meantime, owners who received a written notification of owner selection subsequent to the effective date of the final rule (November 14, 2005) and have entered into a Housing Assistance Payment (HAP) contract may request a redetermination of initial rents in accordance with § 983.301 of the final rule, if the initial rents were capped under the tax credit rent provision at § 983.304(c)(1)(v).
For the reasons provided in Section I of this preamble, this proposed rule would remove the requirement added to § 983.304(c) by the October 13, 2005, final rule that PHAs in qualified census tracts have their rents limited by the tax credit rent. Therefore, PHAs would not
The Office of Management and Budget (OMB) reviewed this proposed rule under Executive Order 12866 (entitled “Regulatory Planning and Review”). OMB determined that this rule is a “significant regulatory action,” as defined in section 3(f) of the Executive Order (although not economically significant, as provided in section 3(f)(1) of the Executive Order). The docket file is available for public inspection between the hours of 8 a.m. and 5 p.m. in the Regulations Division, Office of General Counsel, Department of Housing and Urban Development, 451 Seventh Street, SW., Room 10276, Washington, DC 20410-0500. Due to security measures at the HUD Headquarters building, an advance appointment to review the public comments must be scheduled by calling the Regulations Division at (202) 708-3055 (this is not a toll-free number).
The Regulatory Flexibility Act (5 U.S.C. 601
Notwithstanding HUD's determination that this rule will not have a significant economic impact on a substantial number of small entities, HUD specifically invites comments regarding any less burdensome alternatives to this rule that will meet HUD's objectives as described by this preamble.
This interim rule involves establishment of external administrative or fiscal requirements related to a rate or cost determination, which does not constitute a development decision affecting the physical condition of specific project areas or building sites. Accordingly, under 24 CFR 50.19(c)(6), this interim rule is categorically excluded from environmental review under the National Environmental Policy Act of 1969 (42 U.S.C. 4321
Executive Order 13132 (entitled “Federalism”) prohibits, to the extent practicable and permitted by law, an agency from promulgating a regulation that has federalism implications and either imposes substantial direct compliance costs on state and local governments and is not required by statute, or preempts state law, unless the relevant requirements of section 6 of the Executive Order are met. This proposed rule does not have federalism implications and does not impose substantial direct compliance costs on state and local governments or preempt state law within the meaning of the Executive Order.
Title II of the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4; approved March 22, 1995) (UMRA) establishes requirements for federal agencies to assess the effects of their regulatory actions on state, local, and tribal governments, and on the private sector. This proposed rule does not impose any federal mandates on any state, local, or tribal governments, or on the private sector, within the meaning of the UMRA.
The Catalog of Federal Domestic Assistance number applicable to the program affected by this proposed rule is 14.871.
Grant programs—housing and community development, Housing, Low- and moderate-income housing, Rent subsidies, Reporting and recordkeeping requirements.
For the reasons stated in the preamble, HUD proposes to amend 24 CFR part 983 to read as follows:
1. The authority citation for part 983 continues to read as follows:
42 U.S.C. 1437f and 3535(d).
2. Revise § 983.304(c) to read as follows:
(c)
(i) An insured or non-insured Section 236 project;
(ii) A formerly insured or non-insured Section 236 project that continues to receive Interest Reduction Payment following a decoupling action;
(iii) A Section 221(d)(3) below market interest rate (BMIR) project;
(iv) A Section 515 project of the Rural Housing Service;
(v) Any other type of federally subsidized project specified by HUD.
(2) The rent to owner may not exceed the subsidized rent (basic rent) as determined in accordance with requirements for the applicable federal program listed in paragraph (c)(1) of this section.
Copyright Royalty Board, Library of Congress.
Final rule and order.
The Copyright Royalty Judges, on behalf of the Copyright Royalty Board of the Library of Congress, are announcing their final determination of the rates and terms for two statutory licenses, permitting certain digital performances of sound recordings and the making of ephemeral recordings, for the period beginning January 1, 2006, and ending on December 31, 2010.
The final determination is also posted on the Copyright Royalty Board Web site at
Richard Strasser, Senior Attorney, or Gina Giuffreda, Attorney Advisor.
This is a rate determination proceeding convened under 17 U.S.C. 803(b)
The parties to this proceeding are: (i) Digital Media Association and certain of its member companies that participated in this proceeding, namely: America Online, Inc. (“AOL”), Yahoo!, Inc. (“Yahoo!”), Microsoft, Inc. (“Microsoft”), and Live365, Inc. (“Live365”) (collectively referred to as “DiMA”); (ii) “Radio Broadcasters” (this designation was adopted by the parties): namely, Bonneville International Corp., Clear Channel Communications, Inc., National Religious Broadcasters Music License Committee (“NRBMLC”), Susquehanna Radio Corp.; (iii) SBR Creative Media, Inc. (“SBR”) and the “Small Commercial Webcasters” (this designation was adopted by the parties): namely, AccuRadio, LLC, Digitally Imported, Inc., Radioio.com LLC, Discombobulated, LLC, 3WK, LLC, Radio Paradise, Inc.; (iv) National Public Radio, Inc. (“NPR”), Corporation for Public Broadcasting-Qualified Stations (“CPB”), National Religious Broadcasters Noncommercial Music License Committee (“NRBNMLC”), Collegiate Broadcasters, Inc. (“CBI”), Intercollegiate Broadcasting System, Inc., (“IBS”), and Harvard Radio Broadcasting, Inc. (“WHRB”); (v) Royalty Logic, Inc. (“RLI”); and (vi) SoundExchange, Inc. (“SoundExchange”).
DiMA, Radio Broadcasters, Small Commercial Webcasters, SBR, NPR, CPB, NRBNMLC, CBI, IBS and WHRB are sometimes referred to collectively as “the Services.” The Services are Internet webcasters or broadcast radio simulcasters that each employ a technology known as streaming, but comprise a range of different business models and music programming. DiMA and certain of its member companies that participated in the proceeding (namely: AOL, Yahoo!, Microsoft and Live365), Radio Broadcasters, SBR and Small Commercial Webcasters are sometimes referred to collectively as “Commercial Webcasters.” NPR, CPB, NRBNMLC, CBI, IBS and WHRB are sometimes referred to collectively as “Noncommercial Webcasters.”
A notice calling for the filing of Petitions to Participate in this proceeding to set the rates and terms for the period beginning January 1, 2006, and ending on December 31, 2010, was published February 16, 2005. 70 FR 7970. The Petitions were due by March 18, 2005. Forty-two petitions were filed. Following an order to file a Notice of Intention to Submit Written Direct Statements, the participants were reduced to the following twenty eight: SBR; NPR; NPR Member Stations; CPB; CBI; SoundExchange; RLI; IBS; WHRB; Digital Media Association; AOL; Live365; Microsoft; Yahoo!; AccuRadio LLC; Discombobulated LLC; Digitally Imported, Inc.; Radioio.com LLC; Radio Paradise, Inc.; Educational Media Foundation; NRBNMLC; Bonneville International Corp.; Clear Channel Communications, Inc.; CBS Radio, Inc.; NRBMLC; Salem Communications Corp.; Susquehanna Radio Corp.; and Beethoven.com LLC.
Following an unsuccessful negotiation period, the Written Direct Statements were due October 31, 2005. All of the above filed plus the additional following: Mvyradio.com LLC; 3WK; XM Satellite Radio, Inc.; Sirius Satellite, Inc.; Infinity Broadcasting Corp.
The participants conducted discovery and then began live testimony. By the time testimony began, the participants reduced to the following: SBR; NPR; NPR Member Stations; CPB; CBI; SoundExchange; RLI; IBS; WHRB; Digital Media Association; AOL; Yahoo!; AccuRadio LLC; Discombobulated LLC; Digitally Imported, Inc.; Mvyradio.com LLC; Radioio.com LLC; Radio Paradise, Inc.; 3WK LLC; Educational Media Foundation; NRBNMLC; Bonneville International Corp.; Clear Channel Communications, Inc.; NRBMLC; and Susquehanna Radio Corp.
Testimony was taken from May 1, 2005, through August 7, 2006. SoundExchange presented the testimony of the following 14 witnesses: (1) John Simson, SoundExchange, executive director; (2) Barrie Kessler, SoundExchange, chief operating officer; (3) James Griffin, One House LLC, chief executive officer; (4) Erik Brynjolfsson, MIT Sloan School of Management, professor of management and director of Center for eBusiness at MIT; (5) Michael Pelcovits, MiCRA, economic consultant; (6) Mark Eisenberg, SONY BMG, senior vice president of business and legal affairs; (7) Lawrence Kenswil, Universal eLabs, a division of Universal Music Group, president; (8) Michael Kushner, Atlantic Records Group, business and legal affairs; (9) Stephen Bryan, Warner Music Group, vice president of strategic planning and business development; (10) Harold Bradley, American Federation of Musicians of United States and Canada, vice president; (11) Jonatha Brooke, songwriter and performer, owner of Bad Dog Records; (12) Cathy Fink, songwriter and performer; (13) Bruce Iglauer, Alligator
Royalty Logic, Inc. presented the testimony of Ronald A. Gertz, president.
The Services presented the testimony of the following 24 witnesses: Digital Media Association and its Member Companies: (1) Adam B. Jaffe, Brandeis University, professor in economics; (2) Christine Winston, America Online, executive director of programming strategy and planning; (3) David Porter, Live365, general manager of business development; (4) Jonathan Potter, DiMA, executive director; (5) N. Mark Lam, Live365, chairman and chief executive officer; (6) Robert D. Roback, Yahoo! Music, general manager; (7) J. Donald Fancher, Deloitte and Touche Financial Advisory Services LLP; (8) Jay Frank, Yahoo!, programming and label relations; (9) Fred Silber, Microsoft, business development manager for MSN; (10) Eric Ronning, Ronning Lipset Radio; (11) Jack Isquith, American Online Music, executive director Music Industry Relations; (12) Karyn Ulman, Music Reports, Inc.;
Radio Broadcasters: (13) Dan Halyburton, Susquehanna Radio, research, engineering and programming; (14) Roger Coryell, San Francisco Bonneville Radio Group, director strategic marketing and Internet; (15) Russell Hauth, National Radio Broadcasters Music Licensing Committee, executive director; (16) Brian Parsons, Clear Channel Radio, vice president of technology;
Small Commercial Webcasters: (17) Kurt Hanson, AccuRadio, president and RAIN newsletter, publisher;
National Public Radio: (18) Kenneth Stern, NPR, chief executive officer;
Intercollegiate Broadcasting System, Inc. and Harvard Radio Broadcasting Co., Inc.: (19) Frederick J. Kass, Jr., IBS, chief operating officer; (20) Michael Papish, HRBC, treasurer and Media Unbound, president;
Collegiate Broadcasters, Inc.: (21) William Robedee, CBI, past chair and KTRU, Rice University, manager; (22) Joel R. Willer, KXUL, University of Louisiana, Monroe, faculty advisor;
National Religious Broadcasters Noncommercial Music Licensing Committee: (23) Eric Johnson, NRBNMLC, board member and CDR Radio Network, music director; and
SBR Creative Media, Inc.: (24) David Rahn, president.
The participants filed Written Rebuttal Statements on September 29, 2006. Discovery was then conducted on the rebuttal evidence. Rebuttal testimony was taken from November 6 through November 30, 2006.
SoundExchange presented the testimony of the following nine witnesses: (1) Barrie Kessler, SoundExchange, chief operating officer; (2) James Griffin, One House LLC, chief executive officer; (3) Erik Brynjolfsson, MIT Sloan School of Management, professor of management and director of Center for eBusiness at MIT; (4) Michael Pelcovits, MiCRA, economic consultant; (5) Mark Eisenberg, SONY BMG, senior vice president of business and legal affairs; (6) Thomas Lee, American Federation of Musicians, president; (7) Simon Wheeler, Association of Independent Music, chair of New Media Committee; (8) Charles Ciongoli, Universal Music Group, North American, executive vice president and chief financial officer; and (9) Tom Rowland, Universal Music Enterprises, senior vice president, film and television music;
Royalty Logic, Inc. presented the testimony of the following two witnesses: (1) Ronald A. Gertz, president; and (2) Peter Paterno, entertainment attorney;
The Services presented the testimony of the following 16 witnesses:
Digital Media Association and its Member Companies: (1) Adam B. Jaffe, Brandeis University, professor in economics; (2) Christine Winston, America Online, executive director of programming strategy and planning; (3) N. Mark Lam, Live365, chairman and chief executive officer; (4) Robert D. Roback, Yahoo! Music, general manager; (5) J. Donald Fancher, Deloitte and Touche Financial Advisory Services LLP; (6) Jay Frank, Yahoo!, programming and label relations; (7) Jack Isquith, American Online Music, executive director Music Industry Relations; (8) Roger James Nebel, FTI Consulting;
Radio Broadcasters: (9) Keith Meehan, Radio Music Licensing Committee, executive director; (10) Eugene Levin, Radio Music Licensing Committee, controller; (11) Brian Parsons, Clear Channel Radio, vice president of technology; (12) Adam B. Jaffe, Brandeis University, professor of economics;
National Public Radio: (13) Adam B. Jaffe, Brandeis University, professor of economics;
Intercollegiate Broadcasting System, Inc. and Harvard Radio Broadcasting Co., Inc.: (14) Jerome Picard, economics professor (ret.); (15) Michael Papish, HRBC, treasurer; and
National Religious Broadcasters Noncommercial Music Licensing Committee: (16) Eric Johnson, member of board.
At the close of all the evidence, the record was closed. In addition to the written direct statements and written rebuttal statements, the Copyright Royalty Judges heard 48 days of testimony, which filled 13,288 pages of transcript, and 192 exhibits were admitted. The docket contains 475 entries of pleadings, motions and orders.
After the evidentiary phase of the proceeding, the participants were ordered to file Proposed Findings of Fact and Conclusions of Law on December 12, 2006, and Responses to those proposals on December 15, 2006. The parties were also ordered to submit Stipulated Terms on December 15, 2006, but none have been filed. Closing arguments were heard on December 21, 2006. Then the matter was submitted to the Copyright Royalty Judges for a Determination.
On March 2, 2007, the Copyright Royalty Judges issued the initial Determination of Rates and Terms. Pursuant to 17 U.S.C. 803(c)(2) and 37 CFR Part 353, the parties filed Motions for Rehearing.
Section 102 of the Copyright Act of 1976 (the “Copyright Act”) identifies various categories of works that are eligible for copyright protection. 17 U.S.C. 102. These include “musical works” and “sound recordings.”
Under the 1976 Copyright Act, a copyright owner receives a bundle of exclusive rights set forth in section 106. 17 U.S.C. 106. Among them is the right to make or authorize the performance to the public of a copyrighted work. The performance right is granted to all categories of copyrighted works with one exception: Sound recordings. Thus, while the owner of a musical work enjoys the performance right, the owner of a sound recording does not.
In 1995, Congress enacted the Digital Performance Right in Sound Recordings Act (“DPRA”), Public Law 104-39, 109 Stat. 336 (1995), which added a new section 106(6) to the Copyright Act. That provision grants copyright owners of sound recordings a limited performance right to make or authorize the performance of their works “by means of a digital audio transmission.” 17 U.S.C. 106(6). Often referred to as the “digital performance right,” the right was further limited by the creation of a statutory license for certain nonexempt, noninteractive subscription services and preexisting satellite digital audio radio services. 17 U.S.C. 114. The statutory license permits these services, upon compliance with certain statutory conditions, to make those transmissions without obtaining consent from, or having to negotiate license fees with, copyright owners of the sound recordings they perform.
Absent agreement among all the interested parties, the Librarian of Congress was directed to convene a Copyright Arbitration Royalty Panel (“CARP”) to recommend royalty rates and terms. Congress directed the CARP to set a royalty rate for the subscription services' statutory license that achieves the policy objectives in section 801(b)(1) of the Copyright Act.
Under the DPRA, copyright owners must allocate one-half of the statutory licensing royalties that they receive from the subscription services to recording artists. Forty-five percent of these royalties must be allocated to featured artists; 2
The new statutory license for digital audio transmission of sound recordings was expanded in the Digital Millennium Copyright Act of 1998 (“DMCA”), Public Law 105-304, 112 Stat. 2860 (1998). It provided that certain digital transmissions and retransmissions, typically referred to as webcasting, are subject to the section 106(6) digital performance right and that webcasters who transmit/retransmit sound recordings on an interactive basis, as defined in section 114(j), must obtain the consent of, and negotiate fees with, individual owners of those recordings. However, webcasting would be eligible for statutory licensing when done on a
Congress adopted the DPRA voluntary negotiation and arbitration procedures for the DMCA webcaster performance license. 17 U.S.C. 114(e), (f). However, it changed the statutory standard for determining rates and terms. The new standard is to determine what “most clearly represent the rates and terms that would have been negotiated in the marketplace between a willing buyer and a willing seller.” 17 U.S.C. 114(f)(2)(B).
Congress also recognized that webcasters who avail themselves of the section 114 license may need to make one or more temporary or “ephemeral” copies of a sound recording in order to facilitate the transmission of that recording. Accordingly, Congress created a new statutory license in section 112(e) for such copies and extended that license to services that transmit sound recordings to certain business establishments under the section 114(d)(1)(c)(iv) exemption created by the DPRA. Congress retained the DPRA voluntary negotiation and arbitration procedures for the section 112 ephemeral license. 17 U.S.C. 112(e)(2), (3). Congress again applied the willing buyer/willing seller standard applicable to the section 114 webcaster performance license. 17 U.S.C. 112(e)(4). The webcasting and
The two DMCA licenses were the subject of one prior proceeding. Determination of Reasonable Rates and Terms for the Digital Performance of Sound Recordings and Ephemeral Recordings (Final Rule), 67 FR 45240 (July 8, 2002) (codified at 37 CFR part 261) (“Webcaster I”). After a recommendation from a CARP, the Librarian applied the statutory standard to determine rates and terms. Many of the parties in this proceeding participated in that prior proceeding.
Congress enacted a new system to administer copyright royalties with the Copyright Royalty and Distribution Reform Act of 2004 (the “Reform Act”), Public Law 108-419, 118 Stat. 2341. The Copyright Royalty Judges were established to perform the functions previously served by the Copyright Royalty Tribunal and the Librarian of Congress. They were appointed January 9, 2006, and took over this proceeding.
The criteria for setting rates and terms for the section 114 webcaster performance license are enunciated under 17 U.S.C. 114(f)(2)(B), which provides in pertinent part:
* * * Such rates and terms shall distinguish among the different types of eligible nonsubscription transmission services then in operation and shall include a minimum fee for each such type of service, such differences to be based on criteria including, but not limited to, the quantity and nature of the use of sound recordings and the degree to which use of the service may substitute for or may promote the purchase of phonorecords by consumers. In establishing rates and terms for transmissions by eligible nonsubscription services and new subscription services, the Copyright Royalty Judges shall establish rates and terms that most clearly represent the rates and terms that would have been negotiated in the marketplace between a willing buyer and a willing seller. In determining such rates and terms, the Copyright Royalty Judges shall base [their] decision on economic, competitive and programming information presented by the parties, including—
(i) whether use of the service may substitute for or may promote the sales of phonorecords or otherwise may interfere with or may enhance the sound recording copyright owner's other streams of revenue from its sound recordings; and
(ii) the relative roles of the copyright owner and the transmitting entity in the copyrighted work and the service made available to the public with respect to relative creative contribution, technological contribution, capital investment, cost, and risk.
The statute further directs the Judges to set “a minimum fee for each such type of service” and grants the Judges discretion to consider the rates and terms for “comparable types of digital audio transmission services and comparable circumstances under voluntary license agreements” negotiated under the voluntary negotiation provisions of the statute.
Webcaster I clarified the relationship of the statutory factors to the willing buyer/willing seller standard. The standard requires a determination of the rates that a willing buyer and willing seller would agree upon in the marketplace. In making this determination, the two factors in section 114(f)(2)(B)(i) and (ii) must be considered, but neither factor defines the standard. They do not constitute additional standards, nor should they be used to adjust the rates determined by the willing buyer/willing seller standard. The statutory factors are merely to be considered, along with other relevant factors, to determine the rates under the willing buyer/willing seller standard. Webcaster I; In re Rate Setting for Digital Performance Right in Sound Recordings and Ephemeral Recordings, No. 2000-9 CARP DTRA 1 & 2 (“Webcaster I Carp Report”).
The parties agree that the directive to set rates and terms that “would have been negotiated” in the marketplace between a willing buyer and a willing seller reflects Congressional intent for the Judges to attempt to replicate rates and terms that “would have been negotiated” in a hypothetical marketplace. Webcaster I CARP Report at 21. The “buyers” in this hypothetical marketplace are the Services (and other similar services) and this marketplace is one in which no statutory license exists.
As noted, the statute directs us to “establish rates and terms that
The criteria for setting rates and terms for the section 112 ephemeral license are enunciated under 17 U.S.C. 112(e)(4), which provides in pertinent part:
The Copyright Royalty Judges shall establish rates that most clearly represent the fees that would have been negotiated in the marketplace between a willing buyer and a willing seller. In determining such rates and terms, the Copyright Royalty Judges shall base their decision on economic, competitive, and programming information presented by the parties, including—
(A) whether use of the service may substitute for or may promote the sales of phonorecords or otherwise interferes with or enhances the copyright owner's traditional streams of revenue; and
(B) the relative roles of the copyright owner and the transmitting organization in the copyrighted work and the service made available to the public with respect to relative creative contribution, technological contribution, capital investment, cost, and risk.
Based on the applicable law and relevant evidence received in this proceeding, the Copyright Royalty Judges must determine rates for two licenses, the section 114 webcaster performance license and the section 112 ephemeral reproduction license. The Copyright Act requires that the Copyright Royalty Judges establish rates for each of these two licenses that most clearly represent those “that would have been negotiated in the marketplace between a willing buyer and a willing seller” and directs the Copyright Royalty Judges to set a minimum fee for each license. In the case of both licenses, the Copyright Act requires the Copyright Royalty Judges to take into account evidence presented on such factors as (1) whether the use of the webcasting services may substitute for or promote the sale of phonorecords and (2) whether the copyright owner or the service provider make relatively larger contributions to the service ultimately provided to the consuming public with respect to creativity, technology, capital investment, cost and risk. 17 U.S.C. 114(f)(2)(B) and 17 U.S.C. 112 (e)(4).
Having carefully considered the relevant law and the evidence received in this proceeding, the Copyright Royalty Judges determine that the appropriate section 114 performance license rate is a per performance usage rate for Commercial Webcasters and an annual flat per-station rate for Noncommercial Webcasters for use up to a specified cap coupled with a per performance rate for use above the cap, while the appropriate section 112 reproduction license rate is deemed to be included in the applicable respective section 114 license rates.
The applicable rate structure is the starting point for the Copyright Royalty Judges' determination.
The contending parties present several alternative rate structures for Commercial Webcasters. In its final revised rate proposal, SoundExchange argues in favor of a monthly fee equal to the greater of: 30% of gross revenues or a performance rate beginning at $.0008 per performance in 2006 and increasing annually to $.0019 by 2010.
By contrast, DiMA on behalf of certain large commercial webcasters, proposes a fee structure under which webcasters could elect a fee equal to either $.00025 per performance or $.0038 per Aggregate Tuning Hour (“ATH”) or 5.5% of revenue directly associated with the streaming service. However, DiMA applies only its per performance usage rate to “bundled services” situations where the bundle price to the consumer is not allocated as between the individual component parts of the bundle. DiMA PFF at ¶¶ 35-38.
Smaller commercial webcasters present varying proposals. SBR Creative Media, Inc., a privately owned commercial webcaster, proposes a fee structure under which webcasters can elect a fee equal to either a use metric of $.0033 per Aggregate Tuning Hour (“ATH”) or 4% of gross revenue. SBR Creative Media PFF at ¶ 19. The self-styled Small Commercial Webcasters,
Radio Broadcasters propose an annual flat fee
In short, among the parties on both sides who have proposed rates covering Commercial Webcasters, only Small Commercial Webcasters propose a fee structure based solely on revenue. However, in making their proposal, this group of five webcasters clearly is unconcerned with the actual structure of the fee, except to the extent that a revenue-based fee structure especially one in which the percent of revenue fee is a single digit number (i.e., 5%)—can protect them against the possibility that their costs would ever exceed their revenues.
While each of the remaining contending parties—SoundExchange, DiMA, Radio Broadcasters and SBR Creative Media, Inc.—proposes a fee structure for Commercial Webcasters that contains revenue-based elements as well as either usage elements or a usage alternative, from the evidence of record, the Copyright Royalty Judges conclude that numerous factors weigh in favor of a per-performance usage fee structure for Commercial Webcasters.
First, as aptly stated by Dr. Adam Jaffe, revenue merely serves as “a proxy” for what “we really should be valuing, which is performances.” Jaffe, WDT Section N, Designated Testimony (Jaffe WDT in Webcaster I at 22). By contrast, a per-performance metric “is directly tied to the nature of the right being licensed, unlike other bases such as revenue * * * of the licensee.”
Second, percentage-of-revenue models present measurement difficulties because identifying the relevant webcaster revenues can be complex, such as where the webcaster offers features unrelated to music. Webcaster I noted this particular difficulty. 67 FR 45249 (July 8, 2002). Mixed format webcasters/simulcasters continue to make up a significant part of the commercial webcasting market and, in a number of cases, generate the more significant portion of their revenues from non-music programming. RBX1; RBX7; RBX20; 7/27/06 Tr. 283:7-285:12 (Hauth). Clearly, questions surrounding the proper allocation of revenues related to music use in such instances present greater complexity than a straightforward use of a usage-based approach.
Third, percentage of revenue metrics ultimately demand a clear definition of revenue so as to properly relate the fee to the value of the rights being provided, and no such clear definition has been proffered by the parties. Indeed, the definition of revenue has been a point of substantial contention between two of the parties in this proceeding. SoundExchange sought an expansive definition of revenue, ostensibly covering revenues from subscription fees, advertisements (of many kinds including advertisements directly and indirectly derived from webcasting), sales of products and commissions from third party sales, software fees and sales of data. SoundExchange's Revised Rate Proposal (filed September 29, 2006) at 12-17. But the Copyright Royalty Judges are not persuaded that all the elements of the SoundExchange definition of revenue have been shown, in every instance, to be related to the use of the rights provided to licensees.
Fourth, the use of a revenue-based metric gives rise to difficult questions for purposes of auditing and enforcement related to payment for the use of the license. The per-performance approach involves the relatively straightforward application of a rate to reports of use (recordkeeping) data that is already required to be produced by the Services. See 37 CFR part 370. While audit and enforcement issues may arise even with a pure usage metric, the alternative use of a revenue-based metric will give rise to additional, different issues of interpretation and controversy related to how revenues are defined or allocated. See, for example, Radio Broadcasters PFF at ¶ 258 and 7/31/06 Tr. 78:3-11, 79:1-13 (Parsons). In other words, the introduction of multiple payment systems will augment
Fifth, the way that the contending parties, in particular SoundExchange and DiMA, suggest using a revenue-based metric in their rate proposals does not square with the basic notion agreed to by their respective experts (Dr. Brynjolfsson for SoundExchange and Dr. Jaffe for DiMA) that the more the rights being licensed are used, the more payments should increase in direct proportion to usage. See supra at Section IV.B.1. SoundExchange seeks to use the revenue-based metric to insure that it will share in any revenue produced by the Services that is greater than what it would receive based on a usage rate coupled with actual usage. Pelcovits WDT at 28. This could result in a situation where the Services would be forced to share revenues that are not attributable to music use, but rather to other creative or managerial inputs. DiMA, on the other hand, seeks to employ a revenue-based metric to protect against the failure of revenues produced by the Services (particularly as they pursue a shift to advertising-supported business models) to rise to the level necessary to pay for music use based on actual usage. Winston WDT at 10. This could result in a situation in which copyright owners are forced to allow extensive use of their property without being adequately compensated due to factors unrelated to music use such as a dearth of managerial acumen at one or more Services. The similar potentiality that webcasters might generate little revenue and, under a revenue-based metric, produce a situation where copyright owners receive little compensation for the extensive use of their property was a concern that animated the Librarian to approve a per performance metric rather than providing for a revenue-based payment option in Webcaster I. 67 FR 45249 (July 8, 2002).
For all of the above reasons, the Copyright Royalty Judges conclude that evidence in the record weighs in favor of a per-performance usage fee structure for Commercial Webcasters. This does not mean that some revenue-based metric could not be successfully developed as a proxy for the usage-based metric at some time in the future by the parties if the problems noted above were remedied. It does mean that the parties to this proceeding have not overcome these problems in the context of the proposals they have offered in this proceeding.
A further consequence of the Copyright Royalty Judges rejecting the revenue-based metric as a proxy for a usage-based metric is to eliminate the need for a rate structure formulated as a “greater of” or “lesser of” comparison between per performance metrics and alternative revenue-based metrics.
The Copyright Royalty Judges also find that a revenue-based metric is not a good proxy for a usage-based metric as applied to noncommercial webcasters in the non-interactive webcasting marketplace because, in addition to suffering from the same shortcomings discussed supra at Section IV.B.1. in the context of the Commercial Webcasters,
Only one party in this proceeding, SoundExchange, proposes that Noncommercial Webcasters should be subject to a rate structure incorporating a revenue-based metric as one alternative means of payment. SoundExchange specifically proposes that Noncommercial Webcasters pay according to the same structure and rates applicable to Commercial Webcasters, previously summarized supra at Section IV.B.1.
The Noncommercial Webcasters propose a variety of rates that are (or could be read as) per station flat rates. For example, NPR proposes a flat fee of $80,000 per annum, with successive years after the first year increased by a cost-of-living adjustment as determined by the change in the CPI. NPR proposes that this flat fee cover all NPR (798) and CPB-qualified stations (estimated at 100 or 200). Stern WDT at 13; 6/27/06 Tr. 154:18-155:18 (Stern).
The NRBNMLC proposes that non-commercial, non-NPR music stations pay a flat annual fee consisting of the lesser of (a) $200 per Internet simulcast and up to two associated side channels or (b) $500 per group of up to five Internet simulcasts and up to two Internet-only side channels per simulcast. The NRBNMLC further proposes that for news, talk, business, teaching/talk, or sports stations the aforementioned annual fee alternatives drop to $100 and $250 respectively. Mixed format stations would pay a pro rata share of these annual fees based on the demonstrated music-talk programming breakdown. Finally, NRBNMLC proposes that all five years of such fees covering the 2006-2010 license term be paid in one lump sum at the beginning of the term, except that a broadcaster that stops streaming before the end of the term would be entitled to a pro rata refund.
IBS' amended rate proposal seeks a $100 annual rate for large college stations and a $25 annual rate for
For the reasons discussed infra at Section IV.C.2.a., the Copyright Royalty Judges determine that Commercial Webcasters and certain Noncommercial Webcasters represent two different segments of the marketplace. In contrast to the general commercial marketplace, agreements produced by the parties in this proceeding covering noncommercial services typically structured payments as flat fees. See, for example, SERV-D-X 157. Furthermore, no evidence was presented by the parties that could be used in a precise way to convert such flat annual fees into a reliable per-performance metric. Consequently, only a per station metric could be ascertained from such flat fees.
Flat annual fees do not present the complexity, measurement difficulties, accounting and enforcement issues presented by revenue-based alternatives, and, as a result, do not increase transaction costs beyond what might be experienced under a usage-based fee structure. On the other hand, flat fees do permit increasing usage without increasing payment.
However, as noted infra at Section IV.C.2.a, the Copyright Royalty Judges have determined that in order to preserve the distinction between the commercial webcasters and certain noncommercial segments of the marketplace over the period of the license term, a cap on usage must be established for certain noncommercial webcasters.
In short, the Copyright Royalty Judges conclude that, on balance, the most appropriate rate structure for noncommercial services that can be reliably derived from the record of evidence is an annual flat per-station rate structure for use by certain noncommercial webcasters up to a specified cap coupled with a per performance rate for use by noncommercial services that exceed the cap.
As previously noted hereinabove, supra at Section IV.A., the Copyright Act requires that the Copyright Royalty Judges establish rates for the section 114 performance license that “most clearly” represent those “that would have been negotiated in the marketplace between a willing buyer and a willing seller.” Both the copyright owners and the commercial services agree that the willing buyer/willing seller standard should be applied by the Copyright Royalty Judges in determining the rates for the section 114 license and both the copyright owners and the commercial services agree that those rates should reflect the rates that would prevail in a hypothetical marketplace that was not constrained by a statutory license. Finally, both copyright owners and commercial services agree that the best approach to determining what rates would apply in such a hypothetical marketplace is to look to comparable marketplace agreements as “benchmarks” indicative of the prices to which willing buyers and willing sellers in this marketplace would agree. SoundExchange PFF at ¶¶ 215-219; SoundExchange PCL at ¶¶ 4-27; DiMA and Radio Broadcasters JPFF at ¶¶ 75-80; DiMA and Radio Broadcasters JPCL at ¶¶ 28-9; DiMA PFF at ¶¶ 39-45; Radio Broadcasters PFF at ¶¶ 296-301; SBR Creative Media, Inc. PFF at ¶¶ 17; Small Commercial Webcasters PFF at ¶¶ 24-28.
However, the parties, to some extent, appear to disagree about the degree of competition among sellers required by law in the hypothetical marketplace, resulting in different definitions of the sellers in the hypothetical marketplace.
The question of competition is not confined to an examination of the seller's side of the market alone. Rather, it is concerned with whether market prices can be unduly influenced by sellers' power or buyers' power in the market. This issue was addressed in Webcaster I. An effectively competitive market is one in which super-competitive prices or below-market prices cannot be extracted by sellers or buyers, because both bring “comparable resources, sophistication and market power to the negotiating table.” 67 FR 45245 (July 8, 2002). In other words, neither sellers nor buyers can be said to be “willing” partners to an agreement if they are coerced to agree to a price through the exercise of overwhelming market power.
Furthermore, we find that in the hypothetical marketplace that would exist in the absence of a statutory license constraint, the willing sellers are the record companies. Any cognizable entity smaller than the record companies makes little sense because, in such cases, the larger buyers among the Services would enjoy disproportionate market power resulting in below-market prices. At the same time, if the sellers' side of the market were characterized by so many sellers as to be consistent with perfect competition, the transaction costs to the buyers of the copyrights would likely be prohibitive.
Webcaster I made clear that “the willing buyers are the services which may operate under the webcasting license (DMCA-compliant services), the willing sellers are record companies and the product consists of a blanket license for each record company which allows use of that record company's complete repertoire of sound recordings.” 67 FR 45244 (July 8, 2002) (emphasis added). None of the parties has adduced persuasive evidence that this definition of sellers has been altered in the marketplace as a result of greater or lesser competition between these sellers since Webcaster I was issued. For example, no party provided any empirical evidence on the elasticity of the demand curve facing these firms in the market or, more importantly, whether it has changed since Webcaster I. Similarly, no party produced persuasive evidence that market share had changed substantially among the record companies in the hypothetical marketplace since Webcaster I.
As articulated in the Copyright Act, the “willing buyer/willing seller standard” encompasses consideration of economic, competitive and programming information presented by the parties, including (1) the promotional or substitution effects of the use of webcasting services by the public on the sales of phonorecords and (2) the relative contributions made by the copyright owner and the webcasting service with respect to creativity, technology, capital investment, cost and risk in bringing the copyrighted work and the service to the public. Because we adopt a benchmark approach to determining the rates, we agree with Webcaster I that such considerations “would have already been factored into the negotiated price” in the benchmark agreements. 67 FR 45244 (July 8, 2002). Therefore, such considerations have been reviewed by the Copyright Royalty Judges in our determination of the most appropriate benchmark from which to set rates. We have further reviewed the evidence bearing on these considerations to determine if the benchmark agreements require any further adjustment based on any evidence of differences between the benchmark market and the target hypothetical market. See infra at Section IV.C.1.c.
Notwithstanding their general agreement that a benchmark approach is the best way to setting rates in this hypothetical marketplace, the parties disagree about what constitutes the appropriate benchmark indicative of the prices to which willing buyers and willing sellers in this marketplace would agree. SoundExchange maintains that the most appropriate benchmark agreements, as analyzed by its expert economist, Dr. Michael Pelcovits, are those found in the market for interactive webcasting covering the digital performance of sound recordings. SoundExchange PFF at ¶ 216. On the other hand, DiMA, Radio Broadcasters and Small Commercial Webcasters argue that the most appropriate benchmarks are agreements between the performing rights organizations (especially, ASCAP and BMI) and webcasters covering the digital public performance of musical works. DiMA PFF at ¶¶ 39-45; Radio Broadcasters PFF at ¶ 297; Small Commercial Webcasters PFF at ¶¶ 24-26. SBR Creative Media, Inc. claims analog over-the-air broadcast music radio as its benchmark, with reference to musical composition royalties paid by such broadcasters to the performing rights organizations (“PROs”). SBR Creative Media, Inc. Rahn WDT at 11.
We find, based on the available evidence before us, that the most appropriate benchmark agreements are those reviewed by Dr. Pelcovits in the market for interactive webcasting covering the digital performance of sound recordings.
The interactive webcasting market is a benchmark with characteristics reasonably similar to non-interactive webcasting, particularly after Dr. Pelcovits' final adjustment for the difference in interactivity. Both markets have similar buyers and sellers and a similar set of rights to be licensed (a blanket license in sound recordings). Both markets are input markets and demand for these inputs is driven by or derived from the ultimate consumer markets in which these inputs are put to use. In these ultimate consumer markets, music is delivered to consumers in a similar fashion, except that, as the names suggest, in the interactive case the choice of music that is delivered is usually influenced by the ultimate consumer, while in the non-interactive case the consumer usually plays a more passive role. Pelcovits WDT at 5-15. But this difference is accounted for in Dr. Pelcovits' analysis. In order to make the benchmark interactive market more comparable to the non-interactive market, Dr. Pelcovits adjusts the benchmark by the added value associated with the interactivity characteristic. Pelcovits WDT at 37-41. In short, the Copyright Royalty Judges find the Pelcovits benchmark to be of the comparable type that the Copyright Act invites us to consider. 17 U.S.C. 114(f)(2)(B) (“In establishing such rates and terms, the Copyright Royalty Judges may consider the rates and terms for comparable types of digital audio transmission services and comparable circumstances under voluntary license agreements negotiated under subparagraph (A).”).
SoundExchange offers additional relevant evidence from the marketplace for other types of digital music services to corroborate Dr. Pelcovits' analysis by showing that, for many types of music services, a substantial portion of revenue is paid to sound recording copyright owners above the current statutory rate, just as it would be under the rate proposal that Dr. Pelcovits' analysis seeks to support. See, for example, summary chart of Universal Music Group agreements covering various digital music marketplaces at SoundExchange PFF at ¶ 338. We find these additional voluntary agreements covering such digital services as clip licenses, permanent audio downloads, etc. of some general corroborative value. These data show that, in many cases, the price paid by buyers for the rights to utilize a sound recording in various ways is as much as or higher than the rate proposed by Dr. Pelcovits as a result of his benchmark analysis.
At the same time, SoundExchange offered further purportedly corroborative testimony by its economic expert, Dr. Brynjolfsson, which seeks to support its rate proposal based on an analysis of costs and revenues related to webcasting and of the “surplus” that would be generated over the course of the license period. Dr. Brynjolfsson testified that one approach to determining the price a seller would obtain in the market is to measure the “surplus” that would be generated when the seller's input is added to the buyer's service and sold to the public, and then to divide that “surplus” between the buyer and the seller. In order to make the division, it is necessary to determine the revenue that would be generated by the retail sale of the service and the service provider's other costs of providing the service (i.e., costs other than expenditures on the input sought to be valued). This requires certain information about the buyer, the seller and the marketplace to determine how the “surplus” would be divided. We find that the Brynjolfsson analysis relies on unsupported assumptions about market behavior and how negotiations take place in obtaining his results. For example, Dr. Brynjolfsson makes a questionable assumption that conditions in the real world justify the use of a 75% licensor to 25% licensee ratio in bargaining power in his models for this market. 5/18/2006 Tr. 120:1-124-3 (Brynjolfsson). No evidence from this market was provided to support this assumption. A different assumption of equal bargaining power would yield a different estimate of the proposed royalty rate. Similarly, other assumptions such as a 20% annual growth rate in the sell-out rates for
The Services' objections to the Pelcovits benchmark analysis are not supported by persuasive evidence. Their major objections are reflected in Dr. Jaffe's written rebuttal testimony and boil down to two: (1) The claim that this benchmark market is not adequately competitive and (2) certain alleged methodological flaws in the Pelcovits approach. Jaffe WRT at 4-24.
As we have indicated hereinabove, supra at Section IV.C.1.a., the law does not require a perfectly competitive target market if that is the thrust of Dr. Jaffe's objections; therefore, neither does it require a perfectly competitive benchmark market because that would not be comparable to circumstances in the target market. Indeed, Webcaster I emphasizes that buyers and sellers participate in a “competitive” market for purposes of the law when they have comparable resources and market power.
On the other hand, if the thrust of Dr. Jaffe's concerns are that the benchmark market is not sufficiently competitive to be similar to the competitive circumstances that prevail in the target hypothetical market, we find that the evidence does not support such a view. On the contrary, the evidence establishes that the benchmark market is sufficiently similar to the target hypothetical market to merit comparison. There are multiple sellers and buyers in each market—indeed many are the same buyers and sellers. Pelcovits WDT at 12-13. In other words, the weight of the evidence supports the Pelcovits benchmark analysis.
Dr. Jaffe's claim that buyers in the market for interactive webcasting face a different seller than the record companies because they need the portfolios of the four major record companies in order to provide a service to consumers is largely unsubstantiated.
At the same time, Dr. Jaffe's contention that the interactive webcasting benchmark market is highly concentrated on the seller's side is not supported by any evidence of a super-competitive impact on prices in the benchmark market. Further undermining his contention is Dr. Jaffe's own admission that market concentration on one side of the market (i.e., among sellers) need not necessarily result in an outcome that looks markedly different from a competitive outcome so long as the buyers in the same market have comparable market power. SoundExchange PFF at ¶ 196.
Nor does Dr. Jaffe provide any persuasive evidence to support a collusion allegation among the sellers in the interactive webcasting benchmark market. SoundExchange PFF at ¶ 312. And he fails to substantiate his claim that the presence of so-called most favored nations (“MFN”) clauses in certain agreements in the interactive webcasting market is suggestive of anti-competitive behavior. MFN clauses are not automatically indicative of tacit collusion—they may simply reflect the need for price flexibility in the face of uncertainty in long-term contracts.
In short, Dr. Jaffe's concerns that the benchmark market is not sufficiently competitive to be similar to the competitive circumstances that prevail in the target hypothetical market amount to little more than the theoretical speculations of an academic offering a quick outline of possible criticisms without carefully considering the applicable facts or alternative explanations. We find that the available evidence does not support such a view.
Apart from his concerns about the competitive comparability of the interactive webcasting market benchmark to the hypothetical target market, Dr. Jaffe also raises methodological criticisms of the projected rate results obtained by Dr. Pelcovits from the latter's use of interactive webcasting as a benchmark. While raising interesting potential issues, Dr. Jaffe's critique fails in its search for persuasive evidence. For example, Dr. Jaffe complains that the interactivity adjustment made by Dr. Pelcovits is based on incorrect and internally inconsistent assumptions—i.e., the assumption that “elasticity at market equilibrium is the same for interactive services and non-interactive services.” Jaffe WRT at 17. First, it should be noted that even if Dr. Jaffe's complaint were supported by the record, it would not eliminate the interactive webcasting market as an appropriate benchmark. As Dr. Pelcovits correctly notes, “if demand elasticity were to differ significantly between the two markets, it could increase the copyright fee or decrease it.” Pelcovits WRT at 36 n.14. But we are not faced with that difficulty here because the available evidence tends to support Dr. Pelcovits' assumption that demand elasticities were likely to be very close in the relevant range of the demand curves. SoundExchange RFF at ¶¶ 117-118; Pelcovits WRT at 25-27.
Dr. Jaffe also contends that Dr. Pelcovits improperly extrapolates fees for non-subscription or ad-supported services from a model based entirely on subscription services because subscription services only account for a small percentage of non-interactive services. Jaffe WRT at 22-24. He says, without empirical support, that this small fraction is not representative of all non-interactive listeners. Jaffe WRT at 22-24. The implication is that ad-supported services are the predominant business model now for non-interactive webcasting and that ad-supported services would necessarily pay less than subscription services to use the same music in their non-interactive services because their advertising revenues have not yet grown to the point where ad-supported services are more lucrative on a per-listener hour basis. However, this criticism, besides providing no information on the degree of substitution by consumers between the subscription and non-subscription options, fails to take into account any improvement in ad-supported revenues over the term of this licensing period. SoundExchange PFF at ¶¶ 320-321, 323-324. Therefore, to the extent that ad-supported revenues may not yet have equalized subscription revenues on a per-listener hour basis but are expected to grow over the term of this applicable license, SoundExchange's proposed phase-in of the per-performance rates to the level indicated by the benchmark analysis represents a wholly reasonable approach to dealing with this potential issue.
Finally, Dr. Jaffe contends that one or more of the key data items in Dr. Pelcovits' rate analysis must be incorrect because their strict application would produce a negative royalty rate. Jaffe WRT at 20-22. But this criticism ignores the profits earned by interactive services, or, alternatively, assumes without basis that the same dollar amount of profit should be earned by services in the non-interactive market.
In sum, the Services' objections to the Pelcovits benchmark analysis are not persuasive. This does not mean that Dr. Pelcovits' analysis and presentation is without any warts. For example, Dr. Pelcovits failed to fully account in his written statement for the reasoning behind his choice of variables and the functional form used in his hedonic model to isolate the value of interactivity to consumers of online music services. But for the fact that he subsequently provided most of that information orally in response to questions from the Copyright Royalty Judges, 5/16/2006 Tr. 267:16-276:14 (Pelcovits), such an omission may have led to more serious questions about this aspect of his model. And a more comprehensive study of the relative price elasticities of demand in the interactive and non-interactive webcasting markets would have been a welcome addition to the available evidence on this point, even though the available evidence weighed in Dr. Pelcovits' favor. On the other hand, the Copyright Royalty Judges find that these critiques are not sufficient to undermine the basic thrust and conclusions of the Pelcovits benchmark analysis. Moreover, as noted supra at Section IV.C.1.b.ii., his analysis benefits from some general corroborative evidence.
We have also considered and rejected Dr. Jaffe's offer of agreements from the musical works marketplace as a benchmark. This benchmark analysis appears to be little more than a hasty attempt to revive and rehabilitate some similar arguments that failed to prevail in Webcaster I.
The Copyright Royalty Judges find that the benchmark analysis offered by Dr. Jaffe is fatally flawed for several reasons. First, Dr. Jaffe's benchmark analysis is based on a marketplace in which, while the buyers may be the same as in the target hypothetical marketplace, the sellers are different and they are selling different rights. Therefore, contrary to Dr. Jaffe's expectations that the prices paid for the rights in each respective market dealing with similar rights should be the same, substantial empirical evidence shows that sound recording rights are paid multiple times the amounts paid for musical works rights in the markets for ring tones, digital downloads, music videos and clip samples. Pelcovits WRT at 4; Eisenberg WRT at 7-14.
Second, the Copyright Royalty Judges find that Dr. Jaffe's equivalence argument also fails because of his reliance on the assumption of “sunk costs” as a justification. This assumption must be rejected on both theoretical and empirical grounds. Dr. Jaffe claims that, while the sellers in his benchmark market are not the same, they come to the negotiation from a similar position because in both his proposed benchmark market and in the hypothetical target market, the costs of producing the underlying intellectual property are “sunk.” Jaffe WDT at 23. According to Dr. Jaffe, this means “there is no incremental cost imposed on either the musical work or sound recording by virtue of making the underlying intellectual property available for digital performance.”
Third, there is ample empirical evidence in the record from other marketplaces to controvert Dr. Jaffe's premise that the market for sound recordings and the market for musical works are necessarily equivalent. SoundExchange PFF at ¶¶ 483-495.
For all these reasons, the Copyright Royalty Judges find that Dr. Jaffe's proffered benchmark is not useful to our determination of an appropriate benchmark from which to derive applicable rates. We, therefore, adhere to the Pelcovits benchmark analysis as a superior tool for that purpose.
One other benchmark was proposed in this proceeding by a commercial party. SBR Creative Media, Inc. claims analog over-the-air broadcast music radio as its benchmark, with reference to musical composition royalties paid by such broadcasters to the performing rights organizations. SBR Creative Media, Inc. Rahn WDT at 11. We find that this is virtually the same benchmark as that proposed by Dr. Jaffe on behalf of the Services and rejected in Webcaster I. 67 FR 45246-7 (July 8, 2002). SBR does nothing to remedy the deficiencies from which this proposed benchmark was shown to suffer in Webcaster I. Furthermore, this proposed benchmark suffers from the same deficiencies we find fatal with respect to Dr. Jaffe's proposed benchmark discussed supra at Section IV.C.1.b.iv. For all these reasons, the Copyright Royalty Judges find that the SBR Creative Media, Inc. proffered benchmark is not useful to our determination of an appropriate benchmark from which to derive applicable rates and, therefore, adhere to the Pelcovits benchmark analysis as a superior tool for that purpose.
As discussed supra at Section IV.C.1.a., the “willing buyer/willing seller standard” in the Copyright Act encompasses consideration of economic, competitive and programming information presented by the parties, including (1) the promotional or substitution effects of the use of webcasting services by the public on the sales of phonorecords and (2) the relative contributions made by the copyright owner and the webcasting service with respect to creativity, technology, capital investment, cost and risk in bringing the copyrighted work and the service to the public. Because we adopt a benchmark approach to determining the rates, we agree with Webcaster I that such considerations “would have already been factored into the negotiated price” in the benchmark agreements. 67 FR 45244 (July 8, 2002). Therefore, such considerations have been reviewed by the Copyright Royalty Judges in our determination of the most appropriate benchmark from which to set rates. Nevertheless, we have also further reviewed the evidence bearing on these considerations to determine if the benchmark agreements require any further adjustment based on any evidence of differences between the benchmark market and the target hypothetical market.
We find that no further adjustment is necessary to the Pelcovits benchmark analysis to account for any of these considerations. Dr. Pelcovits explicitly examined the promotion and substitution issues and ultimately found no empirical evidence to suggest a net substitution/promotion difference between the interactive and the non-interactive marketplaces. Pelcovits WRT at 17-27. Because only the relative difference between the benchmark market and the hypothetical target market would necessitate an adjustment, the absence of solid empirical evidence of such a difference obviates the need for such further adjustment. Furthermore, even if the absolute levels of promotion/substitution in the non-interactive market alone were somehow relevant, as the Services appear to suggest, we find that the Services presented no acceptable empirical basis for quantifying promotion/substitution for purposes of adjusting rates in that market.
Similarly, the parties' evidence with respect to the relative contributions made by the copyright owner and the webcasting service with respect to creativity, technology, capital investment, cost and risk in bringing the copyrighted work and the service to the public does not persuade us that any further adjustment needs to be made to the Pelcovits benchmark to account for quantifiable differences related to these factors. We find that such factors are implicitly accounted for in the rates that result from negotiations between the parties in the benchmark marketplace. Moreover, because only the relative difference between the benchmark market and the hypothetical target market would necessitate an adjustment, the absence of solid empirical evidence of such a difference obviates the need for such further adjustment.
Finally, the Radio Broadcasters seek to differentiate their simulcasting operations from the operations of other commercial webcasters and, thereby, obtain a different, lower royalty rate. The record before us fails to persuade us that these simulcasters operate in a submarket separate from and non-competitive with other commercial webcasters. Indeed, there is substantial evidence to the contrary in the record indicating that commercial webcasters such as those represented by DiMA in this proceeding and simulcasters such as those represented by Radio Broadcasters in this proceeding regard each other as competitors in the marketplace. SoundExchange PFF at ¶¶ 1107-1110. Therefore, the Copyright Royalty Judges do not find a basis for setting a different, lower rate for these simulcasters as compared to other commercial webcasters. Webcaster I, at 67 FR 45255, 45272 (July 8, 2002), reached a similar conclusion in finding no basis for treating these simulcasters any differently with respect to the per performance commercial rate, and we find no facts to persuade us of a change in circumstance since then.
Because we find that the interactive webcasting market is a benchmark with characteristics reasonably similar to non-interactive webcasting, particularly after Dr. Pelcovits' final adjustment for the difference in interactivity, the Copyright Royalty Judges find that this benchmark supports the explicit annual usage rates
The following Aggregate Tuning Hours (ATH) usage rate calculation options will be available for the transition period of 2006 and 2007: Note: [See table for footnote 33 above] where “Non-Music Programming” is defined as Broadcaster programming reasonably classified as news, talk, sports or business programming; “Broadcast Simulcast Programming” is defined as Broadcaster simulcast programming not reasonably classified as news, talk, sports or business programming; and “Other Programming” is defined as programming other than either Broadcaster simulcast programming or Broadcaster programming reasonably classified as news, talk, sports or business programming.
We find no basis for making further adjustments to this usage rate to reflect inflation
We are persuaded by the evidence in the record to apply these usage rates without any further adjustment for wireless transmission to all Commercial Webcasters. While SoundExchange's proposed rates included a 25% premium for “wireless services,” the Copyright Royalty Judges find no persuasive basis in the record for such a so-called “mobility premium.” The proposed wireless premium was not grounded on the Pelcovits benchmark analysis that underlies SoundExchange's primary rate proposal. Indeed, Dr. Pelcovits specifically declined to do so because of the absence of any data on mobile interactive services. Pelcovits WDT at 60-61. The alternative data offered by Dr. Pelcovits on this issue is not persuasive. Most of the relatively limited data he offers fails to address salient differences between the markets and products represented by that data and the non-interactive webcasting market and its product offerings. In addition, SoundExchange fails to provide any persuasive evidence that a music service delivered to a tethered laptop computer via the Internet is valued differently in the marketplace than the same music service delivered to a laptop computer via the Internet over private or public wireless Internet networks using Wireless Fidelity (“WiFi”) technology. SoundExchange's proposal to exempt wireless transmissions over “personal, short range residential networks” from its proposed wireless premium also underlines its own recognition of the absence of a difference. SoundExchange's Revised Rate Proposal (filed September 29, 2006) at 7. Therefore, on the record before us, we do not find a sufficient basis to support a proposed premium for the wireless transmission of non-interactive webcasts.
Under 17 U.S.C. 114(f)(2)(B), the Copyright Royalty Judges are directed to set a minimum fee for each type of service. SoundExchange points out that the Webcaster I CARP noted that one purpose of the minimum fee was to “protect against a situation in which a licensee's performances are such that it costs the license administrator more to administer the license than it would receive in royalties” and another purpose was “to capture the intrinsic value of the licensee's access to the full blanket license, irrespective of whether the service actually transmits any performances.” SoundExchange PFF at ¶ 1349. We find no evidence in the record that establishes an amount for such an “intrinsic value” and, therefore, focus on the administrative cost issue. Here again, we are provided with little evidence of the administrative cost per licensee,
As previously noted hereinabove, supra at Section IV.A., the Copyright Act requires that the Copyright Royalty Judges establish rates for the section 114 performance license that “most clearly” represent those “that would have been negotiated in the marketplace between a willing buyer and a willing seller.” Both copyright owners and noncommercial services agree that the best approach to determining what rates would apply in such a hypothetical marketplace is to look to comparable marketplace agreements as “benchmarks” indicative of the prices to which willing buyers and willing sellers in this marketplace would agree. However, the copyright owners and the noncommercial services disagree on an appropriate benchmark.
The copyright owners insist there is no basis to apply a benchmark other than that used in the commercial market; and consequently, they maintain that the rates supported by the interactive benchmark analysis apply with equal force to Commercial and Noncommercial Webcasters. SoundExchange's Revised Rate Proposal (filed September 29, 2006). The Noncommercial Webcasters, on the other hand, maintain that they are distinguishable from commercial services and, as such, require a different, lower rate. In effect, they claim to be different buyers and, hence, a different benchmark should be consulted. Joint Noncommercial PFF
Based on the available evidence, we find that, up to a point, certain “noncommercial” webcasters may constitute a distinct segment of the non-interactive webcasting market that in a willing buyer/willing seller hypothetical marketplace would produce different, lower rates than we have determined hereinabove for Commercial Webcasters. A segmented marketplace may have multiple equilibrium prices because it has multiple demand curves for the same commodity relative to a single supply curve. An example of a segmented market is a market for electricity with different prices for commercial users and residential users. In other words, price differentiation or price discrimination is a feature of such markets. The multiple demand curves represent distinct classes of buyers and each demand curve exhibits a different price elasticity of demand. By definition, if the commodity in question derives its demand from its ultimate use, then the marketplace can remain segmented only if buyers are unable to transfer the commodity easily among ultimate uses. Put another way, each type of ultimate use must be different.
Certainly, there is a significant history of Noncommercial Webcasters such as NPR and the copyright owners reaching agreement on rates that were substantially lower than the applicable commercial rates over the corresponding period. See, for example, the 2001 NPR-SoundExchange agreement which covered streaming from 1998 to 2004 (SERV-D-X 157). And, even though SoundExchange offers no formal proposal exempting any Noncommercial Webcasters from its proposed commercial rates, its own economic expert suggests a continuation of differentiated rates where the service offered by such Noncommercial Webcasters does not appear to pose any threat of making serious inroads into the business of those services paying the commercial rate. Brynjolfsson WRT at 42. Dr. Brynjolfsson suggests a cap on listeners beyond which Noncommercial Webcasters would no longer enjoy the lower rate in order to reduce “the chance that small noncommercial stations will cannibalize the webcasting market more generally” and thereby adversely affect the value of the digital performance right in sound recordings.
The Copyright Royalty Judges also can envision such circumstances. But, as a matter of pure economic rationale based on the willing buyer/willing seller standard, those circumstances undoubtedly must include safeguards to assure that, as the submarket for noncommercial webcasters that can be distinguished from commercial webcasters evolves, it does not simply converge or overlap with the submarket
The Copyright Royalty Judges have reached this view after a careful consideration of the characteristics that help to delineate the noncommercial submarket, juxtaposed against evidence in the record that those characteristics may be changing for at least some members of the submarket. For example, the noncommercial broadcasters cite a myriad of characteristics that they claim set them apart from commercial broadcasters. Noncommercial licensees are non-profit organizations. Johnson WDT at ¶ 5; Papish WDT at ¶¶ 4, 12; Robedee WDT at ¶ 2; 6/27/06 Tr. 63:1-21 (Stern); 8/7/06 Tr. 13:11-17, 21:10-12 (Kass). The noncommercial webcasters' mission is to provide educational, cultural, religious and social programming not generally available on commercial venues. See, for example, Stern WDT at 4 and 8/1/06 Tr. 21:11-22:1 (Johnson). Noncommercial webcasters have different sources of funding than ad-supported commercial webcasters-such as listener donations, corporate underwriting or sponsorships, and university funds. Joint Noncommercial PFF at ¶ 20. The implication is that noncommercial webcasters do not compete with commercial webcasters. But as webcasting has developed, some of these traits have become blurred. Public and collegiate radio stations no longer necessarily face a limited geographic audience, but rather their music programming is geographically unbounded so that such stations may compete with commercial webcasters even “worldwide.” SoundExchange PFF at ¶¶ 1105, 1185. Some college radio stations use the Live365 service to stream their simulcasts, making them just another consumer choice available on Live365 together with numerous commercial stations. SoundExchange PFF at ¶ 1186. Commercial Webcasters view Noncommercial Webcasters as competition for an audience interested in listening to music. SoundExchange PFF at ¶ 1116. And some Noncommercial Webcasters, such as NPR, may view Commercial Webcasters as their competition for audience as well. SoundExchange PFF at ¶ 1170. Some noncommercial stations have adopted programming previously found on commercial stations for use on noncommercial side channels or expanding the use of side channels as music outlets. SoundExchange PFF at ¶¶ 1117, 1123. Music programming found on noncommercial stations competes with similar music programming found on commercial stations. SoundExchange PFF at ¶ 1122, SoundExchange RFF at ¶ 284. Sponsorships appear to monetize webcasting in a fashion similar to advertising. SoundExchange PFF at ¶¶ 1130, 1134, 1166. Some noncommercial stations use the functional equivalent of marketing materials that emphasize the size, income and demographics of their audience in much the same manner that commercial stations make their advertising sales pitches. SoundExchange PFF at ¶¶ 1135, 1142. In other words, as webcasting has evolved, some convergence between some noncommercial webcasters and commercial webcasters can be observed ultimately resulting in competition for audience. Brynjolfsson WRT at 40-41. To the extent such competition occurs, market segmentation breaks down, obviating the need for a separate lower royalty rate.
The copyright owners take the position that the same benchmark applies to the noncommercial and the commercial services in the marketplace. Consequently, they maintain that the rates supported by the interactive benchmark analysis discussed supra at Section IV.C.1.b.i. apply with equal force to Commercial and Noncommercial Webcasters. Because we have found that, up to a point, “noncommercial” webcasters, may constitute a segment of the non-interactive webcasting market that in a willing buyer-willing seller hypothetical marketplace would produce different, lower rates than we have determined hereinabove for Commercial Webcasters, we necessarily find that the benchmark proposed by the copyright owners is applicable to only some Noncommercial Webcasters (i.e., those that cannot be clearly distinguished from their commercial counterparts). In other words, the copyright owners' benchmark does not apply to those Noncommercial Webcasters that can be said to constitute a distinct submarket in the non-interactive marketplace. The interactive market benchmark analysis is based on agreements in which all of the services are Commercial Webcasters. There are no agreements that form part of that analysis that would adequately gauge what a Noncommercial Webcaster in a distinctly different submarket would be willing to pay as a willing buyer for the rights at issue in this proceeding.
The Noncommercial Webcasters offer several alternative benchmarks applicable to all noncommercial Services without distinction as well: (1) The musical works rates applicable to over-the-air broadcasting pursuant to section 118 of the Copyright Act and (2) rates loosely related to the 2001 NPR-SoundExchange agreement which covered streaming from 1998 to 2004 (SERV-D-X 157). We find neither of these approaches adequately deals with the segmented marketplace.
First, the Noncommercial Webcasters would apply the rates determined using their benchmarks to all noncommercial Services, irrespective of whether they were part of a submarket in the marketplace for non-interactive webcasting that was distinctly different from commercial non-interactive webcasting.
Second, even within a distinctly different submarket, the benchmarks proposed by the Noncommercial Webcasters suffer from serious flaws. For example, the musical works benchmark proposed by the Services is based on a very different marketplace characterized by different sellers who are selling different rights. Then too, as previously discussed, there is ample evidence in the record from other relevant marketplaces to controvert the underlying premise of this proposed benchmark that the market for sound recordings and the market for musical works are necessarily equivalent. SoundExchange PFF at ¶¶ 483-495. Similarly, the 2001 NPR-SoundExchange agreement covering streaming from 1998 to 2004 does not provide clear evidence of a per station rate that could be viewed as a proxy for one that a willing buyer and a willing seller would negotiate today—it provided for a lump sum amount to cover the entire 74-month term of the contract with no amount specified for different years, and there is nothing in the contract or the record to indicate the parties' expectations as to levels of streaming or the proper attribution of payments for any given year or how additional stations beyond the 410 covered by the agreement were to be handled. Moreover, the transformation of this proposed benchmark by the offering service, the NRBNMLC, into proposed rates adds further problems. In NRBNMLC PFF at ¶ 57, the entire lump sum payable under the 2001 NPR-SoundExchange agreement is divided by 798 stations to arrive at an estimated annual fee of less than $60 per station. But, as previously noted, the agreement in question covered only about half as many stations (410) and dividing the stated lump sum by 410 stations over the stated 74-month term of the agreement would yield a per station rate
In short, we find neither SoundExchange's proposals based on its benchmark nor the Noncommercial Webcasters' proposals based on their suggested benchmarks adequate to provide a basis for determining the rates to be applicable to that part of the noncommercial market for non-interactive webcasting that can be identified as a distinct submarket from the commercial market. However, we observe that certainly the bare minimum that such services should have to pay is the administrative cost of administering the license. There is no evidence in the record to suggest that the submarket in which a Noncommercial Webcaster may reside would yield a different administrative cost for SoundExchange as compared to the administrative costs associated with Commercial Webcasters and SoundExchange, notably, makes no distinction between webcasters with respect to the $500 minimum fee. Webcaster I affirmed the notion that all webcasters—all Noncommercial Webcasters as well as all Commercial Webcasters—should pay the same minimum fee for the same license. 67 FR 45259 (July 8, 2002). We also find no basis in the record for distinguishing between Commercial Webcasters and Noncommercial Webcasters with respect to the administrative cost of administering the license.
Because this minimum fee of $500 is meant to cover administrative costs, it does not address actual usage. Therefore, it would be reasonable to add at least the bare minimum suggested by the Services' proposals as payment for usage to the $500 minimum fee for administration. However, based on the available evidence, we find that past practice has been to treat the minimum fee as recoupable against usage charges. Therefore, we have no basis upon which to add a usage element that is not recoupable to the minimum fee for this distinctive submarket of noncommercial webcasters. Moreover, we note that this minimum fee corresponds to the $500 original fee proposal of IBS and, therefore, demonstrates that, at least for some webcasters in the relevant submarket, the $500 amount represented a ceiling beyond which they would not be willing buyers. Kass WDT at Exhibit A.
We turn next to the derivation of a cap to delineate the boundaries of the submarket for which the effective $500 flat fee rate will apply.
Because there is evidence in the record that some Noncommercial Webcasters typically have a listenership of less than 20 simultaneous listeners—see, for example 8/2/06 Tr. 137 (Robedee) and 8/2/06 Tr. 243 (Willer)—Dr. Brynjolfsson suggests a cap of 20 simultaneous listeners (or about 14,600 ATH
The 2001 NPR-SoundExchange agreement covered the typical NPR webcasting station at a rate substantially less than the rate that applied to Commercial Webcasters as of 2004. Based on the available evidence, the typical NPR station in 2004, then, would not have been treated as the functional equivalent of a commercial station. This is significant because the latest available data on what might constitute a typical NPR streaming station consists of a survey of NPR stations undertaken in 2004. See SoundExchange Trial Ex. 67 (NPR Digital Music Rights Station Survey, 2004). According to that survey, the NPR stations averaged 218 simultaneous streaming listeners per station (or the equivalent of 159,140 ATH per month). This average (218) or a lesser number of listeners was exhibited by 80% of all of the NPR stations engaged in streaming that responded to the survey—in short, it encompassed the experience of all but a handful of NPR stations positioned at the extreme high end of the listenership
Again, we stress that this cap is only a proxy for assessing the convergence point between Noncommercial Webcasters and Commercial Webcasters in order to delineate a distinct noncommercial submarket in which willing buyers and willing sellers would have a meeting of the minds that would result in a lower rate than the rate applicable to the general commercial webcasting market.
A careful review of the record also does not persuade us to make any further adjustment to the lower $500 per station rate described hereinabove to account for such considerations as (1) the promotional or substitution effects on CD sales of webcasting by members of the noncommercial submarket or (2) the relative contributions made by copyright owners and webcasting services with respect to creativity, technology, capital investment, cost and risk. There is no showing of a quantitative effect of these considerations that is not already embraced within the lower rate we have set. Furthermore, inasmuch as that lower rate is also encompassed by the minimum fee necessary to support administration of the license, no showing has been made by any Noncommercial Webcaster that such administrative costs are somehow overborne by such considerations. Similarly, with respect to the higher rate (i.e., the Commercial Webcaster rate) applicable to Noncommercial Webcasters above the monthly 159,140 ATH cap, we find that no further adjustment is required for the same reasons that we found no such adjustment necessary for Commercial Webcasters subject to the commercial rate we set. See supra at Section IV.C.1.c.
In summary, first, we determine that the minimum fee applicable to Noncommercial Webcasters is an annual non-refundable, but recoupable
The following Aggregate Tuning Hours (ATH) usage rate calculation options will be available for the transition period of 2006 and 2007: where “Non-Music Programming” is defined as Broadcaster programming reasonably classified as news, talk, sports or business programming; “Broadcast Simulcast Programming” is defined as Broadcaster simulcast programming not reasonably classified as news, talk, sports or business programming; and “Other Programming” is defined as programming other than either Broadcaster simulcast programming or Broadcaster programming reasonably classified as news, talk, sports or business programming.
Section 112(e) of the Copyright Act directs the Copyright Royalty Judges to establish rates and terms for the making of ephemeral copies of digital recordings to enable or facilitate the transmission of those recordings under the statutory license in section 114. As is the case with the section 114 license, we are tasked with setting rates and terms that “most clearly represent the fees that would have been negotiated in the marketplace between a willing buyer and a willing seller,” as well as establish “a minimum fee for each type
Webcaster I set the royalty fee for the section 112 license at 8.8% of the total royalty fee by a Service under the section 114 license. 67 FR 45240, 45262 (July 8, 2002). This fee, as a separate charge, was not part of the 2003 “push forward” of the Webcaster I rates negotiated by SoundExchange and the Services. Rather, the parties agreed to incorporate the fee for section 112 within the rates for section 114 (which increased by a modest $0.000062 per performance over the Webcaster I rates), but the regulations adopting their agreement provided that of the total section 112/114 fee, 8.8% was “deemed” to comprise the charge for ephemeral recordings. 37 CFR 262.3(c).
SoundExchange proposes to carry forward the combination of section 112 and 114 rates from the prior license period, including the “deeming” of 8.8% of the total fee owed by Services as constituting the section 112 charge. SoundExchange's Revised Rate Proposal (filed September 29, 2006) at 4. DiMA agrees with this proposal. DiMA RFF at ¶ 115. Radio Broadcasters and the NRBMLC also believe that the fee for the section 112 license should be combined with that for section 114, but oppose the attribution of an 8.8% value for the section 112 license. They argue that the effect is to hide an independent value for the section 112 license within the overall fee even though SoundExchange failed, in their view, to provide any evidence to justify the 8.8% value. Radio Broadcasters “take no position as to the percentage of the overall royalty that is to be designated as the portion attributable to the making of ephemeral copies,” but submit that ephemeral copies have no economic value separate from the value of the performances they effectuate. Radio Broadcasters PFF at ¶ 319. The NRBMLC also contends that ephemeral copies have no independent economic value, citing the Copyright Office's 2001 DMCA Section 104 Report in support. NRBMLC PFF at ¶¶ 60, 62.
None of the other parties offer specific proposals as to section 112 rates. SBR Creative Media, Inc. combines section 112 with section 114 in its request for a single fee, while CBI asserts that its stations have no need of the section 112 license. SBR PFF at ¶ 14; CBI PFF at ¶ 19.
While the record in Webcaster I regarding the section 112 license was thin,
Radio Broadcasters and the NRBMLC counter that none of SoundExchange's witnesses discussed proposed rates or values for ephemeral recordings in written or oral testimony. Instead, they point to testimony of Adam Jaffe offered in Webcaster I that ephemeral copies have no independent economic value from the value of the public performances that they effectuate, Jaffe 2001 WDT at ¶ 82; Jaffe 2001 WRT at 81; 2001 Tr. 6556:10-13 (Jaffe), and offer the Copyright Office's 2001 DMCA Section 104 Report in support of Dr. Jaffe's view.
Of the thousands of pages of testimony and exhibits submitted by the parties in this proceeding, less than twenty of the pages are devoted to any discussion of the section 112 license and ephemeral copies. It is therefore evident that the parties consider the section 112 license to be of little value at this point in time, which may explain why SoundExchange is content to roll whatever value the license may have into the rates for the section 114 license. Nevertheless, SoundExchange asks the Copyright Royalty Judges to bless its proposal that whatever the royalty fee for the section 114 may be, 8.8% of that fee constitutes the value of the section 112 license. We decline to accept SoundExchange's invitation for two reasons.
First, the section 112 license requires us to determine the rate or rates that would have been negotiated between a willing buyer and a willing seller. SoundExchange's valuation of 8.8% is not a rate. Services will not be paying 8.8% more in total royalty fees because of this valuation, nor will they be subtracting 8.8% from their charge if they choose not to avail themselves of the section 112 license. Rather, the 8.8% valuation is nothing more than an effort to preserve a litigation position for future negotiations that the section 112 license has some independent value, as it did in Webcaster I. It is understandable why DiMA would not find the 8.8% figure objectionable since it does not represent any additional charges to its members in this proceeding.
Second, the paucity of the record prevents us from determining that 8.8% of the section 114 royalties is either the value of or the rate for the section 112 license. SoundExchange's assertion that its 8.8% proposal is “strong evidence” of copyright owners' and performers' belief as to the appropriate rate applicable to section 112 is bootstrapping. SoundExchange did not present any persuasive testimony or evidence from copyright owners or performers on this point. We also do not find the WMG-Next Radio and the SONY BMG-MusicMatch agreements to be supportive of an 8.8% rate for ephemeral copies, which SoundExchange asserts are evidence of marketplace negotiations and establish a “zone of reasonableness” for section 112 rates in the 10% range. These agreements are for custom radio, which SoundExchange has long avowed is not DMCA compliant, and both have expired. SoundExchange Ex. 002 DR at 10 (WMG-Next Radio Solutions webcasting agreement); SoundExchange Ex. 004 DR at 14 (SONY BMG-MusicMatch Internet radio agreement). More importantly, the 10% figure in both is not a rate but is, like SoundExchange's proposal, a proclamation as to how much of the total fees paid by Next Radio and MusicMatch are attributable to the making of ephemeral copies. Since the 10% figure does not represent any actual monies to be paid by Next Radio or MusicMatch, it can hardly be argued that those agreements are marketplace evidence of negotiated royalty rates for the section 112 license.
We are left with a record that demonstrates that, since the expiration of section 112 rates set in Webcaster I, copyright owners and performers are unable to secure separate fees for the section 112 license. The license is merely an add-on to the securing of the performance right granted by the section 114 license. SoundExchange's proposal to include the section 112 license within the rates and minimum fees set for the section 114 license reflects this reality and we accept it. In so doing we decline, for the reasons stated above, to ascribe any particular percentage of the section 114 royalty as representative of the value of the section 112 license.
Sections 112(e)(3) and 114(f)(2)(A) of the Copyright Act, 17 U.S.C., require the Copyright Royalty Judges to adopt royalty payment terms for the section 112 and 114 statutory licenses.
In Webcaster I the parties agreed to a set of terms and, with the exception of a few disputed terms, presented them to the CARP for acceptance. In adopting the parties' proposed terms, the CARP declined to make a determination as to whether they were feasible or efficient and deferred to the judgment of the Librarian of Congress. Webcaster I CARP Report at 129. The Librarian declined to address the issue as well and evaluated the agreed-upon terms according to the “arbitrary or contrary to law” standard that the Librarian applied to the other aspects of the CARP's decision. The Librarian did, however, state that he was “skeptical of the proposition that terms negotiated by parties in the context of a CARP proceeding are necessarily evidence of terms that a willing buyer and a willing seller would have negotiated in the marketplace,” and noted that he would not have adopted all of the negotiated terms if his “task were to determine the most reasonable terms governing payment of royalties.” 67 FR 45266 (July 8, 2002). The question therefore remains as to whether the Judges should consider matters of feasability and administrative efficiency in adopting payment terms. We conclude the answer is yes, for two reasons.
First, it is an axiom of the copyright laws that statutory licenses are designed to achieve efficiencies that the marketplace cannot. See, H.R. Rep. No. 94-1476, at 89 (1976). Typically, statutory licenses reduce transaction costs associated with licensing large volumes of copyrighted works from multiple rights holders. They guarantee access to the use of prescribed categories of works to those who satisfy the eligibility requirements of a license, while providing a return to the owners of the works subject to the license. Statutory licenses are about administrative efficiency. For example, they increase the speed and ease with which copyrighted works may be used. Adopting a set of terms whose operation is not practical, or creates additional unjustified costs and/or inefficiencies, is inconsistent with the precepts of statutory licensing, and we must avoid such circumstances.
Second, we observe that rational willing buyers and sellers themselves will, in their agreements with one another, select terms that are practical, efficient, and avoid excessive costs. Consequently, we have considered the terms presented in agreements offered by the parties to this proceeding, assessed their applicability to the blanket license structure of the statutory licenses, and adopted those terms that will facilitate an efficient collection, distribution and administration of the statutory royalties.
Unlike the statutory licenses set forth in sections 111, 119, and chapter 10 of the Copyright Act where royalty payments are submitted directly to a government collecting body (the Licensing Division of the Copyright Office), the section 112 and 114 licenses contain no such provision. Read literally, the licenses appear to require that licensees pay royalties directly to each copyright owner and performer. Recognizing the costs and inefficiencies of such an approach, the parties to the first section 112/114 proceeding negotiated a payment scheme whereby all services paid their royalties to a single “Receiving Agent”: SoundExchange, Inc. See 37 CFR 262.4. SoundExchange was, at that time, an unincorporated division of the Recording Industry Association of America.
The royalty collection and distribution scheme adopted in Webcaster I ended with the expiration of the 1998-2002 licensing period. In negotiations for rates and terms for the 2003-2004 licensing period, the parties retained the Receiving Agent/Designated Agent structure but did not recognize Royalty Logic as a Designated Agent.
Royalty Logic, acting as an authorized agent for certain copyright owners and performers,
Royalty Logic contends that it is necessary for the Copyright Royalty Judges to formally recognize it as a “Designated Agent”—complete with direct accounting, reporting, payment and auditing rights vis-a-vis the Services—in the payment regulations to be adopted in this proceeding so that it may compete with SoundExchange as a royalty collection and distribution agent. The claimed need for competition is the central feature of Royalty Logic's presentation. According to Royalty Logic, Designated Agents can compete with one another on multiple levels, including: (1) The royalty rates to be charged; (2) interpretations of the statute; (3) distribution policies; and (4) costs. 6/14/06, Tr. 101:5-105:5; 124:14-127:20; 314:22-315:19 (Gertz). Royalty Logic advocates a payment scheme whereby a proportionate share of the royalties owed by each Service under the section 112 and 114 licenses would be allocated to each Designated Agent; i.e., it and SoundExchange. Both Designated Agents would be entitled to direct receipt of statements of account, royalty fees and the reports of use of sound recordings required by 37 CFR part 370. For the initial payment period, Royalty Logic proposes that it receive five percent of each Service's royalties, which subsequently would be adjusted either upwards or downwards depending upon the number of performances belonging to Royalty Logic's affiliates that were made by the Service. The identity and ownership of performances (and ephemeral reproductions, if any) would be determined through examination of each Service's report of use of sound recordings. Thereafter, royalty payments to Royalty Logic and SoundExchange would be based solely upon performances of the works of each organization's members, as determined by the reports of use from the prior payment period. Any disputes between the Designated Agents concerning royalty allocations would be resolved by the Copyright Royalty Judges. RLI PFF at ¶ 117(g).
SoundExchange is a non-profit performing rights organization that represents thousands of record labels and artists who have specifically authorized SoundExchange to collect royalties on their behalf. Kessler WDT at 3. SoundExchange presented the direct testimony of John Simson, Barrie Kessler, Harold Ray Bradley, and Cathy Finks on the matter of royalty collection and distribution, as well as the rebuttal testimony of Thomas Lee.
SoundExchange submits that it would be inefficient for the Copyright Royalty Judges to select more than one agent to receive and distribute royalties. SoundExchange PFF at ¶ 46. It argues that it should be the sole collection and distribution agent because it is proven and well-run and is the most qualified and dedicated to the interests of copyright owners and performers. SoundExchange PFF at ¶¶ 1558-67. It contends that Royalty Logic is unsuitable to serve as an agent because it is owned by Music Reports, Inc., a company that represents licensees of musical works, and such connection creates a conflict of interest. SoundExchange PFF at ¶¶ 50, 51.
At the outset, the Copyright Royalty Judges must address a fundamental misperception of Royalty Logic, and to a somewhat lesser extent SoundExchange, regarding Receiving Agents and Designated Agents. As noted above, Receiving Agents and Designated Agents and the terms governing their operation were established by agreement by the parties in Webcaster I and were adopted, reluctantly, by the Librarian of Congress. 67 FR 45240, 45266 (July 8, 2002); See also, Determination of Reasonable Rates and Terms for the Digital Performance of Sound Recordings by Preexisting Subscription Services (Final rule), 68 FR 39837, 39839 n.2 (July 3, 2003) (stating that in Webcaster I the Librarian “expressed skepticism about the benefit of the two-tier structure involving a Receiving Agent and more than one Designated Agent, which adds expense and administrative burdens to a process the purpose of which is to make prompt, efficient, and fair payments of royalties to copyright owners and performers with a minimum of expense.”) The entire Receiving Agent/Designated Agent structure is a legal fiction with no basis or grounding in the statute,
In evaluating the Receiving Agent/Designated Agent system, we share in the Librarian's skepticism that it is an effective and efficient means of collecting and distributing royalties. The system was pressed in negotiations by the Services in Webcaster I as a means of enabling Royalty Logic to enter the business of collecting and distributing section 112 and 114 royalties even though Royalty Logic did not represent at the time a single copyright owner or performer entitled to those royalties. 68 FR 39839 (July 3, 2003). While Royalty Logic's participation may have presented the Services with a potential future benefit, it is difficult to determine what, if any, benefit was derived by copyright owners and performers. Royalty Logic responds that the benefit to copyright owners and performers is the fruits of competition between it and SoundExchange, yet there is no evidence in the record that demonstrates that any copyright owners or performers sought or claimed such a supposed benefit. If anything, the record reflects that copyright owners and performers prefer SoundExchange as the sole collection and distribution entity. SoundExchange Ex. 239 RP, 240 RP; Lee WRT at 4; Bradley WRT at 20; Fink WDT at 14.
We are also troubled by Royalty Logic's contention throughout this proceeding that an agent must be formally recognized by the Copyright Royalty Judges as a Designated Agent before it can have any involvement in the royalty distribution process. This position has no support in the statute. Sections 112(e) and 114(e) state that it is copyright owners and performers who may designate common agents for the receipt of royalties. As the Librarian observed in the 2003 section 112 and 114 preexisting subscription service proceeding:
In fact, it is not clear that RLI needs to participate in a CARP proceeding or be named in a negotiated settlement in order to act as a designated agent for purposes of collecting royalty fees on behalf of copyright owners and performers who are entitled to receive funds collected pursuant to the section 112 and section 114 licenses. Section 112(e)(2) and section 114(e) of the Copyright Act both expressly provide that a copyright owner of a sound recording may designate common agents to negotiate, agree to, pay, or receive royalty payments. Under these provisions, it is plausible that a copyright owner or performer could designate any agent of his or her choosing (including RLI)—whether or not that agent had been formally designated in the CARP proceeding—to receive royalties from the licensing of digital transmissions and, by doing so, limit the costs of such agents to those specified in section 114(g)(4), as amended by the Small Webcaster Settlement Act of 2002.
Given our reservations about the Receiving Agent/Designated Agent
As noted above, a literal reading of the section 112 and 114 licenses suggests that the Services pay directly each and every copyright owner and performer for the use of their respective works. No one in this proceeding, however, has suggested this arrangement, nor do any of the statutory licenses in the Copyright Act function in that fashion. Direct payments would add enormous transaction costs to the Services as they would be forced to locate and make arrangements with all copyright owners and performers for the thousands and thousands of sound recordings they perform, thereby eliminating much, if not all, of the efficiencies achieved by statutory licensing. Consequently, the royalty payment and collection system that we adopt must promote administrative efficiency and economy and reduce transaction costs wherever possible. This stated purpose is wholly consistent with the willing buyer/willing seller standard.
In adopting an economically and administratively efficient royalty collection and distribution method, Royalty Logic proposes that we look to the marketplace for performance rights for musical works, which is dominated by three principal rights organizations: ASCAP, BMI and SESAC. These organizations operate on behalf of and are paid for by their members. Royalty Logic contends that competition among the performing rights organizations reduces the administration costs for collecting and distributing royalties in that market and is therefore more efficient than a single Collective such as SoundExchange. We reject application of the performing rights organization model to this proceeding for several reasons. First, the performing rights organizations do not operate exclusively within the confines of a statutory license. The majority of these organizations' activity is direct licensing with users of musical works.
Second, performing rights organizations are member societies that license only the works of their members. The statutory licenses are blanket licenses that cover the works of all copyright owners and performers. Forcing owners and performers to choose membership in one or more Collectives when their works have already been licensed does not seem to serve a purpose and creates a significant practical difficulty in resolving how unaffiliated copyright owners and performers should receive their royalty distributions.
Third, while Royalty Logic vehemently argues that competition between it and SoundExchange will reduce the overall administrative costs in the royalty collection and distribution process and therefore result in greater returns for copyright owners and performers, it never presented evidence demonstrating the likelihood of such an outcome.
In sum, we find that selection of a single Collective represents the most economically and administratively efficient system for collecting royalties under the blanket license framework created by the statutory licenses. Transaction costs to the users of such a license are minimized when they can make payment to a single Collective, as opposed to allocating their payments among several. And there is no credible evidence that demonstrates copyright owners and performers suffer increased costs from a system with a single Collective. We now turn to the issue of which of the two parties in this proceeding, Royalty Logic or SoundExchange, will best fulfill the role of the Collective for section 112 and 114 royalties.
SoundExchange, a non-profit corporation under 26 U.S.C. 501(c)(6), has operated as the royalty collection and distribution entity since the beginning of the statutory licenses involved in this proceeding, and collects and distributes the royalties paid by preexisting subscription and satellite digital audio services under the statutory license created by the Digital Performance Right in Sound Recordings Act of 1995, Public Law 104-39, 109 Stat. 336 (1995). Kessler WDT at 2. SoundExchange is controlled by an 18-member Board of Directors comprised of equal numbers of representatives of copyright owners and performers. Copyright owners are represented by board members associated with the major record companies (five), independent labels (two), the Recording Industry Association of America (one), and the American Association of Independent Music (one). Performers are represented by one representative each from the American Federation of Television and Radio Artists; the American Federation of Musicians; and seven at-large artist seats. Simson WDT at 33. Though it is a non-member organization, SoundExchange is authorized by over 12,000 performers, 3,000 record labels and 800 record companies to collect royalties on their behalf. SoundExchange PFF at ¶ 75. SoundExchange distributes royalties to nearly 15,000 copyright owner and performer accounts and, as of September 20, 2005, has processed over 650 million sound recording performances. Kessler WDT at 12, 16. It is the only organization that directly receives reports of use from the Services under the licenses in this proceeding. 37 CFR 370.3(d)(4).
SoundExchange presented Thomas Lee, President of the American Federation of Musicians, who testified that the structure of SoundExchange's Board provides the necessary checks and balances to ensure that performer interests are well represented. Lee WRT at 4-5. Several performer organizations—the American Federation of Television and Radio Artists, the Music Manager's Forum, and the Recording Artists' Coalition—wrote to Mr. Lee to express their preference and support for SoundExchange in these proceedings. SoundExchange Exs. 239 RP, 240 RP, 241 RP; Lee WRT at 4. Recording artists Harold Ray Bradley and Cathy Fink testified as to their preference for SoundExchange as the sole collective for section 112 and 114
Royalty Logic, a for-profit corporation, operated as a “Designated Agent” under the Webcaster I decision. Gertz WDT at 5-6; RLI PFF at ¶ 36. Royalty Logic was created and is currently managed by the principals of Music Reports, Inc. Music Reports is in the business of allocating royalty payments from television stations to performing rights societies for musical works performed by those stations. Royalty Logic recently received a significant investment from Abry Partners and may be reorganizing as a result. 11/15/06 Tr. 130:16-131:5 (Gertz). As described in footnote 61, supra, the precise number and identity of copyright owners and performers currently represented by Royalty Logic is unclear. Royalty Logic did not present any copyright owner or performer witnesses
After considering the presentations of both parties, the Copyright Royalty Judges conclude that SoundExchange is the superior organization to serve as the Collective for the 2006-2010 royalty period. SoundExchange has a proven track record in collecting and processing section 112 and 114 royalties, having done so since the inception of the statutory licenses. Its operational practices appear efficient and fair, and the Judges were not presented with credible evidence of significant failures or deficiencies.
This testimony is not outweighed by the Royalty Logic/DiMA royalty rate agreement offered by Royalty Logic as evidence of the Services' preference for Royalty Logic. It is difficult to envision any interest that the Services can have in the administration and distribution of royalties, which are the essential functions of the Collective. The Services' views on this subject are not reflected in the agreement. More importantly, the value of the agreement itself is illusory. Signed only by DiMA, a trade organization, it does not bind any Service to its terms; and, to date, no Services have signed on to the agreement. 11/15/06 Tr. 108:7-15 (Gertz).
The Copyright Royalty Judges also have serious reservations about the bona fides of Royalty Logic to act as the Collective under the statutory licenses. Royalty Logic “is a for profit organization whose acknowledged goal is to make a profit,” 67 FR 45267 (July 8, 2002), and Mr. Gertz candidly offered that his reasons for seeking entrance into the royalty collection and distribution business was “to make money.” 11/15/06 Tr. 89:7-10 (Gertz). In addition, Mr. Gertz stated that Royalty Logic may decide to pay some copyright owners and/or performers more than others. 11/15/06 Tr. 79:22-80:10 (Gertz). These statements raise a concern as to whether Royalty Logic will act in the best interest of all copyright owners and performers covered by the statutory licenses. The concern is elevated by the fact that Royalty Logic's participation in Webcaster I was championed by the Services and is favored more in this proceeding by the Services than by copyright owners and performers.
Likewise, we have no basis in the record to expect that Royalty Logic will deduct lower administration fees, and therefore return greater royalties to copyright owners and performers, than SoundExchange. We were not presented with any comparison of Royalty Logic's and SoundExchange's administration fees, only an argument that competition between Collectives potentially could reduce the overall administration fees. Given that we are selecting only a single Collective, the potential effects of competition on administration fees to be charged to copyright owners and users is not relevant.
In sum, the Copyright Royalty Judges determine that SoundExchange will best serve the interests of all copyright owners and performers whose works are subject to the statutory licenses and, therefore, shall be the Collective for the 2006-2010 royalty period.
Having resolved the matter of who shall serve as the Collective for the 2006-2010 licensing period, the Copyright Royalty Judges now turn to other terms necessary to effectuate payment and distribution. Other than the few disputed terms, adoption of all the terms necessary for payment and distribution presents a decidedly unfortunate challenge, as is discussed below.
In Webcaster I, the parties to the proceeding presented the CARP with a comprehensive, negotiated settlement of nearly all the payment, administration and distribution terms for the section 112 and 114 licenses. These terms included governing provisions for submission of payments and statements of account, confidentiality requirements, audit and verification of statements of account and royalty distributions, and unclaimed royalty
The Librarian made significant alterations to the CARP's determination regarding terms. While he accepted the CARP's rejection of the broadcaster definitional terms and the determination that SoundExchange should serve as agent for unaffiliated copyright owners, he rejected a negotiated term limiting agents' liability for improper distributions and a negotiated term allowing agents to deduct litigation and licensing costs from collected royalty fees. 67 FR 45268-9 (July 8, 2002). He also modified a negotiated definition of “gross proceeds” and created two new definitional provisions: one for “Ephemeral Recordings” and another for “Listener.” Further, he extended the right to select a Designated Agent to performers in addition to copyright owners, granted performers the right to audit their Designated Agent, and “clarified” the negotiated terms for allocating royalty payments among Designated Agents and for allocation of royalties among parties entitled to receive such royalties. 67 FR 45270-1 (July 8, 2002).
As noted previously, there was no CARP proceeding for the 2003-2004 licensing period. The parties settled their differences and offered the Librarian a negotiated agreement for rates and terms. The proposed agreement included the Webcaster I terms with some modifications. After offering the proposed agreement for public comment, the Librarian adopted it. See, Digital Performance Right in Sound Recordings and Ephemeral Recordings (Final rule), 69 FR 5693 (February 6, 2004). Codified in part 262 of the Copyright Office's regulations, the effective date of these rates and terms was extended by the Copyright Royalty and Distribution Reform Act of 2004 until December 31, 2005, the last day prior to the beginning of the rates and terms established by this proceeding. 37 CFR part 262; Copyright Royalty and Distribution Reform Act of 2004, Public Law 108-419, section 6(b)(3) (transition provisions), 118 Stat. 2341, 2370 (2004).
The parties' approach to rates and terms was decidedly different in this proceeding than in Webcaster I. Even though the Copyright Royalty and Distribution Reform Act of 2004 eliminated the CARP system and thereby removed the Librarian and the Copyright Office from further involvement in royalty adjustment proceedings,
In examining part 262, the Copyright Royalty Judges observe that these are the regulations of the “Copyright Office, Library of Congress.” The Copyright Royalty Judges do not have authority to amend, alter, or otherwise affect these regulations. There is no provision in the Copyright Royalty and Distribution Reform Act of 2004 that carries forward the regulations contained in part 262 or makes them applicable to the Copyright Royalty Judges.
Other than testimony and argument devoted to amendment of certain provisions contained in part 262, no other evidence was presented regarding terms for payment and distribution. The Copyright Royalty Judges anticipated that the parties would follow their approach from Webcaster I and present negotiated terms prior to the close of the record. When nothing was forthcoming, the Copyright Royalty Judges issued an order directing parties to file agreed-upon terms no later than the deadline for the submission of their reply findings of fact and conclusions of law. Amendment to Amended Trial Order, Docket No. 2005-1 CRB DTRA (November 28, 2006). When nothing again was filed, the Copyright Royalty Judges questioned counsel at closing arguments who stated that because of the press of time in drafting and filing proposed findings and reply findings, they were unable to discuss or negotiate any terms. Still nothing has been filed.
The failure to submit negotiated terms, coupled with the absence of further testimony, places the Copyright Royalty Judges in a difficult situation. While there is sufficient record testimony to resolve the disputed terms, see infra, the only evidence for the “missing terms” is the assumption of the parties that the provisions of part 262, plus our resolution of disputed terms, would constitute the terms for payment and distribution for the 2006-2010 statutory period. The parties' assumption is certainly thin evidence on which to proceed. Nevertheless, there are sufficient grounds to resolve the difficulty of the missing terms.
First, we observe that in Webcaster I the Librarian made several wholesale changes to the parties' negotiated terms even though the parties did not propose such changes. The Librarian created definitions for “Ephemeral Recordings” and “Listener” because, in his view, their absence from the regulations would lead to confusion. 67 FR 45269-70 (July 8, 2002). He extended the right of choosing a Designated Agent to performers as well as copyright owners and permitted them to audit Designated Agents because he could “conceive of no reason why Performers should not be given the same choice” as copyright owners. 67 FR 45271 (July 8, 2002). It is clear that the Librarian took these actions so that the regulations governing terms would be clearer, more efficient and fairer to the parties affected. In other words, the Librarian endeavored to make the operation of the statutory licenses as smooth, efficient, and fair as possible. This approach was both necessary and proper and we adopt it here. It is wholly consistent with our conclusion, discussed in Section V.A., supra, that it is our obligation to adopt royalty payment and distribution terms that are practical and efficient. Failure to so act would produce statutory licenses that are operationally chaotic and otherwise unusable, thereby frustrating the Congressional intention underlying their establishment.
Second, while an assumption that part 262 would apply to the new license period is not necessarily the best
Consequently, the Copyright Royalty Judges are adopting the undisputed provisions of part 262 as the baseline for terms for the 2006-2010 licensing period, subject to the additions and changes adopted in this decision. Parties to future royalty rate proceedings are strongly urged to attach a greater importance to the adoption of terms and to create a more comprehensive and thorough record.
SoundExchange requests that the Copyright Royalty Judges establish a fee for late payments of statutory royalties equal to 2.5% of the total royalty owed by the Service for that period. The 2.5% late fee represents a substantial increase from the 0.75% late fee adopted in Webcaster I.
SoundExchange argues that the increase is necessary. Barrie Kessler stated that many Services are late with their royalty payments and opined that a nominal late fee (0.75%) coupled with the high cost of bringing an infringement action for failure to pay royalties actually encourages late payments. Kessler WDT at 27-28; 6/8/06 Tr. 261:1-6 (Kessler). Ms. Kessler also requested that the late fee be doubled every five days beginning 20 days after SoundExchange sends a Service notification of late payment. Kessler WDT at 28.
In support of its request for the 2.5% late fee, SoundExchange offers several marketplace agreements between record companies and services containing, on average, a late payment fee of 1.5% per month, with a high of 2.0%. SoundExchange Ex. 012 DR (UMG-MusicNet subscription services agreement); SoundExchange Ex. 014 DR (UMG-Muze clip license agreement); SoundExchange Ex. 017 DR (UMG-Real Networks subscription agreement); SoundExchange Ex. 021 DR (SONY BMG-Muze clip license agreement); SoundExchange Ex. 002 DR (WMG-Next Radio Solutions webcasting agreement); SoundExchange Ex. 004 DR (SONY BMG-MusicMatch Internet radio agreement).
Radio Broadcasters and DiMA counter that a 0.75% late fee (9% per annum) is generous and is greater than the current cost of borrowing. DiMA and Radio Broadcasters JPFF at ¶ 286. They cite the testimony of Eugene Levin of Entercom Broadcasting who, while conceding that Entercom has agreements with a number of suppliers (including ASCAP, BMI and SESAC) that provide for late fees ranging from 12% to 18% per year, testified that late fees are often waived so as to promote a positive business atmosphere and maintain good relations. Levin WRT at 4-5; 11/14/06 Tr. 38:2-9, 41:5-12 (Levin). Radio Broadcasters cite Entercom's agreements with SESAC and Liquid Compass as evidence that late fees can be discretionary. Radio Broadcasters RFF at ¶¶ 137-138.
The Copyright Royalty Judges determine that the record evidence does not support continuation of a 0.75% per month late fee. Although Mr. Levin advocated that number, he did not provide a single agreement that his company had for music service that contained such a rate, nor did he state that he was aware of any agreements containing such a rate. To the contrary, Entercom's agreements with ASCAP, BMI and SESAC all provide for late fees ranging from 12% to 18% per annum. 11/14/06 Tr. 38:2-9, 41:5-12 (Levin). The agreements cited by SoundExchange also fall within this range.
We are not persuaded that contracting parties' ability to waive late fees requires rejection of a higher late fee. Contract provisions granting discretion to waive late fees were present in some of Entercom's agreements but were noticeably absent from the record company/music service agreements cited by SoundExchange. Mr. Levin was not aware of industry practices with respect to waiver. Moreover, his testimony that waiver promotes good business relationships with contractees is unavailing in the context of statutory licensing. While waiving a late fee can promote good feelings in a private agreement and thereby avoid termination of future goods and services by the offending party, it has no bearing for a statutory license where copyright owners and performers cannot, short of an infringement determination by a federal court, terminate access to their works under the license.
After reviewing the record, the Copyright Royalty Judges find that the record company/music service agreements provided by SoundExchange are the best evidence as to the appropriate late fee. While these are not agreements for DMCA-compliant webcasting,
Webcaster I and part 262 of the Copyright Office's rules adopted a late fee for royalty payments but not for late statements of account. Ms. Kessler testified that it is not uncommon for SoundExchange to receive late and incomplete statements of account from Services. 6/6/06 Tr. 137:12-138:20 (Kessler). She urged the Copyright Royalty Judges to adopt a penalty fee for late and/or incomplete statements calculated as if the Service had failed to pay royalties when required. Kessler WDT at 29-30. Mr. Levin testified that it was inappropriate to assess a late fee when a Service did not submit a timely statement of account and particularly unfair where the statement contained good faith errors or omissions. Levin WRT at ¶¶ 16,19; 11/14/06, Tr. 44:18-45:11 (Levin).
The Copyright Royalty Judges determine that timely submission of a statement of account is critical to the quick and efficient distribution of royalties. The statement of account identifies the time period to which the royalty payment applies, enables SoundExchange to determine what music service is being paid for and whether the filer has attributed the correct royalty fee to the service or services it is paying for. Although Mr.
With respect to the completeness of the statement of account, the burden is upon the Service to provide as complete and error-free a statement as possible. All of the information needed to complete the statement—which is neither complex nor lengthy, see SoundExchange Ex. 212 DP—is in the possession of the Service. Inconsequential good-faith omissions or errors should not warrant imposition of the late fee.
There is considerable disagreement as to whether the information contained in statements of account is confidential and should be viewed by the Collective (SoundExchange) alone and not by copyright owners and performers. DiMA and Radio Broadcasters assert that a confidentiality requirement is necessary and is what willing buyers and sellers would agree to in a competitive market. DiMA and Radio Broadcasters JPFF at ¶¶ 297, 299. They cite to the confidentiality provisions of five agreements—SoundExchange Ex. 003 DR sec. 10(b) (WMG-MusicNet subscription services agreement); SoundExchange Ex. 004 DR sec. 10.01 (SONY BMG-MusicMatch Internet radio agreement); SoundExchange Ex. 006 DR sec. 8.1 (EMI standard wholesale agreement for streaming/conditional download licenses); SoundExchange Ex. 017 DR sec. 5(b) (UMG-Real Networks subscription agreement); SoundExchange Ex. 014 DR sec. 6 (WMG-Muze clip license agreement)—in support of this assertion. Further, Mr. Levin testified that the information concerning a Service's total royalty payments, listening minutes and aggregate tuning hours is not the kind of information that Services share with their competitors. 11/14/06 Tr. 47:14-48:7 (Levin).
SoundExchange counters that precluding copyright owners and performers from access to the information contained in the statements of account not only impedes the operation of its Board of Directors (which is comprised of owners and performers) but is a denial of the fundamental information necessary for enforcement of the statutory licenses. Kessler WDT at 33. Copyright owners and performers only see statement of account information from prior statutory license periods in the aggregate
The Copyright Royalty Judges are troubled by continuing the confidentiality restrictions adopted in Webcaster I and part 262 of the Copyright Office's regulations. Because they were the product of negotiations, there was no finding that the types of information contained in the statements of account were indeed “confidential”; i.e., that their disclosure would harm the business interests of the reporting Services. Mr. Levin, the only witness offered by the Services on this point, did not articulate how the information contained in the statements can or could injure the competitiveness of a Service, or otherwise negatively affect its operation. 11/14/06 Tr. 96:11-104:11 (Levin). Further, he conceded that a competitor's subscription to Arbitron, a broadcasting rating and information service, would provide much of the same information contained in the statements. 11/14/06 Tr. 85:20-87:13, 97:13-99:14 (Levin). The Copyright Royalty Judges come to the conclusion that while Services may want the information contained in statements of account to remain confidential, they have not demonstrated how disclosure of that information is, or is likely to be, harmful.
Even more troubling is how the denial of information to copyright owners and performers impacts their substantive rights under the section 112 and 114 licenses. Without the information contained in a statement of account, a copyright owner and/or performer cannot begin to make an informed judgment as to whether a Service is complying with its statutory obligations and making the correct payments. Permitting the disclosure of the information contained in statements of account only to the Collective does not alter this concern and grants the Collective an inordinate amount of control as the only party knowledgeable of the compliance of each of the Services. No support can be found in the statute for an arrangement that effectively imbues only the Collective, or any other agent, with the information necessary to pursue an infringement action. In sum, copyright owners and performers should not be excluded from obtaining the information contained in a statement of account of a Service that performed his or her work.
Review of the licensing agreements cited by Radio Broadcasters does not counsel a different result. The confidentiality provisions in these agreements generally prohibit disclosure of “business” information to those not party to the agreement, i.e., the public at-large. They do not deny the licensor—the copyright owner—access to this information. And several of the cited agreements permit the licensor to share obtained business information with others, including advisors, financial officers, bankers, and contractors with a need to know. SoundExchange Ex. 004 DR sec. 10.01(a) (SONY BMG-MusicMatch Internet radio agreement); SoundExchange Ex. 002 DR sec. 9.01(a) (WMG-NextRadio Solutions webcasting license agreement). In the statutory licensing setting, copyright owners and performers are the licensors of their works to the Services and certainly need to know the information concerning the Services' payments. Providing the information only to SoundExchange, as the Services request, is not consistent with these agreements.
What is consistent with these agreements, however, is a prohibition of disclosure of statement of account information to the general public, and we are adopting that restriction.
SoundExchange requests four “clarifications” to the part 262 regulations regarding verification of royalty payments made by the Services: (1) That the Services should be required to maintain their books and records for the three prior calendar years (January to December) and the entirety of those three years may be audited; (2) persons other than Certified Public Accountants (“CPAs”) should be allowed to serve as auditors and need only be independent from the Service they are auditing; (3) individual copyright owners and performers, in addition to the Collective, should be permitted to audit Services; and (4) the threshold for allocating the costs of an audit should be reduced from a 10% underpayment to a 5% underpayment, or if the Service underpays by $5,000 or more. SoundExchange PFF ¶¶ at 1314, 1342. With the exception of the first request, the Copyright Royalty Judges decline to accept SoundExchange's proposals.
By eliminating the requirements that an auditor be a CPA and independent from SoundExchange, SoundExchange is seeking to transform the prior verification process into what it calls “technical audits.” SoundExchange PFF at ¶¶ 1327, 1328. Technical audits would, in SoundExchange's view, reduce its costs by allowing in-house technical experts to conduct the audits rather than outside CPAs, who might lack the technical capability for the data processing and analysis and may be more expensive than in-house personnel. 6/6/06 Tr. 269:16-273:4 (Kessler). The Copyright Royalty Judges have reviewed the record company/music service agreements submitted by the parties and note that some agreements permit technical audits. SoundExchange Ex. 002 DR sec. 5.02 (WMG-NextRadio Solutions webcasting license agreement); SoundExchange Ex. 003 DR sec. 4(b) (WMG-MusicNet subscription services agreement). Others, however, require the auditors to be CPAs, (SoundExchange Ex. 001 DR sec. 4.01 (WMG-All Media Guide clip license agreement), SoundExchange Ex. 014 DR sec. 3.7 (WMG-Muze clip license agreement)), and that the auditor be independent of both the licensor and licensee. SoundExchange Ex. 001 DR sec. 4.01 (WMG-All Media Guide clip license agreement); SoundExchange Ex. 004 DR sec. 6.05 (SONY BMG-MusicMatch Internet radio agreement); SoundExchange Ex. 007 DR sec. 8(b) (EMI—MusicNet nonportable subscription services agreement). While technical audits by in-house personnel might be cheaper for the Collective, we conclude that it is more important, in the interest of establishing a high level of credibility in the results of the audit, that the auditor be independent of both parties. 11/14/06 Tr. 9:8-11:11 (Levin). Likewise, we find that requiring the auditor to be certified further raises confidence levels in the audit. CPAs have experience in the field of accounting, are familiar with the accepted standards and practices for auditing, and are governed by standards of conduct. If technical skills are required to process the data of a Service, the auditor can request assistance. In sum, the Copyright Royalty Judges are requiring that the auditor be certified and independent of both SoundExchange and the Service being audited.
The Copyright Royalty Judges are not persuaded that all copyright owners and performers should have the right to audit a Service. It is one thing for a Service that enters into a private agreement with a copyright owner to allow the owner to conduct an audit. Kenswil WDT at 10-11; Eisenberg WDT at 13. It is an altogether different matter to grant the right of audit to copyright owners and performers under a statutory licensing scheme where there is no privity of contract and the potential for a significant magnitude of audits. We agree with the Services that subjecting them to that kind of extensive auditing process could seriously impair their business operations. Levin WRT at ¶ 30.
Likewise, we are not persuaded that the underpayment threshold for shifting the cost of an audit should be reduced from an underpayment of 10% to one of 5% of the royalty fee due, or $5,000, whichever is less. Ms. Kessler stated that the 10% figure was too high and encourages the Services to deliberately underpay their royalties up to 9%, but she did not offer any direct evidence of this occurring. Furthermore, the 10% figure is consistent with several of the record company/music service agreements. SoundExchange Ex. 003 DR sec. 6(f) (WMG-MusicNet subscription services agreement); SoundExchange Ex. 004 DR sec. 6.06 (SONY BMG-MusicMatch Internet radio agreement); SoundExchange 010 DR sec. 5(c) (EMI-Muze clip license agreement).
Finally, the Copyright Royalty Judges agree with SoundExchange that the Services should retain their books and records for the three calendar years prior to the current year. Services need to know with precision how long they must retain their books and records as well as the time period that is potentially subject to an audit.
Subsequent to the conclusion of the hearings on the direct statements, the Copyright Royalty Judges issued an Interim Final Rule in Docket No. RM 2005-2, the docket establishing notice and recordkeeping requirements for certain digital audio services using the section 112 and 114 licenses. Notice and Recordkeeping for Use of Sound Recordings Under Statutory License (Interim final rule), 71 FR 59010 (October 6, 2006). The Interim Final Rule prescribed the format and delivery requirements for reports of use of sound recordings, thereby completing the interim recordkeeping rulemaking process begun several years ago by the Copyright Office. Several of the parties in this proceeding, uncertain as to whether such recordkeeping issues would be addressed in this docket and noting the statutory language that permits the Copyright Royalty Judges to modify their existing recordkeeping rules, 17 U.S.C. 803(c)(3), submitted testimony on the matter. Although we ruled that recordkeeping matters would be addressed through notice and comment rulemaking and not in this proceeding, we did not strike the testimony. Instead, such testimony was allowed to remain in the record as evidence, if any, of the relative costs to the Services and the Collective associated with recordkeeping. Order Denying Radio Broadcasters' Motion for Clarification, Motion to Strike SoundExchange Exhibits 414-418 DP and Motion to Set Expedited Briefing Schedule, Docket No. 2005-1 CRB DTRA (September 8, 2006).
The costs of recordkeeping to both sides did not influence our determination of royalty rates in this proceeding, nor are we choosing to amend our existing recordkeeping regulations. See 37 CFR part 370. The testimony presented by the Services as to the costs associated with recordkeeping was vague and unsubstantiated and went little beyond the assertion that there are some costs associated with recordkeeping. Clearly,
Likewise, there was no persuasive testimony compelling an adjustment of the current recordkeeping regulations. SoundExchange presses for census reporting, but the record is incomplete as to effectiveness of the current periodic reporting requirement. Once again, the Copyright Royalty Judges conclude that this matter is more appropriate for a future recordkeeping rulemaking.
Having eschewed the Receiving Agent/Designated Agent model of the prior regulations in favor of a single Collective, we are adopting streamlined royalty distribution procedures. SoundExchange has the responsibility of collecting the royalties from the Services and distributing them to all eligible copyright owners and performers, including any agents designated by copyright owners and/or performers for their receipt. Deduction of costs by SoundExchange is governed by the statute, 17 U.S.C. 114(g)(3), and therefore we have no authority to address any resulting inequalities.
With respect to the distribution methodology, the Copyright Royalty Judges are retaining the requirement that all performances be valued equally by the Collective. SoundExchange is already familiar with and applies this requirement. 6/6/06 Tr. 171:2-172:10 (Kessler). Copyright owners and/or performers are certainly free to agree to subsequent distribution methodologies once they have received their distribution from the Collective.
Having fully considered the record, the Copyright Royalty Judges make the above Findings of Fact based on the record. Relying upon these Findings of Fact, the Copyright Royalty Judges unanimously adopt every portion of this Final Determination of the Rates and Terms of the Statutory Licenses for the digital audio transmission of sound recordings, pursuant to 17 U.S.C. 114, and for the making of ephemeral phonorecords, pursuant to 17 U.S.C. 112(e). The Copyright Royalty Judges exercise their authority under 17 U.S.C. 803(c), and transmit this Final Determination to the Librarian of Congress for publication in the
Copyright, Sound recordings.
17 U.S.C. 112(e), 114(f), 804(b)(3).
(a)
(b)
(c)
For purposes of this part, the following definitions shall apply:
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(1) Is exempt from taxation under section 501 of the Internal Revenue Code of 1986 (26 U.S.C. 501),
(2) Has applied in good faith to the Internal Revenue Service for exemption from taxation under section 501 of the Internal Revenue Code and has a commercially reasonable expectation that such exemption shall be granted, or
(3) Is operated by a State or possession or any governmental entity or subordinate thereof, or by the United States or District of Columbia, for exclusively public purposes.
(i)
(1) A performance of a sound recording that does not require a license (e.g., a sound recording that is not copyrighted);
(2) A performance of a sound recording for which the service has previously obtained a license from the Copyright Owner of such sound recording; and
(3) An incidental performance that both:
(i) Makes no more than incidental use of sound recordings including, but not limited to, brief musical transitions in and out of commercials or program segments, brief performances during news, talk and sports programming, brief background performances during disk jockey announcements, brief performances during commercials of sixty seconds or less in duration, or brief performances during sporting or other public events and
(ii) Other than ambient music that is background at a public event, does not contain an entire sound recording and does not feature a particular sound recording of more than thirty seconds (as in the case of a sound recording used as a theme song).
(j)
(k)
(l)
(a) Royalty rates and fees for eligible digital transmissions of sound recordings made pursuant to 17 U.S.C. 114, and the making of ephemeral recordings pursuant to 17 U.S.C. 112 are as follows:
(1)
(ii) Optional transitional Aggregate Tuning Hour fee for 2006-2007: The following Aggregate Tuning Hours (ATH) usage rate calculation options, in lieu of the per-performance fee, are available for the transition period of 2006 and 2007:
(iii) “Non-Music Programming” is defined as Broadcaster programming reasonably classified as news, talk, sports or business programming; “Broadcast Simulcast Programming” is defined as Broadcaster simulcast programming not reasonably classified as news, talk, sports or business programming; and “Other Programming” is defined as programming other than either Broadcaster simulcast programming or Broadcaster programming reasonably classified as news, talk, sports or business programming.
(2)
(ii) For all digital audio transmissions totaling in excess of 159,140 Aggregate Tuning Hours (ATH) in a month, including simultaneous digital audio retransmissions of over-the-air AM or FM radio broadcasts, a Noncommercial Webcaster will pay a performance royalty of: $.0008 per performance for 2006, $.0011 per performance for 2007, $.0014 per performance for 2008, $.0018 per performance for 2009, and $.0019 per performance for 2010.
(iii) The following Aggregate Tuning Hours (ATH) usage rate calculation options, in lieu of the per-performance fee, are available for the transition period of 2006 and 2007:
(iv) “Non-Music Programming” is defined as Broadcaster programming reasonably classified as news, talk, sports or business programming; “Broadcast Simulcast Programming” is defined as Broadcaster simulcast programming not reasonably classified as news, talk, sports or business programming; and “Other Programming” is defined as programming other than either Broadcaster simulcast programming or Broadcaster programming reasonably classified as news, talk, sports or business programming.
(v) The royalty payable under 17 U.S.C. 112 for any reproduction of a phonorecord made by a Noncommercial Webcaster during this license period and used solely by the Noncommercial Webcaster to facilitate transmissions for which it pays royalties as and when provided in this section is deemed to be included within such royalty payments.
(b)
(a)
(b)
(2) If SoundExchange, Inc. should dissolve or cease to be governed by a board consisting of equal numbers of representatives of Copyright Owners and Performers, then it shall be replaced by a successor Collective upon the fulfillment of the requirements set forth in paragraph (b)(2)(i) of this section.
(i) By a majority vote of the nine Copyright Owner representatives and the nine Performer representatives on the SoundExchange board as of the last day preceding the condition precedent in paragraph (b)(2) of this section, such representatives shall file a petition with the Copyright Royalty Board designating a successor to collect and distribute royalty payments to Copyright Owners and Performers entitled to receive royalties under 17 U.S.C. 112(e) or 114(g) that have themselves authorized such Collective.
(ii) The Copyright Royalty Judges shall publish in the
(c)
(d)
(1) Payment due under § 380.3(b) for 2006 and 2007 shall be due 45 days after the last day of the month in which the Copyright Royalty Judges issue their final determination adopting these rates and terms.
(2) Payment for a Licensee that has not previously made eligible nonsubscription transmissions, noninteractive digital audio transmissions as part of a new subscription service or Ephemeral Recordings pursuant to the licenses in 17 U.S.C. 114 and/or 17 U.S.C. 112(e) shall be due by the 45th day after the end of the month in which the Licensee commences to do so.
(e)
(f)
(1) Such information as is necessary to calculate the accompanying royalty payment;
(2) The name, address, business title, telephone number, facsimile number (if any), electronic mail address and other contact information of the person to be contacted for information or questions concerning the content of the statement of account;
(3) The handwritten signature of:
(i) The owner of the Licensee or a duly authorized agent of the owner, if the Licensee is not a partnership or corporation;
(ii) A partner or delegee, if the Licensee is a partnership; or
(iii) An officer of the corporation, if the Licensee is a corporation.
(4) The printed or typewritten name of the person signing the statement of account;
(5) The date of signature;
(6) If the Licensee is a partnership or corporation, the title or official position held in the partnership or corporation by the person signing the statement of account;
(7) A certification of the capacity of the person signing; and
(8) A statement to the following effect:
I, the undersigned owner or agent of the Licensee, or officer or partner, have examined this statement of account and hereby state that it is true, accurate, and complete to my knowledge after reasonable due diligence.
(g)
(2) If the Collective is unable to locate a Copyright Owner or Performer entitled to a distribution of royalties under paragraph (g)(1) of this section within 3 years from the date of payment by a Licensee, such distribution may first be applied to the costs directly attributable to the administration of that distribution. The foregoing shall apply notwithstanding the common law or statutes of any State.
(h)
(a)
(b)
(c)
(d)
(1) Those employees, agents, attorneys, consultants and independent contractors of the Collective, subject to an appropriate confidentiality agreement, who are engaged in the collection and distribution of royalty payments hereunder and activities related thereto, for the purpose of performing such duties during the ordinary course of their work and who require access to the Confidential Information;
(2) An independent and Qualified Auditor, subject to an appropriate confidentiality agreement, who is authorized to act on behalf of the Collective with respect to verification of a Licensee's statement of account pursuant to § 380.6 or on behalf of a Copyright Owner or Performer with respect to the verification of royalty distributions pursuant to § 380.7;
(3) Copyright Owners and Performers, including their designated agents, whose works have been used under the statutory licenses set forth in 17 U.S.C. 112(e) and 114(f) by the Licensee whose Confidential Information is being supplied, subject to an appropriate confidentiality agreement, and including those employees, agents, attorneys, consultants and independent contractors of such Copyright Owners and Performers and their designated agents, subject to an appropriate confidentiality agreement, for the purpose of performing their duties during the ordinary course of their work and who require access to the Confidential Information; and
(4) In connection with future proceedings under 17 U.S.C. 112(e) and 114(f) before the Copyright Royalty Judges, and under an appropriate protective order, attorneys, consultants and other authorized agents of the parties to the proceedings or the courts.
(e)
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(a)
(b)
(c)
(d)
(e)
(f)
(g)
If the Collective is unable to identify or locate a Copyright Owner or Performer who is entitled to receive a royalty distribution under this part, the Collective shall retain the required payment in a segregated trust account for a period of 3 years from the date of distribution. No claim to such distribution shall be valid after the expiration of the 3-year period. After expiration of this period, the Collective may apply the unclaimed funds to offset any costs deductible under 17 U.S.C. 114(g)(3). The foregoing shall apply notwithstanding the common law or statutes of any State.
Centers for Medicare & Medicaid Services (CMS), HHS.
Proposed rule.
This proposed rule would set forth the hospice wage index for fiscal year 2008. This proposed rule would also revise the methodology for updating the wage index for rural areas without hospital wage data and provide clarification of selected existing Medicare hospice regulations and policies.
To be assured consideration, comments must be received at one of the addresses provided below, no later than 5 p.m. on July 2, 2007.
In commenting, please refer to file code CMS-1539-P. Because of staff and resource limitations, we cannot accept comments by facsimile (FAX) transmission.
You may submit comments in one of four ways (no duplicates, please):
1.
2.
Please allow sufficient time for mailed comments to be received before the close of the comment period.
3.
4.
(Because access to the interior of the HHH Building is not readily available to persons without Federal Government identification, commenters are encouraged to leave their comments in the CMS drop slots located in the main lobby of the building. A stamp-in clock is available for persons wishing to retain a proof of filing by stamping in and retaining an extra copy of the comments being filed.)
Comments mailed to the addresses indicated as appropriate for hand or courier delivery may be delayed and received after the comment period.
For information on viewing public comments, see the beginning of the
Terri Deutsch, (410) 786-9462.
Comments received timely will also be available for public inspection as they are received, generally beginning approximately 3 weeks after publication of a document, at the headquarters of the Centers for Medicare & Medicaid Services, 7500 Security Boulevard, Baltimore, Maryland 21244, Monday through Friday of each week from 8:30 a.m. to 4 p.m. To schedule an appointment to view public comments, phone 1-800-743-3951.
Hospice care is an approach to treatment that recognizes that the impending death of an individual warrants a change in the focus from curative care to palliative care for relief of pain and for symptom management. The goal of hospice care is to help terminally ill individuals continue life with minimal disruption to normal activities while remaining primarily in the home environment. A hospice uses an interdisciplinary approach to deliver medical, social, psychological, emotional, and spiritual services through use of a broad spectrum of professional and other caregivers, with the goal of making the individual as physically and emotionally comfortable as possible. Counseling services and inpatient respite services are available to the family of the hospice patient. Hospice programs consider both the patient and the family as a unit of care.
Section 1861(dd) of the Social Security Act (the Act) provides for coverage of hospice care for terminally ill Medicare beneficiaries who elect to receive care from a participating hospice. Section 1814(i) of the Act provides payment for Medicare participating hospices.
Our regulations at 42 CFR part 418 establish eligibility requirements, payment standards and procedures, define covered services, and delineate the conditions a hospice must meet to be approved for participation in the Medicare program. Part 418 subpart G provides for payment in one of four prospectively-determined rate categories (routine home care, continuous home care, inpatient respite care, and general inpatient care) to hospices based on each day a qualified Medicare beneficiary is under a hospice election.
Our regulations at § 418.306(c) require each hospice's labor market to be established using the most current hospital wage data available, including any changes to the Metropolitan Statistical Areas (MSAs) definitions, which have been superseded by Core Based Statistical Areas (CBSAs). Section 1814(i)(2)(D) of the Act requires Medicare to pay for hospice care furnished in an individual's home on
The hospice wage index is used to adjust payment rates for hospice agencies under the Medicare program to reflect local differences in area wage levels. The original hospice wage index was based on the 1981 Bureau of Labor Statistics hospital data and had not been updated since 1983. In 1994, because of disparity in wages from one geographical location to another, a committee was formulated to negotiate a wage index methodology that could be accepted by the industry and the government. This committee, functioning under a process established by the Negotiated Rulemaking Act of 1990, was comprised of national hospice associations; rural, urban, large and small hospices; multi-site hospices; consumer groups; and a government representative. On April 13, 1995, the Hospice Wage Index Negotiated Rulemaking Committee signed an agreement for the methodology to be used for updating the hospice wage index.
In the August 8, 1997
The annual update to the hospice wage index is published in the
Raw wage index values (that is, inpatient hospital pre-floor and pre-reclassified wage index values) as described in the August 8, 1997 hospice wage index final rule (62 FR 42860), are subject to either a budget neutrality adjustment or application of the wage index floor. Raw wage index values of 0.8 or greater are adjusted by the budget neutrality adjustment factor. Budget neutrality means that, in a given year, estimated aggregate payments for Medicare hospice services using the updated wage index values will equal estimated payments that would have been made for these services if the 1983 wage index values had remained in effect. To achieve this budget neutrality, the raw wage index is multiplied by a budget neutrality adjustment factor. The budget neutrality adjustment factor is calculated by comparing what we would have paid using current rates and the 1983 wage index to what would be paid using current rates and the new wage index. The budget neutrality adjustment factor is computed and applied annually. For the FY 2008 hospice wage index in the proposed rule, FY 2007 hospice payment rates were used in the budget neutrality adjustment factor calculation.
Raw wage index values below 0.8 are adjusted by the greater of: (1) The hospice budget neutrality adjustment factor; or (2) the hospice wage index floor (a 15 percent increase) subject to a maximum wage index value of 0.8. For example, if County A has a pre-floor, pre-reclassified hospital wage index (raw wage index value) of 0.4000, we would perform the following calculations using the budget neutrality factor (which for this example is 1.060988) and the hospice wage index floor to determine County A's hospice wage index:
Raw wage index value below 0.8 multiplied by the budget neutrality adjustment factor: (0.4000 × 1.060988 = 0.4244).
Raw wage index value below 0.8 multiplied by the hospice wage index floor: (0.4000 × 1.15 = 0.4600).
Based on these calculations, County A's hospice wage index would be 0.4600.
Section 4441(a) of the Balanced Budget Act of 1997 (BBA) amended section 1814(i)(1)(C)(ii) of the Act to establish updates to hospice rates for FYs 1998 through 2002. Hospice rates were to be updated by a factor equal to the market basket index, minus 1 percentage point. However, neither the BBA nor subsequent legislation specified the market basket adjustment to be used to compute payment for FY 2008. Therefore, payment rates for FY 2008 will be updated according to section 1814(i)(1)(C)(ii)(VII) of the Act, which states that the update to the payment rates for subsequent FYs will be the market basket percentage for the fiscal year. Accordingly, the FY 2008 update to the payment rates will be the full market basket percentage increase for FY 2008. This rate update is implemented through a separate administrative instruction and is not part of this notice. Historically, the rate update has been published through a separate administrative instruction issued annually in July to provide adequate time to implement system change requirements. Providers determine their payment rates by applying the wage index in this notice to the labor portion of the published hospice rates.
As discussed above, the hospice payment rates are adjusted each year based upon the full hospital market basket. In the FY 2007 update notice (72 FR 52082) issued on September 1, 2006, we indicated that beginning in April 2006, with the publication of March 2006 data, the Bureau of Labor Statistic's (BLS's) Employment Cost Index (ECI) began using a different classification system, the North American Industrial Classification System (NAICS), instead of the Standard Industrial Classification System (SIC), which no longer exists. The ECIs had been used as the data source for wages and salaries and other price proxies in the hospital market basket. In the FY 2007 update notice we noted that no changes would be made to the usage of the NAICS-based ECI, however, input was solicited on this issue. We received
The hospice wage index presented in this proposed rule would be effective October 1, 2007 through September 30, 2008. We note that we are not proposing any modifications to the hospice wage index methodology. In accordance with our regulations and the agreement signed with other members of the Hospice Wage Index Negotiated Rulemaking Committee, we are using the most current hospital data available to us. For this proposed rule, the FY 2007 hospital wage index was the most current hospital wage data available for calculating the FY 2008 hospice wage index values. We used the FY 2007 pre-reclassified and pre-floor hospital area wage index data for this calculation.
Payment rates for each of the four levels of care are adjusted annually based upon the hospital market basket for that year and are promulgated administratively to allow for sufficient time for system changes and provider notification. Due to the need to ensure appropriate time for implementing changes, the latest adjustments to these payment rates were not incorporated into this proposed rule.
As noted above, for FY 2008, the hospice wage index values will be based solely on the adoption of the CBSA-based labor market definitions and its wage index. We continue to use the most recent pre-floor and pre-reclassified hospital wage index data available (FY 2003 hospital wage data).
A detailed description of the methodology used to compute the hospice wage index is contained in both the September 4, 1996 proposed rule (61 FR 46579) and the August 8, 1997 final rule (62 FR 42860). All wage index values are adjusted by a budget-neutrality factor of 1.066028 and are subject to the wage index floor adjustment, if applicable. We completed all of the calculations described in section 2.B below and included them in the wage index values reflected in Tables A and B of the Addendum. Specifically, Table A reflects the FY 2008 wage index values for urban areas under the CBSA designations. Table B reflects the FY 2008 wage index values for rural areas under the CBSA designations.
(If you choose to comment on issues in this section, please include the caption “Rural Areas without Wage Data” at the beginning of your comments.)
When adopting OMB's new labor market designations, we identified some geographic areas where there were no hospitals, and thus, no hospital wage index data on which to base the calculation of the hospice wage index (70 FR 45135, August 4, 2005). For FY 2006 and FY 2007, we adopted a policy to use the FY 2005 pre-floor, pre-reclassified hospital wage index value for rural areas when no rural hospital wage data were available. We also adopted the policy that for urban labor markets without an urban hospital from which a hospital wage index data could be derived, all of the CBSAs within the State would be used to calculate a statewide urban average wage index data to use as a reasonable proxy for these areas. We did not receive any public comments regarding our policy to calculate an urban wage index, using an average of all of the urban CBSA wage index data within the State, for urban labor markets without an urban hospital from which a hospital wage index could be derived. Consequently, in the August 2005 final rule and in the August 2006 update notice, we applied the average wage index data from all urban areas lacking hospital wage data in that state. Currently, the only CBSA that is affected by this is CBSA 25980 Hinesville-Fort Stewart, Georgia. We propose to continue this approach for urban areas where there are no hospitals and, thus, no hospital wage index data on which to base the calculations for the FY 2008 and subsequent hospice wage indexes. Therefore, the pre-floor, pre-reclassified wage index data for urban CBSA 25980, Hinesville-Fort Stewart, GA is calculated as the average wage index data of all urban areas in Georgia with a value of 0.9178.
Under the CBSA labor market areas, there are no rural hospitals in rural locations in Massachusetts and Puerto Rico. Since there was no rural proxy for more recent rural data within those areas, in the August 2005 proposed rule (70 FR 45135), we proposed applying the FY 2005 pre-floor, pre-reclassified hospital wage index value to rural areas where no hospital wage data are available. We did not receive any public comments on this matter, either. Consequently, in the August 2005 final rule and in the August 2006 update notice, we applied the FY 2005 pre-floor, pre-reclassified hospital wage index data for rural areas lacking hospital wage data in that state in both FY 2006 and FY 2007 for rural Massachusetts and rural Puerto Rico.
Since we have used the same wage index value from FY 2005 for these areas for the previous two fiscal years, we believe it is appropriate to consider alternatives in our methodology to update the wage index for rural areas without hospital wage index data. We believe that the best imputed proxy for rural areas, would: (1) Use pre-floor, pre-reclassified hospital data; (2) use the most local data available to impute a rural wage index; (3) be easy to evaluate; and, (4) be easy to update from year-to-year. Although our current methodology uses local, rural pre-floor, pre-reclassified hospital wage data, this method cannot be updated from year-to-year.
Therefore, in cases where there is a rural area without rural hospital wage data, we propose using the average pre-floor, pre-reclassified wage index data from all contiguous CBSAs to represent a reasonable proxy for the rural area. While this approach does not use rural data, it does use pre-floor, pre-reclassified hospital wage data, it is easy to evaluate, it is easy to update from year-to-year, and it uses the most local data available.
In determining an imputed rural wage index, we interpret the term contiguous to mean as sharing a border. For example, in the case of Massachusetts, the entire rural area consists of Dukes and Nantucket counties. We have determined that the borders of Dukes and Nantucket counties are contiguous with Barnstable and Bristol counties. Under the proposed methodology, the pre-floor, pre-reclassified wage index values for the counties of Barnstable (CBSA 12700, Barnstable Town, MA) of 1.2539 and Bristol (CBSA 39300, Providence-New Bedford-Fall River, RI-MA) of 1.0783 would be averaged resulting in an imputed pre-floor, pre-reclassified rural wage index of 1.1661 for rural Massachusetts for FY 2008. The impact of utilizing the proposed methodology is captured in the impact analysis (Table 1). As shown in Table B, the proposed wage index value for FY 2008 for rural Massachusetts is 1.2431. If we had retained the current methodology, the rural Massachusetts wage index would have been 1.0891.
While we believe that this policy could be readily applied to other rural areas that lack hospital wage data (possibly due to hospitals converting to a different provider type, such as a CAH, that do not submit the appropriate wage data), should a similar situation arise in the future, we may re-examine this policy.
However, we do not believe that this policy would be appropriate for Puerto Rico. There are sufficient economic
(If you choose to comment on issues in this section, please include the caption “Nomenclature Changes” at the beginning of your comments.)
In the August 4, 2005 final rule and in the September 1, 2006 update notice, we noted that the Office of Management and Budget (OMB) published a bulletin that changed the titles to certain CBSAs. Since the publication of the Hospice FY 2006 update notice, OMB published additional bulletins that updated the CBSAs. Specifically, OMB added or deleted certain CBSA numbers and revised certain titles. Accordingly, in this proposed rule, we are proposing to clarify that this and all subsequent Hospice rules and notices are considered to incorporate the CBSA changes published in the most recent OMB bulletin, that applies to the hospital wage data used to determine the current hospice wage index. The proposed tables reflect changes made by these bulletins. The OMB bulletins may be accessed at
(If you choose to comment on issues in this section, please include the caption “Site of Service” at the beginning of your comments)
Hospice providers receive payment for four levels of care based upon the individual's needs. Section 4442 of the BBA amended section 1814(i)(2) of the Act, effective for services furnished on or after October 1, 1997, required the application of the local wage index value of the geographic location at which the service is furnished for hospice care provided in the home. This provision has been codified in our regulations at 418.302(g). Prior to this provision, local wage index values were applied based on the geographic location of the hospice provider, regardless of where the hospice care was furnished. We believe that for the majority of hospice providers the office and the site for the provision of home and inpatient care occur in the same geographic area. However, with the substantial growth of hospice providers in multiple states and with multiple sites within a State, hospice providers have been able to inappropriately maximize reimbursement by locating their offices in high-wage areas and delivering services in a lower-wage area. We also believe that hospice providers are also able to inappropriately maximize reimbursement by locating their inpatient services either directly or under contractual arrangements in lower wage areas than their offices.
Section 4442 of the BBA applies the wage index value of a home's geographic location for services provided there, but is silent as to what wage index value should be used for hospice services provided in an inpatient setting. We believe that the application of the wage index values, for rate adjustments on the geographic area, where the hospice care is furnished provides a reimbursement rate that is a more accurate reflection of the wages paid by the hospice for the staff used to furnish care. We also believe that payment should reflect the location of the services provided and not the location of an office.
As a result, we are proposing that effective January 1, 2008, all payment rates (routine home care, continuous home care, inpatient respite and general inpatient care) be adjusted by the geographic wage index value of the area where hospice services are provided. In other words, the wage component of each payment rate is multiplied by the wage index value applicable to the location in which the hospice services are provided. We are proposing to amend 418.302(g) to reflect this proposed change.
Currently, hospice claims do not contain information identifying the location of the facility where general inpatient and respite care are provided. Therefore, we are unable to predict the savings or costs associated with the changes associated with this proposed provision. However, we believe that the impact of implementing this proposal will be negligible.
(If you choose to comment on issues in this section, please include the caption “Nurse Practitioners” at the beginning of your comments.)
On December 8, 2003, the Congress enacted the Medicare Prescription Drug, Improvement, and Modernization Act (MMA) of 2003 (Pub. L. 108-173). Section 408 of the MMA, Recognition of Attending Nurse Practitioners as Attending Physicians to Serve Hospice Patients, amended sections 1861(dd)(3)(B) and 1814(a)(7) of the Act to add nurse practitioners (NPs) to the definition of an attending physician for beneficiaries who have elected the hospice benefit. Section 408 of the MMA was implemented through an administrative issuance (Change Request (CR) 3226, Transmittals 22 and 304, September 24, 2004).
In the FY 2006 Final Rule (70 FR 45130, August 4, 2005), we revised § 418.3 to implement the provisions of section 408 of the MMA. Section 418.3 indicated (under clause (1)(ii) of the definition of “attending physician”) that the nurse practitioner “* * * meet the training, education, and experience requirements as the Secretary may prescribe * * *”. We believe that the definition for nurse practitioners under the Medicare hospice benefit should reflect the definition as established for the Medicare benefit found at § 410.75. To ensure consistency, we propose to revise the definition of “attending physician” at § 418.3 to cross reference the requirement in § 410.75(b).
(If you choose to comment on issues in this section, please include the caption “Care Giver and General Inpatient Care” at the beginning of your comments.)
The Medicare hospice benefit places emphasis on the provision of items and services to enable an individual to remain at home in the company of family and friends. Section 1861(dd)(1)(G) of the Act provides for short term inpatient hospice care to be available when an individual's pain and symptoms must be closely monitored or the intensity of interventions that are required cannot be provided in any other settings. In recognition of the stress in providing care for an
Medicare policy as described in chapter 9 of the Medicare Benefit Policy Manual, states that skilled nursing care may be required by a patient whose home support has broken down, if this breakdown makes it no longer feasible to furnish needed care in the home setting. If the hospice and the caregiver, working together, are no longer able to provide the necessary skilled nursing care in the individual's home, and if the individual's pain and symptom management can no longer be provided at home, then the individual may be eligible for a short term general inpatient level of care. However, it has come to our attention that some hospice providers are requesting payment for the “general inpatient” level of care for circumstances that do not qualify under the statute, our regulations at § 418.202(e) or Medicare hospice policy. In other words, some hospices are billing Medicare for “caregiver breakdown” at the higher “general inpatient” level, rather than the lower payment for “inpatient respite” or “routine home care” levels of care.
To receive payment for “general inpatient care” under the Medicare hospice benefit, beneficiaries
As explained, this is a clarification of current Medicare policy and is not anticipated to create new limitations on access to hospice care. However, we are clarifying that the level of care provided, not the location of care, is what determines the appropriate level of payment. Additionally, the circumstances addressed with this policy, and the clarification discussed above, should not be construed as similar to situations where an individual does not have family or friends or other means that are able to take on the role of a caregiver when a hospice election is made. The Medicare hospice benefit provides for care that is medically reasonable and necessary for the palliation and management of the terminal and related conditions, and is structured in such a way to enable the individual with a terminal condition to remain at home, as long as possible, in the company of family and friends. We recognize the difficulties surrounding the provision of hospice care to an individual who is terminally ill and who does not have caregivers at home. This may be a challenge in rural areas. Section 409 of the MMA established the Rural Hospice Demonstration which hopes to test alternative mechanisms for providing hospice services for beneficiaries who lack an appropriate caregiver and who reside in rural areas. However, we intend to monitor the usage of the general inpatient care.
We are providing this as clarification and therefore are not proposing any changes in existing statute, regulation or policy manual.
(If you choose to comment on issues in this section, please include the caption “Certification” at the beginning of your comments.)
Section 1814(a)(7)(A)(i) of the Act stipulates that the individual's attending physician and the hospice medical director initially certify the individual's terminal diagnosis with prognosis of six months or less if the disease runs its normal course. The requirements of the physician certification, including supportive documentation were discussed in the hospice care amendment proposed rule (67 CFR 70363) and final rule (70 CFR 70548). In these rules, we indicated that a direct consultation between the hospice medical director and the attending physician was not a requirement and that information supporting the terminal diagnosis could be obtained through the hospice admission nurse. We are aware that the intent of this has been construed by some providers, to permit the admission nurse, utilizing documents such as local coverage decisions, to determine eligibility for hospice services and certify the individual's terminal diagnosis. This interpretation is incorrect. We have permitted the hospice nurses to obtain information to be used by the hospice medical director as part of the medical documents used in his or her determination of the terminal diagnosis and eligibility for the Medicare hospice benefit. The statute is explicit in the requirement that the physician and medical director determine the prognosis and his or her signature on the certification attests to that fact. We will provide further clarification in administrative instructions.
This document does not impose any information collection and recordkeeping requirements. Consequently, it need not be reviewed by the Office of Management and Budget under the authority of the Paperwork Reduction Act of 1995 (44 U.S.C. 35).
Because of the large number of public comments we normally receive on
We have examined the impacts of this proposed rule as required by Executive Order 12866 (September 1993, Regulatory Planning and Review), the Regulatory Flexibility Act (RFA) (September 19, 1980, Pub. L. 96-354), section 1102(b) of the Act, the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4), and Executive Order 13132. We estimated the impact on hospices, as a result of the proposed changes to the FY 2008 hospice wage index. As discussed previously, the methodology for computing the wage index was determined through a negotiated rulemaking committee and implemented in the August 8, 1997 final rule (62 FR 42860). This proposed rule updates the hospice wage index in accordance with our regulation and that methodology, incorporating the adoption of the CBSA designations used in the FY 2007 hospital wage index data.
• Table 1 categorizes the impact on hospices by various geographic and provider characteristics. We estimate that the total hospice payments will decrease $538,000 as a result of the proposed FY 2008 wage index values. We anticipate that the final rule will more accurately project payment for FY 2008, based upon changes in the wage index values.
• Table A reflects the FY 2008 wage index values for urban areas designations.
• Table B reflects the FY 2008 wage index values for rural areas designations.
Executive Order 12866 (as amended by Executive Order 13258, which merely reassigns responsibility of duties) directs agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). A regulatory impact analysis (RIA) must be prepared for major rules with economically significant effects ($100 million or more in any 1 year). We have determined that this notice is not an economically significant rule under this Executive Order.
The RFA requires agencies to analyze options for regulatory relief of small businesses. For purposes of the RFA, small entities include small businesses, nonprofit organizations, and small governmental jurisdictions. Most hospices and most other providers and suppliers are small entities, either by nonprofit status or by having revenues of $6.5 million to $31.5 million in any 1 year (for details, see the Small Business Administration's regulation at 65 FR 69432, that sets forth size standards for health care industries). For purposes of the RFA, most hospices are small entities. As indicated in Table 1 below, there are 2,819 hospices. Approximately 81 percent of Medicare certified hospices are identified as voluntary, government, or other agencies and, therefore, are considered small entities. Because the National Hospice and Palliative Care Organization estimates that approximately 79 percent of hospice patients are Medicare beneficiaries, we have not considered other sources of revenue in this analysis. Furthermore, the wage index methodology was previously determined by consensus, through a negotiated rulemaking committee that included representatives of national hospice associations; rural, urban, large and small hospices; multi-site hospices; and consumer groups. Based on all of the options considered, the committee agreed on the methodology described in the committee statement, and it was adopted into regulation in the August 8, 1997 final rule. In developing the process for updating the wage index in the 1997 final rule, we considered the impact of this methodology on small entities and attempted to mitigate any potential negative effects.
In addition, section 1102(b) of the Act requires us to prepare a regulatory impact analysis if a rule may have a significant impact on the operations of a substantial number of small rural hospitals. This analysis must conform to the provisions of section 603 of the RFA. For purposes of section 1102(b) of the Act, we define a small rural hospital as a hospital that is located outside a CBSA and has fewer than 100 beds. We have determined that this notice would not have a significant impact on the operations of a substantial number of small rural hospitals. We are not preparing an analysis for the RFA because we have determined that this rule will not have a significant economic impact on a substantial number of small entities.
Section 202 of the Unfunded Mandates Reform Act of 1995 also requires that agencies assess anticipated costs and benefits before issuing any rule that may result in expenditure in any 1 year by State, local, and tribal governments, in the aggregate, or by the private sector, of $120 million or more. This notice is not anticipated to have an effect on State, local, or tribal governments or on the private sector of $120 million or more.
Executive Order 13132 establishes certain requirements that an agency must meet when it promulgates a proposed rule (and subsequent final rule) that imposes substantial direct requirement costs on State and local governments, preempts State law, or otherwise has Federalism implications. We have reviewed this notice under the threshold criteria of Executive Order 13132, Federalism, and have determined that it would not have an impact on the rights, roles, and responsibilities of State, local, or tribal governments.
In accordance with the provisions of Executive Order 12866, this regulation was reviewed by the Office of Management and Budget.
We are unable to quantify the extent of the usage of the general inpatient level of care in the event of caregiver breakdown and are, therefore, unable to definitively anticipate the impact of our clarification of the general inpatient level of care policy in the event of caregiver breakdown. For this reason, we solicit comment on what the impact of our clarification might be. Based on anecdotal evidence as well as substantial increases in the number of claims submitted for general inpatient care, however, we believe a small proportion of patient days attributed to general inpatient care would be appropriately allocated to inpatient respite care with this clarification. Significant savings could be realized even if only a small proportion of patient days attributed to general inpatient care were allocated to inpatient respite care.
For example, to determine the impact of allocating 5.0 percent of general inpatient care days to inpatient respite care, we used the FY 2005 patient days, expenditures and number of beneficiaries electing the hospice benefit to estimate the impact of the clarification of existing policy in this proposed rule. The number of inpatient days was adjusted from 1,250,678 to 1,188,144. The number of inpatient respite days was adjusted from 96,646 to 159,180. While inpatient respite expenditures increased from $14,000,000 to $23,058,570, general inpatient care expenditures decreased from $737,300,000 to $700,435,000. In total, if 5.0 percent of patient days that were attributed to general inpatient care in FY 2005 were allocated to the inpatient respite level of care, it would have resulted in net savings of $27,806,430.
The impact analysis of this notice represents the projected effects of the changes in the hospice wage index from FY 2007 to FY 2008. We estimate the effects by estimating payments for FY 2008 utilizing the FY 2007 wage index values and the full implementation of the CBSA designations while holding all other payment variables constant.
We note that certain events may combine to limit the scope or accuracy of our impact analysis, because such an analysis is future oriented and, thus, susceptible to forecasting errors due to other changes in the forecasted impact time period. The nature of the Medicare program is such that the changes may interact, and the complexity of the interaction of these changes could make it difficult to predict accurately the full scope of the impact upon hospices.
For the purposes of this proposed rule, we compared estimated payments using the FY 1983 hospice wage index to estimated payments using the FY 2008 wage index and determined the hospice wage index to be budget neutral. Budget neutrality means that, in a given year, estimated aggregate payments for Medicare hospice services using the FY 2008 wage index would equal estimated aggregate payments that would have been made for the same services if the 1983 wage index had remained in effect. Budget neutrality to 1983 does not imply that estimated payments would not increase since the
As discussed above, we use the latest claims file available to us to develop the impact table when we issue the annual yearly wage index update. For the purposes of this proposed rule, data were obtained from the National Claims History file using FY 2005 claims processed through June 2006, which were the most recent available data. We deleted bills from hospice providers that have since closed. For the purposes of this proposed rule, this file is adequate to demonstrate the impact of the FY 2008 wage index values and is not intended to project the anticipated expenditures for FY 2008. We anticipate that the final rule will more accurately project payment for FY 2008. This impact analysis compares hospice payments using the FY 2007 hospice wage index to the estimated payments using the FY 2008 wage index. We note that estimated payments for FY 2008 are determined by using the wage index for FY 2008 and payment rates for FY 2007. As noted in previous sections, payment rates for FY 2008 are published through administrative issuance.
Table 1 demonstrates the results of our analysis. In column 1 we indicate the number of hospices included in our analysis. In column 2, we indicate the number of routine home care days that were included in our analysis, although the analysis was performed on all types of hospice care. Column 3 estimates payments using the FY 2007 wage index values and the FY 2007 payment rates. Column 4 estimates payments using FY 2008 wage index values as well as the FY 2007 payment rates. Column 5 compares columns 3 and 4 and shows the percentage change in estimated hospice payments made based on the hospice category.
Table 1 also categorizes hospices by various geographic and provider characteristics. The first row displays the aggregate result of the impact for all Medicare-certified hospices. The second and third rows of the table categorize hospices according to their geographic location (urban and rural). Our analysis indicated that there are 1,858 hospices located in urban areas and 961 hospices located in rural areas. The next two groupings in the table indicate the number of hospices by census region, also broken down by urban and rural hospices. The sixth grouping shows the impact on hospices based on the size of the hospice's program. We determined that the majority of hospice payments are made at the routine home care rate. Therefore, we based the size of each individual hospice's program on the number of routine home care days provided in FY 2006. The next grouping shows the impact on hospices by type of ownership. The final grouping shows the impact on hospices defined by whether they are provider-based or freestanding. As indicated in Table 1 below, there are 2,819 hospices. Approximately 81 percent of Medicare-certified hospices are identified as voluntary, government, or other agencies and, therefore, are considered small entities. Because the National Hospice and Palliative Care Organization estimates that approximately 79 percent of hospice patients are Medicare beneficiaries, we have not considered other sources of revenue in this analysis. Furthermore, the wage index methodology was previously determined by consensus, through a negotiated rulemaking committee that included representatives of national hospice associations; rural, urban, large, and small hospices; multi-site hospices; and consumer groups. Based on all of the options considered, the committee agreed on the methodology described in the committee statement, and it was adopted into regulation in the August 8, 1997 final rule. In developing the process for updating the wage index in the 1997 final rule, we considered the impact of this methodology on small entities and attempted to mitigate any potential negative effects.
As stated previously, the following discussions are limited to demonstrating trends rather than projected dollars. We used the CBSA designations and wage indices as well as the data from FY 2005 claims processed through June 2006 in developing the impact analysis. For FY 2008 the wage index is the variable that differs between the FY 2007 payments and the FY 2008 estimated payments. FY 2007 payment rates are used for both FY 2007 actual payments and the FY 2008 estimated payments. The FY 2008 payment rates will be adjusted to reflect the full FY 2007 hospital market basket, as required by section 1814(i)(1)(C)(ii)(VII) of the Act. As previously noted, we publish these rates through administrative issuances.
As discussed in the FY 2006 final rule (70 FR 45129), hospice agencies may utilize multiple wage indices to compute their payments based on potentially different geographic locations of the beneficiary for routine and continuous home care or the CBSA for the location of the hospice agency for respite and general inpatient care. For this analysis, we use payments to the hospice in the aggregate based on the location of the hospice. The impact of hospice wage index changes have been analyzed according to the type of hospice, geographic location, type of ownership, hospice base, and size.
Our analysis shows that most hospices are in urban areas and provide the vast majority of routine home care days. Most hospices are medium sized followed by large hospices. Hospices are almost equal in numbers by ownership with 1,231 designated as non-profit and 1,265 as proprietary. The vast majority of hospices are freestanding.
Under the Medicare hospice benefit, hospices can provide four different levels of care days. The majority of the days provided by a hospice are routine home care days (RHC) representing over 70 percent of the services provided by a hospice. Therefore, the number of routine home care days can be used as a proxy for the size of the hospice, that is, the more days of care provided, the larger the hospice. As discussed in the August 4, 2005 final rule, we currently use three size designations to present the impact analyses. The three categories are: Small agencies having 0 to 3,499 RHC days; medium agencies having 3,500 to 19,999 RHC days; and large agencies having 20,000 or more RHC days. Using RHC days as a proxy for size, our analysis indicates that the proposed FY 2008 wage index values are anticipated to have virtually no impact on hospice providers, with a slight decrease of 0.1 percent anticipated for small hospices while no change is anticipated for medium or large hospices.
Our analysis demonstrates that the proposed FY 2008 wage index values will result in little change in estimated payments with urban hospices anticipated to experience no change while rural hospices are anticipated to experience a slight increase of 0.2 percent. The greatest increase of 0.9 percent is anticipated to be experienced by the Mountain regions, followed by an increase for East North Central of 0.6 percent and Pacific regions of 0.5 percent. The remaining urban regions are anticipated to experience a decrease ranging from 0.6 percent in the East South Central region to 0.1 percent in the Middle Atlantic region. The greatest decrease of 2.6 percent is anticipated for Puerto Rico.
For rural hospices, the South Atlantic region and Puerto Rico are anticipated to experience no change. Two regions are anticipated to experience a decrease of 0.9 percent for New England and 0.4 percent for the mountain regions. The
By type of ownership, non-profit hospices are anticipated to experience no change in payment while government hospices are anticipated to experience a slight increase of 0.1 percent. Slight decreases are anticipated for proprietary hospices of 0.1 percent and 0.2 percent for other categories.
For hospice-based facilities, a decrease of 0.1 percent in payment is anticipated for freestanding facilities. Home health, hospital and skilled nursing facilities area anticipated to experience an increase of 0.1, 0.2 and 0.7 percent respectively.
Our impact analysis compared hospice payments by using the FY 2007 wage index to the estimated payments using the FY 2008 wage index. Through the analysis, we estimate that total hospice payments will effectively be budget neutral with a negligible decrease from FY 2007 by $538,000. Additionally, we compared estimated payments using the FY 1983 hospice wage index to estimated payments using the FY 2008 wage index and determined the current hospice wage index to be budget neutral, as required by the negotiated rulemaking committee. As noted above, the payment rates used reflect the FY 2007 rates. The FY 2008 payment rates will be adjusted to reflect the full FY 2008 hospital market basket, as required by section 1814(i)(1)(C)(ii)(VII) of the Act. We publish these rates through administrative issuances.
In accordance with the provisions of Executive Order 12866, this regulation was reviewed by the Office of Management and Budget.
Health facilities, Hospice care, Medicare, Reporting and recordkeeping requirements.
For the reasons set forth in the preamble, the Centers for Medicare & Medicaid Services would amend 42 CFR part 418 as set forth below:
1. The authority citation for part 418 continues to read as follows:
Secs. 1102 and 1871 of the Social Security Act (42 U.S.C. 1302 and 1395hh).
2. Section 418.3 is amended by revising paragraph (1)(ii) in the definition of “attending physician” to read as follows:
(ii) Nurse practitioner who meets the training, education, and experience requirements as described in § 410.75 (b).
3. Section 418.302 is amended by revising paragraph (g) to read as follows:
(g) Payment for routine home care, continuous home care, general inpatient care and inpatient respite care is made on the basis of the geographic location where the services are provided.