Agricultural Marketing Service
Animal and Plant Health Inspection Service
Farm Service Agency
Federal Crop Insurance Corporation
Forest Service
Foreign-Trade Zones Board
International Trade Administration
National Institute of Standards and Technology
National Oceanic and Atmospheric Administration
Air Force Department
Bonneville Power Administration
Federal Energy Regulatory Commission
Presidential Documents
Centers for Disease Control and Prevention
Children and Families Administration
Food and Drug Administration
National Institutes of Health
Coast Guard
U.S. Customs and Border Protection
Fish and Wildlife Service
Land Management Bureau
National Institute of Corrections
Employment and Training Administration
Mine Safety and Health Administration
Occupational Safety and Health Administration
Federal Aviation Administration
Federal Motor Carrier Safety Administration
Federal Transit Administration
Foreign Assets Control Office
United States Mint
Consult the Reader Aids section at the end of this issue for phone numbers, online resources, finding aids, reminders, and notice of recently enacted public laws.
To subscribe to the Federal Register Table of Contents LISTSERV electronic mailing list, go to http://listserv.access.gpo.gov and select Online mailing list archives, FEDREGTOC-L, Join or leave the list (or change settings); then follow the instructions.
Office of Personnel Management.
Final rule.
The Office of Personnel Management (OPM) is issuing final regulations governing Federal adverse actions. The final regulations conform the adverse action rules regarding employee coverage to binding judicial decisions interpreting the underlying statute.
Sharon L. Mayhew by telephone at (202) 606-2930; by FAX at (202) 606-2613; or by e-mail at
On May 1, 2007, OPM published at 72 FR 23772 (2007) proposed amendments to the regulations in 5 CFR part 752, to conform the adverse action rules regarding the procedural and appeal rights of individuals serving a probationary period in the competitive service or a trial period in the excepted service to binding judicial decisions interpreting the underlying statute. We also proposed amendments to 5 CFR part 315 to make corresponding changes to the career and career-conditional employment rules governing probationary periods. The public comment period on the proposed regulations ended on July 2, 2007. OPM carefully considered the three comments received.
Two commenters supported and commended OPM's proposed amendments to the regulations in parts 315 and 752 of title 5 CFR. They recommended OPM make similar changes to procedural and appeal rights in 5 CFR part 432, the regulations governing performance-based actions. One of the commenters suggested additional amendments be made to 5 CFR part 315 to cover actions taken under 5 CFR part 432. These suggestions, however, are beyond the scope of the proposed regulations.
The third commenter supported OPM's proposed amendments to the regulations in parts 315 and 752 of title 5 CFR. The commenter also advocated Congressional legislation to support OPM's interpretation of the statute at 5 U.S.C. 7511 and recommended that OPM repeat previously stated interpretive guidance regarding trial periods for excepted service appointments pending conversion to the competitive service. See 57 FR 20041. These recommendations are beyond the scope of the proposed regulations and will not be further addressed.
Finally, while supporting the language in the proposed regulations, the third commenter expressed concern that a literal reading of the Federal Circuit decision in
For these and all the reasons stated in the proposed regulations published at 72 FR 23772 (2007), OPM issues these final regulations without modification, except for two minor non-substantive grammatical changes in § 752.401(11) and § 752.401(13).
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.
Administrative practice and procedure, Government employees.
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.
(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
(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.
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:
5 U.S.C. 7504, 7514, and 7543.
(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.
(b)
U.S. Office of Personnel Management.
Final rule.
The U.S. Office of Personnel Management (OPM) is issuing final regulations dealing with the use of OPM's allotment authority to allow for pretax salary reductions as part of OPM's flexible benefits plan. Using an allotment from an employee's pay to the employing agency allows certain payments (e.g., employee health insurance premiums, contributions to a flexible spending arrangement, and contributions to a health savings account) to be paid with pretax dollars, as provided under section 125 of the Internal Revenue Code. In addition, these regulations finalize certain policy clarifications and changes to make the regulations more readable.
Kevin Kitchelt by telephone at (202) 606-2858; by fax at (202) 606-0824; or by e-mail at
On November 17, 2006, the U.S. Office of Personnel Management (OPM), issued interim regulations (71 FR 66827) on OPM's allotment authority at 5 CFR part 550, subpart C, to allow for pretax salary reductions as part of OPM's flexible benefits plan. Using an allotment from an employee's pay to the employing agency allows certain payments (e.g., employee health insurance premiums, contributions to a flexible spending arrangement, and contributions to a health savings account) to be paid with pretax dollars, as provided under section 125 of the Internal Revenue Code. The interim regulations also made certain policy clarifications and changes to make the regulations more readable
The 60-day comment period ended on January 16, 2007. During the comment period, OPM received one comment that was outside the scope of these regulations. Therefore, we are adopting the interim regulations as final with a correction to a section title.
I certify that these regulations will not have a significant economic impact on a substantial number of small entities because they will apply only to Federal agencies and employees.
The Office of Management and Budget has reviewed this rule in accordance with E.O. 12866.
Administrative practice and procedure, Claims, Government employees, Wages, Health insurance, and Taxes.
5 U.S.C. 5527; E.O. 10982, 3 CFR 1959-1963 Comp., p.502.
Animal and Plant Health Inspection Service, USDA.
Affirmation of interim rule as final rule.
We are adopting as a final rule, without change, an interim rule that amended the regulations for the importation of unmanufactured wood articles to bring the methyl bromide treatment schedule into alignment with current international phytosanitary standards. The interim rule was necessary because international phytosanitary standards had changed, and our regulations needed to be updated to reflect the current standards.
Effective on February 7, 2008, we are adopting as a final rule the interim rule published at 72 FR 30460-30462 on June 1, 2007.
Mr. John T. Jones, II, Forestry Products Trade Director, PPQ, APHIS, 4700 River Road Unit 140, Riverdale, MD 20737-1236; (301) 734-8860.
In an interim rule
Comments on the interim rule were required to be received on or before July 31, 2007. We received one comment by that date, from a State agriculture department. The commenter stated that methyl bromide treatments do not control deep wood insects, but did not provide any evidence to support that assertion. The commenter also stated that more effective treatments should be required, but did not offer any suggestions for such treatments.
We agree that the methyl bromide treatment standards adopted in the interim rule would be inappropriate for the treatment of logs or large pieces of lumber. However, these standards apply specifically to wood packaging materials, such as pallets, crating, and boxes, which are typically made of stock
Therefore, for the reasons given in the interim rule and in this document, we are adopting the interim rule as a final rule without change.
This action also affirms the information contained in the interim rule concerning Executive Orders 12866 and 12988 and the Paperwork Reduction Act.
Further, this action has been determined to be not significant for the purposes of Executive Order 12866 and, therefore, has not been reviewed by the Office of Management and Budget.
In accordance with 5 U.S.C. 604, we have performed a final regulatory flexibility analysis, which is set out below, regarding the economic effects of this rule on small entities.
We invited the public to comment on the potential effects of the interim rule on small entities, in particular the number and kind of small entities that may incur benefits or costs from the implementation of the interim rule. However, we did not receive any additional information or data in response to those requests.
The rule affects foreign exporters of goods that are shipped using wood packaging materials. No U.S. entities involved in the production or supply of unmanufactured wood packaging materials are expected to be negatively affected by the rule because the revised treatment must occur in the country of origin. The impact on foreign entities is not expected to be large because only the treatment time and concentration reading have been changed; the methyl bromide dosage rate remains the same. It is possible that some foreign entities might pass on additional treatment costs, if any, to U.S. buyers.
The rule has no mandatory reporting, recordkeeping, or other compliance requirements for U.S. entities, other than the requirements that normally pertain to commodity importation. APHIS has not identified any duplication, overlap, or conflict of the interim rule with other Federal rules.
We do not foresee the rule having a significant economic impact on small entities, and therefore have not proposed significant alternatives to minimize impacts. The rule simply aligns the U.S. methyl bromide treatment requirements for wood packaging materials with the standards established by the International Plant Protection Convention. The rule benefits the United States by reducing the risk of introduction of pests via unmanufactured wood packaging materials. It may impact foreign exporters of goods to the United States who use unmanufactured wood packaging materials, which in turn may affect importers of these goods. However, cost increases, if any, due to the revised treatment requirements are not expected to significantly affect domestic entities and thus will not have a measurable impact on the flow of trade.
Coffee, Cotton, Fruits, Imports, Logs, Nursery stock, Plant diseases and pests, Quarantine, Reporting and recordkeeping requirements, Rice, Vegetables.
Federal Crop Insurance Corporation, USDA.
Final rule.
The Federal Crop Insurance Corporation (FCIC) finalizes the Florida Citrus Fruit Crop Provisions. The intended effect of this action is to restrict the effect of the current Florida Citrus Fruit Crop Insurance Provisions to the 2008 and prior crop years and replace with new crop provisions to better meet the needs of the insured producers. The changes will apply for the 2009 and succeeding crop years.
William Klein, Risk Management, Specialist, Product Management, Product Administration and Standards Division, Risk Management Agency, United States Department of Agriculture, 6501 Beacon Drive, Stop 0812, Room 421, Kansas City, MO 64133-4676, telephone (816) 926-7730.
This rule has been determined to be non-significant for the purposes of Executive Order 12866 and, therefore, it has not been reviewed by the Office of Management and Budget (OMB).
Pursuant to the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 35), the collections of information in this rule have been approved by OMB under control number 0563-0053 through June 30, 2008.
FCIC 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.
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA) establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local, and tribal governments and the private sector. This rule contains no Federal mandates (under the regulatory provisions of title II of the UMRA) for State, local, and tribal governments or the private sector. Therefore, this rule is not subject to the requirements of sections 202 and 205 of UMRA.
It has been determined under section 1(a) of Executive Order 13132, Federalism, that this rule does not have sufficient implications to warrant consultation with the States. The provisions contained in this rule will not have a substantial direct effect on States, or on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.
FCIC certifies that this regulation will not have a significant economic impact on a substantial number of small entities. Program requirements for the Federal crop insurance program are the same for all producers regardless of the size of their farming operation. For instance, all producers are required to submit an application and acreage report to establish their insurance guarantees and compute premium amounts, or a notice of loss and production information to determine an indemnity payment in the event of an insured cause of crop loss. Whether a producer has 10 acres or 1000 acres, there is no difference in the kind of information collected. To ensure crop insurance is available to small entities, the Federal Crop Insurance Act authorizes FCIC to waive collection of administrative fees from limited resource farmers. FCIC believes this waiver helps to ensure small entities are given the same opportunities to manage their risks through the use of crop insurance. A Regulatory Flexibility Analysis has not been prepared since this regulation does not have an impact on small entities, and, therefore, this regulation is exempt from the provisions of the Regulatory Flexibility Act (5 U.S.C. 605).
This program is listed in the Catalog of Federal Domestic Assistance under No. 10.450.
This program is not subject to the provisions of Executive Order 12372, which require intergovernmental consultation with State and local officials. See the Notice related to 7 CFR part 3015, subpart V, published at 48 FR 29115, June 24, 1983.
This rule has been reviewed in accordance with Executive Order 12988 on civil justice reform. The provisions of this rule will not have a retroactive effect. The provisions of this rule will preempt State and local laws to the extent such State and local laws are inconsistent herewith. With respect to any direct action taken by FCIC under the terms of the crop insurance policy, the administrative appeal provisions published at 7 CFR part 11 must be exhausted before any action for judicial review of any determination or action by FCIC may be brought.
This action is not expected to have a significant impact on the quality of the human environment, health, and safety. Therefore, neither an Environmental Assessment nor an Environmental Impact Statement is needed.
On October 13, 2006, FCIC published a notice of proposed rulemaking in the
Additionally, FCIC requested input regarding the possible addition of Asiatic Citrus Canker (ACC) as a cause of loss. An insurance service organization commented they believe their members would oppose this since it has been problematic as a cause of loss in the Florida Fruit Tree Pilot policy. An insurance provider commented they are strongly opposed to providing coverage for ACC under the fruit policy. They believe the ACC disease is so widespread it is creating a multitude of problems with the Florida Fruit Tree Pilot Crop Provisions and they have concerns with it being covered in these provisions as well. Additionally, ACC coverage has been removed from the Florida Fruit Tree policy effective for the 2008 crop year.
In addition to the changes described above, FCIC has made minor editorial changes and the following changes:
1. Removed the paragraph immediately preceding section 1 which refers to the order of priority in the event of conflict. This same information is contained in the Basic Provisions. Therefore, it is duplicative and has been removed in the Crop Provisions.
2. Added the provisions, “unless specified otherwise in the Special Provisions” in section 8(a)(2) to allow greater flexibility in modifying the calendar date for the end of the insurance period. Given the rapid advances in technology, which could affect the insurance period, the policy needs the ability to respond quickly.
Crop insurance, Florida Citrus Fruit Crop Provisions.
7 U.S.C. 1506(l) and 1506(p).
The Florida Citrus Fruit Crop Insurance Provisions for the 2009 and succeeding crop years are as follows:
(1) Citrus I—Early and mid-season oranges;
(2) Citrus II—Late oranges juice;
(3) Citrus III—Grapefruit for which freeze damage will be adjusted on a juice basis;
(4) Citrus IV—Tangelos and Tangerines;
(5) Citrus V—Murcott Honey Oranges (also known as Honey Tangerines) and Temple Oranges;
(6) Citrus VI—Lemons and Limes;
(7) Citrus VII—Grapefruit for which freeze damage will be adjusted on a fresh fruit basis, and late oranges fresh;
(8) Citrus VIII—Navel Oranges; and
(9) Citrus IX—Any other citrus fruit crop designated in the Special Provisions.
(a) Including citrus fruit that:
(1) Was harvested before damage occurred;
(2) Remained on the tree after damage occurred;
(3) Except as provided in (b), was missing, damaged, or destroyed from either an insured or uninsured cause;
(4) Was marketed or could be marketed as fresh citrus fruit;
(5) Was harvested prior to inspection by us; or
(6) Was harvested within 7 days after a freeze;
(b) Not including citrus fruit that:
(1) Was missing, damaged, or destroyed before insurance attached for any crop year;
(2) Was damaged or destroyed by normal dropping; or
(3) Any tangerines that normally would not meet the 210 pack size (2 and
(a) A basic unit, as defined in section 1 of the Basic Provisions, will be divided into additional basic units by each citrus fruit crop designated in the Special Provisions.
(b) Provisions in the Basic Provisions that allow optional units by irrigated and non-irrigated practices are not applicable.
(c) In addition to establishing optional units by section, section equivalent, or FSA farm serial number, optional units may be established if each optional unit is located on non-contiguous land.
In addition to the requirements of section 3 of the Basic Provisions:
(a) You may select only one coverage level for each citrus fruit crop shown in section 1 of these Crop Provisions, or designated in the Special Provisions, that you elect to insure. If different amounts of insurance are available for fruit types within a citrus fruit crop, you must select the same coverage level for each fruit type. For example, if you choose the 75 percent coverage level for one fruit type, you must also choose the 75 percent coverage level for all other fruit types within that citrus fruit crop.
(b) The production reporting requirements contained in section 3 of the Basic Provisions are not applicable.
(c) For the first year of insurance for acreage interplanted with another fruit type or another crop, and any time the planting pattern of such acreage is changed, you must report, by the sales closing date, the following:
(1) The age and fruit type of the interplanted citrus trees, as applicable;
(2) The planting pattern; and
(3) Any other information we request in order to establish your amount of insurance.
(d) We will reduce acreage or the amount of insurance or both, as necessary, based on our estimate of the effect of the interplanted fruit type or another crop on the insured fruit type. If you fail to notify us of any circumstance that may reduce the acreage or amount of insurance, we will reduce the acreage or amount of insurance or both as necessary any time we become aware of the circumstance.
(e) For carryover policies:
(1) Any changes to your coverage must be requested on or before the sales closing date;
(2) Requested changes will take effect on May 1, the first day of the crop year, unless we reject the requested increase based on our inspection, or because a loss occurs on or before April 30 (Rejection can occur at any time we discover loss has occurred on or before April 30); and
(3) If the increase is rejected, coverage will remain at the same level as the previous crop year.
(f) If your citrus fruit was damaged prior to the beginning of the insurance period, your amount of insurance (per acre) will be reduced by the amount of damage that occurred.
In accordance with section 4 of the Basic Provisions, the contract change date is January 31 preceding the cancellation date.
In accordance with section 2 of the Basic Provisions, the cancellation and termination dates are April 30.
(a) In accordance with section 8 of the Basic Provisions, the crop insured will be all acreage of each citrus fruit crop that you elect to insure, in which you have a share, that is grown in the county shown on the application, and for which a premium rate is quoted in the actuarial documents.
(b) In addition to the citrus fruit not insurable in section 8 of the Basic Provisions, we do not insure any citrus fruit:
(1) That cannot be expected to mature each crop year within the normal maturity period for the fruit type;
(2) Produced by citrus trees that have not reached the fifth growing season after being set out, unless otherwise provided in the Special Provisions or by a written agreement to insure such citrus fruit (In order for the year of set out to be considered as a growing season, citrus trees must be set out on or before April 30 of the calendar year);
(3) Of “Meyer Lemons” and oranges commonly known as “Sour Oranges” or “Clementines”;
(4) Of the Robinson tangerine variety, for any crop year in which you have elected to exclude such tangerines from insurance (You must elect this exclusion prior to the crop year for which the exclusion is to be effective, except that for the first crop year you must elect this exclusion by the later of the sales closing date or the time you submit the application for insurance);
(5) That is produced on citrus trees that have been topworked until the third crop year after topworking. The Special Provisions will specify the appropriate rate class for trees insurable following topworking, but that have not reached full production; or
(6) Of any fruit type not specified as insurable in the Special Provisions or within the definition of “citrus fruit crop.”
(c) Prior to the date insurance attaches, and upon our approval, you may elect to insure or exclude from insurance any insurable citrus acreage that has a potential production of less than 100 boxes per acre. If you elect to:
(1) Insure such acreage, we will consider the potential production to be 100 boxes per acre when determining the amount of loss; or
(2) Exclude such acreage, we will disregard the acreage for all purposes related to this policy.
(d) In addition to the provisions in section 6 of the Basic Provisions, if you fail to notify us of your election to insure or exclude citrus acreage, and the potential production from such acreage is 100 or more boxes per acre, we will determine the percent of damage on all of the insurable acreage for the unit, but will not allow the percent of damage for the unit to be increased by including such acreage.
(e) Potential production will be determined during loss adjustment.
In lieu of the provisions in section 9 of the Basic Provisions that prohibit insurance attaching to a crop planted with another crop:
(a) Citrus fruit from trees interplanted with another fruit type or another crop is insurable unless we inspect the acreage and determine it does not meet the requirements contained in your policy.
(b) If the citrus fruit is from trees interplanted with another fruit type or another crop, acreage will be prorated according to the percentage of the acres occupied by each of the interplanted fruit types or crops (For example, if grapefruit have been interplanted with oranges on 100 acres and the grapefruit trees are on 50 percent of the acreage, grapefruit will be considered planted on 50 acres and oranges will be considered planted on 50 acres).
(c) The combination of the citrus fruit acreage and the interplanted crop acreage cannot exceed the physical amount of acreage.
(a) In accordance with the provisions of section 11 of the Basic Provisions:
(1) Coverage begins on May 1 of each crop year, unless:
(i) For new or carryover policies, as applicable, we inspect the acreage and determine it does not meet the requirements for insurability contained in your policy (You must provide any information we require for the fruit type, so we may determine the condition of the grove to be insured); or
(ii) For carryover policies, you report additional citrus acreage, or a greater share, such that the amount of insurance will increase by more than 10 percent and we notify you all or a part of your citrus acreage is not insurable.
(2) The calendar date for the end of the insurance period for each crop year, unless specified otherwise in the Special Provisions, is:
(i) February 7 for early and navel oranges, Orlando tangelos and tangerines;
(ii) February 28 for all other tangelos;
(iii) March 31 for mid-season and temple oranges;
(iv) April 30 for lemons, limes;
(v) May 15 for murcott honey oranges; and
(vi) June 30 for grapefruit and late season oranges.
(b) In addition to the provisions of section 11 of the Basic Provisions:
(1) If you acquire an insurable share in any insurable acreage of citrus fruit after coverage begins, but on or before the acreage reporting date of any crop year, and if after inspection we consider the acreage acceptable, then insurance will be considered to have attached to such acreage on the calendar date for the beginning of the insurance period.
(2) If you relinquish your insurable share on any insurable acreage of citrus fruit on or before the acreage reporting date of any crop year, insurance will not be considered to have attached, no premium will be due, and no indemnity payable, for such acreage for that crop year unless:
(i) A transfer of coverage and right to an indemnity, or a similar form approved by us, is completed by all affected parties;
(ii) We are notified by you or the transferee in writing of such transfer on or before the acreage reporting date; and
(iii) The transferee is eligible for crop insurance.
(a) In accordance with the provisions of section 12 of the Basic Provisions, insurance is provided only against the following causes of loss to citrus fruit that occur within the insurance period:
(1) Fire, unless weeds and other forms of undergrowth have not been controlled or pruning debris has not been removed from the grove;
(2) Freeze;
(3) Hail;
(4) Hurricane;
(5) Tornado;
(6) Excess wind, but only if it causes the individual citrus fruit from Citrus IV, V, VII, and VIII to be unmarketable as fresh fruit; or
(7) Diseases, but only if specified in the Special Provisions.
(b) In addition to the causes of loss excluded in section 12 of the Basic Provisions, we will not insure against damage or loss of production due to:
(1) Damage to the blossoms or trees; or
(2) Inability to market the citrus fruit for any reason other than actual physical damage from an insurable cause specified in this section. For example, we will not pay you an indemnity if you are unable to market due to quarantine, boycott, or refusal of any person to accept production.
(a) We will determine your loss on a unit basis. In the event you are unable to provide separate acceptable production records:
(1) For any optional units, we will combine all optional units for which such production records were not provided; or
(2) For any basic units, we will allocate any commingled production to such units in proportion to our liability on the harvested acreage for the units.
(b) If any citrus fruit within a unit is damaged by an insurable cause of loss, we will settle your claim by:
(1) Calculating the amount of insurance for the unit by multiplying the number of acres by the respective dollar amount of insurance per acre for each fruit type and multiplying that result by your share;
(2) Calculating the average percent of damage to the fruit within each respective fruit type, rounded to the nearest tenth of a percent (0.1%) (To determine the percent of damage, the amount of citrus fruit damaged from an insured cause must be converted to boxes and divided by the undamaged potential production);
(3) Subtracting the deductible from the result of section (10)(b)(2);
(4) If the result of section (10)(b)(3) is positive, dividing this result by the coverage level percentage (If the result of section 10(b)(3) is negative, no indemnity will be due);
(5) Multiplying the result of section (10)(b)(4) by the amount of insurance for the unit for the respective fruit type, to determine the value of all damage; and
(6) Totaling all such results of section (10)(b)(5) for all fruit types and subtracting any indemnities paid for the current crop year to determine the amount payable for the unit. (For example, assume a 55-acre unit sustains late season damage. No previous damage has occurred on the unit during
1. 55 acres × $1,180 = $64,900 amount of insurance for the unit;
2. 17,171 ÷ 24,530 = 70 percent average percent of damage;
3. 70 percent damage − 25 percent deductible (100 percent − 75 percent) = 45 percent;
4. 45 percent ÷ 75 percent = 60 percent adjusted damage; and
5. 60 percent × $64,900 = $38,940 indemnity.
(c) Citrus fruit crops IV, V, VII, and VIII that are seriously damaged by freeze, as determined by a fresh-fruit cut of a representative sample of fruit in the unit in accordance with the applicable provisions of the State of Florida Citrus Fruit Laws, or contained in standards issued by FCIC, and that are not or could not be marketed as fresh fruit, will be considered damaged to the following extent:
(1) If less than 16 percent of the fruit in a sample shows serious freeze damage, the fruit will be considered undamaged; or
(2) If 16 percent or more of the fruit in a sample shows serious freeze damage, the fruit will be considered 50 percent damaged, except that:
(i) For tangerines of Citrus IV, damage in excess of 50 percent will be the actual percent of damaged fruit; and
(ii) Citrus IV (except tangerines), V, VII, and VIII, if it is determined that the juice loss in the fruit exceeds 50 percent, such percent will be considered the percent of damage.
(d) Notwithstanding the provisions of section 10(c) of these crop provisions as to citrus fruit of Citrus IV, V, VII, and VIII, in any unit that is mechanically separated using the specific-gravity (floatation) method into undamaged and freeze-damaged fruit, the amount of damage will be the actual percent of freeze-damaged fruit not to exceed 50 percent and will not be affected by subsequent fresh-fruit marketing. However, the 50 percent limitation on mechanically separated, freeze-damaged fruit will not apply to tangerines of Citrus IV.
(e) Any citrus fruit of Citrus I, II, III, and VI damaged by freeze, but that can be processed into products for human consumption, will be considered as marketable for juice. The percent of damage will be determined by relating the juice content of the damaged fruit to:
(1) The average juice content of the fruit produced on the unit for the three previous crop years based on your records, if they are acceptable to us; or
(2) The following juice content, if acceptable records are not furnished:
(i) Citrus I—52 pounds of juice per box;
(ii) Citrus II—54 pounds of juice per box;
(iii) Citrus III—45 pounds of juice per box; and
(iv) Citrus VI—43 pounds of juice per box;
(f) Any individual citrus fruit on the ground that is not collected and marketed will be considered as 100 percent damaged if the damage was due to an insured cause.
(g) Any individual citrus fruit that is unmarketable either as fresh fruit or as juice because it is immature, unwholesome, decomposed, adulterated, or otherwise unfit for human consumption due to an insured cause will be considered as 100 percent damaged.
(h) Individual citrus fruit of Citrus IV, V, VII, and VIII, that are unmarketable as fresh fruit due to serious damage from hail as defined in the applicable United States Standards for Grades of Florida fruit, or wind damage from a hurricane, tornado or other excess wind storms that results in the fruit not meeting the standards for packing as fresh fruit, will be considered 100 percent damaged.
The late and prevented planting provisions of the Basic Provisions are not applicable.
Agricultural Marketing Service, USDA.
Interim final rule with request for comments.
This rule decreases the assessment rate established for the California Olive Committee (committee) for the 2008 and subsequent fiscal years from $47.84 to $15.60 per assessable ton of olives handled. The committee locally administers the marketing order which regulates the handling of olives grown in California. Assessments upon olive handlers are used by the committee to fund reasonable and necessary expenses of the program. The fiscal year began January 1 and ends December 31. The assessment rate will remain in effect indefinitely unless modified, suspended, or terminated.
Effective February 8, 2008. Comments received by April 7, 2008 will be considered prior to issuance of a final rule.
Interested persons are invited to submit written comments concerning this rule. Comments must be sent to the Docket Clerk, Marketing Order Administration Branch, Fruit and Vegetable Programs, AMS, USDA, 1400 Independence Avenue, SW., STOP 0237, Washington, DC 20250-0237; Fax: (202) 720-8938, or Internet:
Jennifer R. Garcia, Marketing Specialist, or Kurt J. Kimmel, Regional Manager, California Marketing Field Office, Marketing Order Administration Branch, Fruit and Vegetable Programs, AMS, USDA; Telephone: (559) 487-5901, Fax: (559) 487-5906; 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. 148 and Order No. 932, both as amended (7 CFR part 932), regulating the handling of olives grown in California, 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.”
The Department of Agriculture (USDA) is issuing this rule in conformance with Executive Order 12866.
This rule has been reviewed under Executive Order 12988, Civil Justice Reform. Under the marketing order now in effect, California olive handlers are subject to assessments. Funds to administer the order are derived from such assessments. It is intended that the assessment rate as issued herein will be applicable to all assessable olives beginning on January 1, 2008, and continue until amended, suspended, or terminated. 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. Such 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 decreases the assessment rate established for the committee for the 2008 and subsequent fiscal years from $47.84 to $15.60 per ton of assessable olives from the applicable crop years.
The California olive marketing order provides authority for the committee, with the approval of USDA, to formulate an annual budget of expenses and collect assessments from handlers to administer the program. The fiscal year, which is the 12-month period between January 1 and December 31, begins after the corresponding crop year, which is the 12-month period beginning August 1 and ending July 31 of the subsequent year. Fiscal year budget and assessment recommendations are made after the corresponding crop year olive tonnage is reported. The members of the committee are producers and handlers of California olives. They are familiar with the committee's needs and with costs for goods and services in their local area and are thus in a position to formulate an appropriate budget and assessment rate. The assessment rate is discussed in a public meeting. Thus, all directly affected persons have an opportunity to participate and provide input.
For the 2007 and subsequent fiscal years, the committee recommended, and USDA approved, an assessment rate that would continue in effect from fiscal year to fiscal year unless modified, suspended, or terminated by USDA upon recommendation and information submitted by the committee or other information available to USDA.
The committee met on December 5, 2007, and unanimously recommended 2008 fiscal year expenditures of $1,588,552 and an assessment rate of $15.60 per ton of assessable olives. In comparison, last year's budgeted expenditures were $965,396. The assessment rate of $15.60 is $32.24 lower than the rate currently in effect. The committee recommended the lower assessment rate because the 2007-08 assessable olive receipts as reported by the California Agricultural Statistics Service (CASS) are 108,059 tons, which compares to 16,270 tons in 2006-07. The 2006-07 crop was unusually small in size due to unusual weather conditions.
The major expenditures recommended by the committee for the 2008 fiscal year include $500,000 for research, $750,000 for marketing activities, and $288,552 for administration. Budgeted expenditures for these items in 2007 were $365,775, $347,450, and $252,171, respectively. The committee recommended a larger 2008 research budget so it can expand its ongoing research to develop a mechanical olive harvesting method. The committee also recommended an increase in the 2008 marketing budget to allow for a restructuring of its marketing program, which will focus on a new Web site and trade advertisements. Recommended increases in the administrative budget are due mainly to a necessary office move and increases in employee benefits. Another $50,000 is budgeted for 2008 for a possible inspection-related research project.
The assessment rate recommended by the committee was derived by considering anticipated fiscal year expenses, actual olive tonnage received by handlers during the 2007-08 crop year, and additional pertinent factors. Actual assessable tonnage for the 2008 fiscal year is expected to be higher than the 2007-08 crop receipts of 108,059 tons reported by CASS because some olives may be diverted by handlers to uses that are exempt from marketing order requirements. Income derived from handler assessments, along with funds from the committee's authorized reserve and interest income, would be adequate to cover budgeted expenses. Funds in the reserve would be kept within the maximum permitted by the order of approximately one fiscal year's expenses (§ 932.40).
The assessment rate established in this rule will continue in effect indefinitely unless modified, suspended, or terminated by USDA upon recommendation and information submitted by the committee or other available information.
Although this assessment rate is effective for an indefinite period, the committee would continue to meet prior to or during each fiscal year to recommend a budget of expenses and consider recommendations for modification of the assessment rate. The dates and times of committee meetings are available from the committee or USDA. Committee meetings are open to the public and interested persons may express their views at these meetings. USDA will evaluate committee recommendations and other available information to determine whether modification of the assessment rate is needed. Further rulemaking would be undertaken as necessary. The committee's 2008 budget and those for subsequent fiscal years will be reviewed and, as appropriate, approved by USDA.
Pursuant to requirements set forth in the Regulatory Flexibility Act (RFA), the Agricultural Marketing Service (AMS) has considered the economic impact of this rule on small entities. Accordingly, AMS has prepared this initial regulatory flexibility analysis.
The purpose of the RFA is to fit regulatory actions to the scale of business subject to such actions in order that small businesses will not be unduly or disproportionately burdened. Marketing orders issued pursuant to the Act, and the rules issued thereunder, are unique in that they are brought about through group action of essentially small entities acting on their own behalf.
There are approximately 745 producers of olives in the production area and 2 handlers subject to regulation under the marketing order. Small agricultural producers are defined by the Small Business Administration (13 CFR 121.201) as those having annual receipts less than $750,000, and small agricultural service firms are defined as those whose annual receipts are less than $6,500,000.
Based upon information from the committee, the majority of olive producers may be classified as small
This rule decreases the assessment rate established for the committee and collected from handlers for the 2008 and subsequent fiscal years from $47.84 to $15.60 per ton of assessable olives. The committee unanimously recommended 2008 expenditures of $1,558,552 and an assessment rate of $15.60 per ton. The proposed assessment rate of $15.60 is $32.24 lower than the 2007 rate. The lower assessment rate is necessary because assessable olive receipts for the 2007-08 crop year were reported by CASS to be 108,059 tons, compared to 16,270 tons for the 2006-07 crop year. Actual assessable tonnage for the 2008 fiscal year is expected to be lower because some of the receipts may be diverted by handlers to exempt outlets on which assessments are not paid.
Income generated from the $15.60 per ton assessment rate should be adequate to meet this year's expenses when combined with funds from the authorized reserve and interest income. Funds in the reserve would be kept within the maximum permitted by the order of about one fiscal year's expenses (§ 932.40).
Expenditures recommended by the committee for the 2008 fiscal year include $500,000 for research, $750,000 for marketing activities, and $288,552 for administration. Budgeted expenditures for these items in 2007 were $365,775, $332,450, and $252,171, respectively. The committee recommended a larger 2008 research budget so it can expand its ongoing research to develop a mechanical olive harvesting method. The committee also recommended an increase in the 2008 marketing budget to allow for a restructuring of its marketing program, which will focus on a new Web site and trade advertisements. Recommended increases in the administrative budget are due mainly to a necessary office move and increases in employee benefits. Another $50,000 is budgeted for a possible inspection-related research project.
Prior to arriving at this budget, the committee considered information from various sources, such as the committee's Executive, Market Development, and Research Subcommittees. Alternate spending levels were discussed by these groups, based upon the relative value of various research and marketing projects to the olive industry. The assessment rate of $15.60 per ton of assessable olives was derived by considering anticipated expenses, the volume of assessable olives, and additional pertinent factors.
A review of historical information indicates that the grower price for the 2007-08 crop year was approximately $1,007.78 per ton for canning fruit and $378.51 per ton for limited-use sizes, leaving the balance as unusable cull fruit. Approximately 81 percent of a ton of olives are canning fruit sizes and 18 percent are limited use sizes, leaving the balance as unusable cull fruit. Grower revenue on 108,059 total tons of canning and limited-use sizes would be $95,322,099 given the current grower prices for those sizes. Therefore, the assessment revenue for the 2007-08 fiscal year is expected to be approximately 2 percent of grower revenue.
This action decreases the assessment obligation imposed on handlers. Assessments are applied uniformly on all handlers, and some of the costs may be passed on to producers. However, decreasing the assessment rate reduces the burden on handlers, and may reduce the burden on producers. In addition, the committee's meeting was widely publicized throughout the California olive industry and all interested persons were invited to attend the meeting and participate in committee deliberations on all issues. Like all committee meetings, the December 5, 2007, meeting was a public meeting and all entities, both large and small, were able to express views on this issue. Finally, interested persons are invited to submit information on the regulatory and informational impacts of this action on small businesses.
This action imposes no additional reporting or recordkeeping requirements on either small or large California olive handlers. 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.
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.
USDA has not identified any relevant Federal rules that duplicate, overlap, or conflict with this rule.
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 committee and other available information, it is hereby found that this rule, as hereinafter set forth, will tend to effectuate the declared policy of the act.
Pursuant to 5 U.S.C. 553, it is also found and determined upon good cause that it is impractical, unnecessary, and contrary to the public interest to give preliminary notice prior to putting this rule into effect, and that good cause exists for not postponing the effective date of this rule until 30 days after publication in the
Olives, Marketing agreements, Reporting and recordkeeping requirements.
7 U.S.C. 601-674.
On and after January 1, 2008, an assessment rate of $15.60 per ton is established for California olives.
Board of Governors of the Federal Reserve System.
Final rule.
The Board of Governors of the Federal Reserve System (Board) has adopted final amendments to its Regulation A to reflect the Board's approval of a decrease in the primary credit rate at each Federal Reserve Bank. The secondary credit rate at each Reserve Bank automatically decreased by formula as a result of the Board's primary credit rate action.
The amendments to part 201 (Regulation A) are effective February 7, 2008. The rate changes for primary and secondary credit were effective on the dates specified in 12 CFR 201.51, as amended.
Jennifer J. Johnson, Secretary of the Board (202/452-3259); for users of Telecommunication Devices for the Deaf (TDD) only, contact 202/263-4869.
The Federal Reserve Banks make primary and secondary credit available to depository institutions as a backup source of funding on a short-term basis, usually overnight. The primary and secondary credit rates are the interest rates that the twelve Federal Reserve Banks charge for extensions of credit under these programs. In accordance with the Federal Reserve Act, the primary and secondary credit rates are established by the boards of directors of the Federal Reserve Banks, subject to the review and determination of the Board.
The Board approved requests by the Reserve Banks to decrease by 50 basis points the primary credit rate in effect at each of the twelve Federal Reserve Banks, thereby decreasing from 4.00 percent to 3.50 percent the rate that each Reserve Bank charges for extensions of primary credit. As a result of the Board's action on the primary credit rate, the rate that each Reserve Bank charges for extensions of secondary credit automatically decreased from 4.50 percent to 4.00 percent under the secondary credit rate formula. The final amendments to Regulation A reflect these rate changes.
The 50-basis-point decrease in the primary credit rate was associated with a similar decrease in the target for the federal funds rate (from 3.50 percent to 3.00 percent) approved by the Federal Open Market Committee (Committee) and announced at the same time. A press release announcing these actions indicated that:
Financial markets remain under considerable stress, and credit has tightened further for some businesses and households. Moreover, recent information indicates a deepening of the housing contraction as well as some softening in labor markets.
The Committee expects inflation to moderate in coming quarters, but it will be necessary to continue to monitor inflation developments carefully.
Today's policy action, combined with those taken earlier, should help to promote moderate growth over time and to mitigate the risks to economic activity. However, downside risks to growth remain. The Committee will continue to assess the effects of financial and other developments on economic prospects and will act in a timely manner as needed to address those risks.
Pursuant to the Regulatory Flexibility Act (5 U.S.C. 605(b)), the Board certifies that the new primary and secondary credit rates will not have a significantly adverse economic impact on a substantial number of small entities because the final rule does not impose any additional requirements on entities affected by the regulation.
The Board did not follow the provisions of 5 U.S.C. 553(b) relating to notice and public participation in connection with the adoption of these amendments because the Board for good cause determined that delaying implementation of the new primary and secondary credit rates in order to allow notice and public comment would be unnecessary and contrary to the public interest in fostering price stability and sustainable economic growth. For these same reasons, the Board also has not provided 30 days prior notice of the effective date of the rule under section 553(d).
Banks, Banking, Federal Reserve System, Reporting and recordkeeping.
12 U.S.C. 248(i)-(j), 343
(a)
(b)
Federal Aviation Administration (FAA), DOT.
Final special conditions; request for comments.
These special conditions are issued for Boeing Model 767-200, -300, and -300F series airplanes. These airplanes as modified by ABX Air Inc. will have a novel or unusual design feature associated with a satellite communication system which uses lithium ion battery technology. The applicable airworthiness regulations do not contain adequate or appropriate safety standards for this design feature. These special conditions contain the additional safety standards that the Administrator considers necessary to establish a level of safety equivalent to that established by the existing airworthiness standards.
The effective date of these special conditions is January 25, 2008. We must receive your comments by March 10, 2008.
You must mail two copies of your comments to: Federal Aviation Administration, Transport Airplane Directorate, Attention: Rules Docket (ANM-113), Docket No. NM387, 1601 Lind Avenue, SW., Renton, Washington 98057-3356. You may deliver two copies to the Transport Airplane Directorate at the above address. You must mark your comments: Docket No. NM387. You can inspect comments in the Rules Docket weekdays, except federal holidays, between 7:30 a.m. and 7 p.m.
Nazih Khaouly, FAA, Airplane and Flight Crew Interface, ANM-111, Transport Airplane Directorate, Aircraft Certification Service, 1601 Lind Avenue, SW., Renton, Washington 98057-3356; telephone (425) 227-2432; facsimile (425) 227-1149.
The FAA has determined that notice and opportunity for prior public comment on these special conditions are unnecessary because the substance of these special conditions has previously been subject to the public comment process. While we received comments on the previously-proposed special conditions and carefully reviewed them, we determined that no changes were needed to the special conditions, as proposed. In addition, notice and opportunity for prior public comment are impracticable because these procedures would significantly delay issuance of the design approval and thus delivery of the affected aircraft. Therefore, the FAA finds that it is unnecessary to provide an additional opportunity to comment and that good cause exists for making these special conditions effective upon issuance.
We invite interested people to take part in this rulemaking by sending written comments, data, or views. The most helpful comments reference a specific portion of the special conditions, explain the reason for any recommended change, and include supporting data. We ask that you send us two copies of written comments.
We will file in the docket all comments we receive as well as a report summarizing each substantive public contact with FAA personnel about these special conditions. You can inspect the docket before and after the comment closing date. If you wish to review the docket in person, go to the address in the
We will consider all comments we receive by 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 special conditions based on the comments we receive.
If you want us to let you know we received your comments on these special conditions, send us a pre-addressed, stamped postcard on which the docket number appears. We will stamp the date on the postcard and mail it back to you.
On July 5, 2007, ABX Air, Inc. of Wilmington, Ohio applied for a supplemental type certificate to install a satellite communication system on Boeing Model 767-200, -300, and -300F series airplanes. The satellite communication system contains the following equipment:
•
•
• Satellite Phone Handset,
•
•
At present, there is limited experience with use of rechargeable lithium ion batteries in applications involving commercial aviation. However, other users of this technology, ranging from wireless telephone manufacturers to the electric vehicle industry, have noted safety problems with lithium ion batteries. These problems include overcharging, over-discharging, and flammability of cell components.
In general, lithium ion batteries are significantly more susceptible to internal failures that can result in self-sustaining increases in temperature and pressure (i.e., thermal runaway) than their nickel-cadmium or lead-acid counterparts. This is especially true for overcharging that causes heating and destabilization of the components of the cell, leading to the formation (by plating) of highly unstable metallic lithium. The metallic lithium can ignite, resulting in a self-sustaining fire or explosion. Finally, the severity of thermal runaway due to overcharging increases with increasing battery capacity due to the higher amount of electrolyte in large batteries.
Discharge of some types of lithium ion batteries beyond a certain voltage (typically 2.4 volts) can cause corrosion of the electrodes of the cell, resulting in loss of battery capacity that cannot be reversed by recharging. This loss of capacity may not be detected by the simple voltage measurements commonly available to flight crews as a means of checking battery status—a problem shared with nickel-cadmium batteries.
Unlike nickel-cadmium and lead-acid batteries, some types of lithium ion batteries use liquid electrolytes that are flammable. The electrolyte can serve as a source of fuel for an external fire, if there is a breach of the battery container.
These problems experienced by users of lithium ion batteries raise concern about the use of these batteries in commercial aviation. Accordingly, the proposed use of lithium ion batteries in a satellite communication system on Boeing Model 767-200, -300, and -300F series airplanes has prompted the FAA to review the adequacy of existing regulations in 14 CFR 25. Our review indicates that the existing regulations do not adequately address several failure, operational, and maintenance characteristics of lithium ion batteries
The intent of these special conditions is to establish appropriate airworthiness standards for lithium ion batteries in Boeing Model 767-200, -300, and -300F series airplanes modified by ABX Air Inc. and to ensure, as required by 14 CFR 25.601, that these battery installations are not hazardous or unreliable. Accordingly, these special conditions include the following requirements:
• Those provisions of 14 CFR 25.1353 which are applicable to lithium ion batteries.
• The flammable fluid fire protection provisions of 14 CFR 25.863.
In the past, this regulation was not applied to batteries of transport category airplanes, since the electrolytes used in lead-acid and nickel-cadmium batteries are not flammable.
• New requirements to address the hazards of overcharging and over-discharging that are unique to lithium batteries.
• New Instructions for Continuous Airworthiness that include maintenance requirements to ensure that batteries used as spares are maintained in an appropriate state of charge.
Under the provisions of 14 CFR 21.101, ABX Air, Inc. must show that the Boeing Model 767-200, -300 and -300F series airplanes, as changed, continue to meet the applicable provisions of the regulations incorporated by reference in Type Certificate No. A1NM or the applicable regulations in effect on the date of application for the change. The regulations incorporated by reference in the type certificate are commonly referred to as the “original type certification basis.”
The certification basis for Boeing Model 767-200, -300, and -300F series airplanes includes applicable sections of 14 CFR part 25, effective July 30, 1982, as amended by Amendments 25-1 through 25-45, except for portions of Amendment 25.38. In addition, the certification basis includes certain special conditions, exemptions, equivalent levels of safety, or later amended sections of the applicable part 25 that are not relevant to these special conditions.
If the Administrator finds that the applicable airworthiness regulations (i.e., part 25, as amended) do not contain adequate or appropriate safety standards for Boeing Model 767-200, -300, and -300F series airplanes because of a novel or unusual design feature, special conditions are prescribed under the provisions of § 21.16.
In addition to the applicable airworthiness regulations and special conditions, the Boeing Model 767-200, -300, and -300F series airplanes must comply with the fuel vent and exhaust emission requirements of 14 CFR part 34 and the noise certification requirements of 14 CFR part 36.
The FAA issues special conditions, as defined in 14 CFR 11.19, under 14 CFR 11.38, and they become part of the type certification basis in accordance with § 21.101.
Special conditions are initially applicable to the models for which they are issued. Should ABX Air, Inc. apply for a supplemental type certificate to modify any other model included on Type Certificate No. A1NM to incorporate the same or similar novel or unusual design feature, these special conditions would also apply to the other model.
The Boeing Model 767-200, -300, and 300F series airplanes—as modified by ABX Air Inc. to include a satellite communication system which uses lithium ion battery technology—will incorporate a novel or unusual design feature. Because of rapid improvements in airplane technology, the applicable airworthiness regulations do not contain adequate or appropriate safety standards for this design feature. These special conditions contain the additional safety standards that the Administrator considers necessary to establish a level of safety equivalent to that established by the existing airworthiness standards.
The satellite communication system will include a lithium ion battery installation. Large, high capacity, rechargeable lithium ion batteries are a novel or unusual design feature in transport category airplanes. This type of battery has certain failure, operational, and maintenance characteristics that differ significantly from those of the nickel-cadmium and lead-acid rechargeable batteries currently approved for installation on large transport category airplanes. The FAA issues these special conditions to require that (1) all characteristics of the lithium ion battery and its installation that could affect safe operation of the satellite communication system are addressed, and (2) appropriate maintenance requirements are established to ensure that electrical power is available from the batteries when it is needed.
As discussed above, these special conditions are applicable to the Boeing Model 767-200, -300, and -300F series airplanes as modified by ABX Air Inc. Should ABX Air, Inc. apply at a later date for a supplemental type certificate to modify any other model included on Type Certificate No. A1NM to incorporate the same novel or unusual design feature, these special conditions would apply to that model as well.
This action affects only certain novel or unusual design features of the Boeing Model 767-200, -300, and 300F series airplanes as modified by ABX Air Inc. It is not a rule of general applicability and affects only the applicant which applied to the FAA for approval of these features on the airplane.
The substance of these special conditions has been subjected to the notice and comment period in several prior instances and has been derived without substantive change from those previously issued. It is unlikely that prior public comment would result in a significant change from the substance contained herein. For this reason and because a delay would significantly affect the certification of the airplane which is imminent, the FAA has determined that prior public notice and comment are unnecessary and impracticable and that good cause exists for adopting these special conditions upon issuance. The FAA is requesting comments to allow interested persons to submit views that may not have been submitted in response to the prior opportunities for comments described above.
Aircraft, Aviation safety, Reporting and recordkeeping requirements.
49 U.S.C. 106(g), 40113, 44701, 44702, 44704.
The FAA proposes the following special conditions as part of the type certification basis for Boeing Model 767-200, -300, and 300F series airplanes modified by ABX Air Inc. in lieu of the requirements of 14 CFR 25.1353(c)(1) through (c)(4), Amendment 25-113.
Lithium ion batteries and battery installations on Boeing 767-200, -300, and -300F series airplanes must be designed and installed as follows:
(1) Safe cell temperatures and pressures must be maintained during
(2) Design of the lithium ion batteries must preclude the occurrence of self-sustaining, uncontrolled increases in temperature or pressure.
(3) No explosive or toxic gases emitted by any lithium ion battery in normal operation or as the result of any failure of the battery charging system, monitoring system, or battery installation which is not shown to be extremely remote may accumulate in hazardous quantities within the airplane.
(4) Installations of lithium ion batteries must meet the requirements of 14 CFR 25.863(a) through (d).
(5) No corrosive fluids or gases that may escape from any lithium ion battery may damage surrounding structure or any adjacent systems, equipment, or electrical wiring of the airplane in such a way as to cause a major or more severe failure condition, in accordance with 14 CFR 25.1309 (b) and applicable regulatory guidance.
(6) Each lithium ion battery installation must have provisions to prevent any hazardous effect on structure or essential systems caused by the maximum amount of heat the battery can generate during a short circuit of the battery or of its individual cells.
(7) Lithium ion battery installations must have a system to control the charging rate of the battery automatically, so as to prevent battery overheating or overcharging, and,
(i) A battery temperature sensing and over-temperature warning system with a means for automatically disconnecting the battery from its charging source in the event of an over-temperature condition, or
(ii) A battery failure sensing and warning system with a means for automatically disconnecting the battery from its charging source in the event of battery failure.
(8) Any lithium ion battery installation whose function is required for safe operation of the airplane must incorporate a monitoring and warning feature that will provide an indication to the appropriate flight crewmembers whenever the state-of-charge of the batteries has fallen below levels considered acceptable for dispatch of the airplane.
(9) The Instructions for Continued Airworthiness required by 14 CFR 25.1529 must contain maintenance requirements to assure that the lithium ion battery is sufficiently charged at appropriate intervals specified by the battery manufacturer to ensure that batteries whose function is required for safe operation of the airplane will not degrade below specified ampere-hour levels sufficient to power the electronic flight bag (EFB) applications that are required for continued safe flight and landing. The Instructions for Continued Airworthiness must also contain procedures for the maintenance of lithium ion batteries in spares storage to prevent the replacement of batteries whose function is required for safe operation of the airplane with batteries that have experienced degraded charge retention ability or other damage due to prolonged storage at a low state of charge. Precautions should be included in the Instructions for Continued Airworthiness maintenance instructions to prevent mishandling of the lithium ion battery which could result in short-circuit or other unintentional damage that could result in personal injury or property damage.
The term, “sufficiently charged” means the charge that is applied to rechargeable lithium ion batteries, which diminishes during the life of batteries with respect to the retentive capacity of the batteries to deliver available power—where capacity is the total quantity of electricity of a cell or battery, expressed in ampere-hours. Battery life is influenced by its internal chemical reaction and by other factors, such as temperature, shock, the number of recharges, etc.
These special conditions are not intended to replace 14 CFR 25.1353(c), Amendment 25-113 in the certification basis of the ABX, Air Inc supplemental type certificate. These special conditions apply only to lithium ion batteries and their installations. The requirements of 14 CFR 25.1353(c), Amendment 25-113 remain in effect for batteries and battery installations on the ABX Air supplemental type certificate that do not use lithium ion batteries.
Compliance with the requirements of this Special Condition must be shown by test or analysis, with the concurrence of the Chicago Aircraft Certification Office.
Securities and Exchange Commission.
Final rule.
The Securities and Exchange Commission is amending its Rules of Organization and Program Management to delegate its authority to the Director of the Division of Corporation Finance to grant or deny exemptions pursuant to Section 36 of the Securities Exchange Act of 1934 from the requirement for registrants in connection with an annual meeting of security holders to furnish an annual report to security holders that contains audited financial statements as required by rules under the Exchange Act under certain limited circumstances. The delegation of authority is intended to conserve Commission resources by permitting the staff to review and act on exemptive applications under Section 36 when appropriate.
Celeste M. Murphy, Special Counsel, at (202) 551-3440, Office of Mergers and Acquisitions, Division of Corporation Finance, Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-3628.
The Commission today announces an amendment to its Organization and Program Management Rules governing Delegations of Authority to the Director of the Division of Corporation Finance.
A number of companies have faced the dilemma of being required to hold a meeting of security holders when they are unable to deliver current audited financial statements. These companies may be compelled to hold meetings of their security holders pursuant to the provisions of certain state corporation
Section 36(a) provides that “the Commission, by rule, regulation, or order, may conditionally or unconditionally exempt any person, security, or transaction, or any class or classes of persons, securities, or transactions, from any provision or provisions of this title or of any rule or regulation thereunder, to the extent that such exemption is necessary or appropriate in the public interest, and is consistent with the protection of investors.”
The delegation of authority to the Director is intended to conserve Commission resources by permitting the staff, pursuant to Section 36(a), to review and act on applications for exemption from Rule 14a-3(b) and Rule 14c-3(a) in cases where upon examination, the matter does not appear to present significant issues that have not been addressed previously or to raise questions of fact or policy indicating that the public interest or the interest of investors warrants that the Commission consider the matter. Nevertheless, the staff may submit matters to the Commission for consideration as it deems appropriate. In addition, under Section 4A(b) of the Exchange Act, the Commission retains discretionary authority to review upon its own initiative or, pursuant to Commission Rule 430, upon application by a party adversely affected, any exemption granted or denied by the Director pursuant to delegated authority.
The Commission finds, in accordance with Section 553(b)(3)(A) of the Administrative Procedure Act,
Administrative practice and procedure, Authority delegations (Government agencies), Organization and functions (Government agencies).
15 U.S.C. 77o, 77s, 77sss, 78d, 78d-1, 78d-2, 78w, 78ll(d), 78mm, 80a-37, 80b-11, and 7202, unless otherwise noted.
(e) * * *
(18) To review and, either unconditionally or upon specified terms and conditions, grant or deny exemptions from the requirements of Rules 14a-3(b) and 14c-3(a) (§§ 240.14a-3(b) and 240.14c-3(a) of this chapter) under the Act pursuant to Section 36 of the Act, in cases where upon examination, the matter does not appear to the Director to present significant issues that have not been addressed previously or to raise questions of fact or policy indicating that the public interest or the interest of investors warrants that the Commission consider the matter, where an applicant demonstrates that it:
(i) Is required to hold a meeting of security holders as a result of an action taken by one or more of the applicant's security holders pursuant to state law;
(ii) Is unable to comply with the requirements of Rule 14a-3(b) or Rule 14c-3(a) under the Act for audited financial statements to be included in the annual report to security holders to be furnished to security holders in connection with the security holder meeting required to be held as a result of the security holder demand under state law;
(iii) Has made a good faith effort to furnish the audited financial statements before holding the security holder meeting;
(iv) Has made a determination that it has disclosed to security holders all available material information necessary for the security holders to make an informed voting decision in accordance with Regulation 14A or Regulation 14C (§§ 240.14a-1-240.14b-2 or §§ 240.14c-1-240.14c-101 of this chapter); and
(v) Absent a grant of exemptive relief, it would be forced to violate either state law or the rules and regulations administered by the Commission.
By the Commission.
Mine Safety and Health Administration (MSHA), Labor.
Final rule.
The Mine Safety and Health Administration (MSHA) is revising its civil penalty assessment amounts to adjust for inflation. The Debt Collection Improvement Act of 1996 (DCIA) requires MSHA to adjust all civil penalties for inflation at least once every four years according to the formula specified in the Federal Civil Penalties Inflation Adjustment Act of 1990 (Inflation Adjustment Act). The revised penalties apply to citations and orders issued on or after the effective date of this rule.
This final rule is effective on March 10, 2008.
Patricia W. Silvey, Director, Office of Standards, Regulations, and Variances, MSHA, 1100 Wilson Blvd., Room 2350, Arlington, Virginia 22209-3939,
The Administrative Procedure Act (APA) requires that rulemakings be published in the
The Inflation Adjustment Act, as amended by the DCIA, requires MSHA to review and, where appropriate, adjust its civil penalties for inflation at least once every four years. The DCIA prescribes the formula for any such adjustments. The decision whether to make adjustments and the amount of any adjustments are not within MSHA's discretion. MSHA is required to perform mathematical computations based on published cost-of-living data and adjust its maximum penalties accordingly. For this reason, MSHA has determined for good cause that public notice and comment are unnecessary, impractical, or contrary to the public interest and that this rule should be published in final form. In accordance with the APA, this rule is effective 30 days after the date of publication in the
On March 22, 2007 (72 FR 13592), MSHA published the final rule, Criteria and Procedures for Proposed Assessment of Civil Penalties (Civil Penalties), that implemented the civil penalty provisions in Sections 5 and 8 of the Mine Improvement and New Emergency Response Act of 2006 (MINER Act) and revised existing civil penalty regulations in part 100 of Title 30 in the Code of Federal Regulations (CFR). Although MSHA significantly increased civil penalties in the final rule, the Agency retained the $60,000 maximum for non-flagrant civil penalties. The Agency also retained the $6,500 maximum daily penalty and the $275 maximum penalty for smoking or carrying smoking materials.
In passing the Inflation Adjustment Act, Congress noted a concern for civil penalties to keep pace with inflation. Section 5 provides an inflation adjustment formula that defines a “cost-of-living” adjustment as—
(1) the Consumer Price Index for the month of June of the calendar year preceding the adjustment, exceeds
(2) the Consumer Price Index for the month of June of the calendar year in which the amount of such civil monetary penalty was last set or adjusted pursuant to law.
Section 3(3) defines the term “Consumer Price Index” (CPI) to mean “the Consumer Price Index for all-urban consumers published by the Department of Labor.”
Section 5(a) included criteria for rounding the cost-of-living adjustment amount as follows:
Any increase * * * shall be rounded to the nearest—
(1) multiple of $10 in the case of penalties less than or equal to $100;
(2) multiple of $100 in the case of penalties greater than $100 but less than or equal to $1,000;
(3) multiple of $1,000 in the case of penalties greater than $1,000 but less than or equal to $10,000;
(4) multiple of $5,000 in the case of penalties greater than $10,000 but less than or equal to $100,000;
(5) multiple of $10,000 in the case of penalties greater than $100,000 but less than or equal to $200,000; and
(6) multiple of $25,000 in the case of penalties greater than $200,000.
This final rule makes a cost-of-living adjustment to MSHA's proposed civil penalty assessment amounts in accordance with the Inflation Adjustment Act. MSHA is adjusting the following three civil penalties in 30 CFR part 100: The maximum civil penalty, the maximum daily penalty, and the maximum miner smoking penalty. These penalties were last adjusted, as appropriate, in 2003 based on the CPI of the previous year. MSHA adjusted the maximum civil penalty and the maximum daily penalty. The maximum smoking penalty was last adjusted in 1998 from $250 to $275. It was not adjusted in 2003 because the increase under the inflation adjustment formula rounded to zero.
MSHA is adjusting the maximum civil penalty and the maximum daily penalty based on the percentage change in the CPI between June of 2003 and June of 2007. MSHA is adjusting the maximum smoking penalty based on the percentage change in the CPI between June 1998 and June 2007.
During the four-year period from June 2003 to June 2007, inflation was approximately 13.4%. During the nine-year period from June 1998 to June 2007, inflation was approximately 27.8%. In the final rule, MSHA has adjusted the maximum civil penalty and the maximum daily penalty by 13.4% and the maximum smoking penalty by 27.8%, and rounded each increase in accordance with the Congressional rounding formula.
The following is an analysis of the final rule's effect on existing civil penalty amounts.
This section addresses the determination of a penalty amount for violations of the Mine Act, as amended, and MSHA's safety and health regulations, under the regular civil penalty assessment provision.
Final § 100.3(a)(1) provides the criteria for determining penalty assessments and specifies a maximum dollar amount for a proposed civil penalty assessment. To adjust the existing maximum civil penalty assessment of $60,000 for inflation, MSHA applied the 13.4% inflation increase, which resulted in $8,052. MSHA rounded the increase to $10,000 in accordance with the Inflation Adjustment Act. This final rule increases the maximum civil penalty to $70,000.
Section 100.3(g) contains a penalty conversion table that correlates the total points assigned for each criterion listed in this section with a proposed civil penalty dollar amount. The existing rule provides a penalty range of $112 to $60,000, and violations assessed through the regular formula receive the maximum penalty only if they receive 140 points or more. The final rule provides a penalty range of $112 to $70,000, and violations receive the maximum penalty if they receive 144 points or more.
Violations receiving 140 or fewer points have no penalty increase because MSHA last adjusted these penalties in March 2007, and the average penalty increase at that time was greater than the amount of inflation.
Under the existing penalty conversion table, assessments for violations with 133 to 140 points increase at a constant rate of $3,071 per point. Final § 100.3(g) provides that assessments for violations with 141 or more points increase at the same constant rate of $3,071 per point until the new maximum penalty is reached. The final rule assigns a regularly assessed violation with more than 140 points new penalty amounts of: 141 points, $63,071; 142 points, $66,142; 143 points, $69,213; and 144 or more points, $70,000.
Section 100.5 provides for a special assessment for violations that MSHA determines should not be processed under the regular assessment provision. Once MSHA determines that a special assessment is appropriate, the Agency will base the proposed penalty on the criteria listed in § 100.3(a).
Section 100.5(c) addresses penalties which may be assessed daily to an
Section 100.5(d) addresses penalties for miners who violate mandatory safety standards relating to smoking and smoking materials underground. The existing maximum smoking penalty is $275. MSHA applied the 27.8% inflation increase, which resulted in $77. MSHA rounded the increase to $100 in accordance with the Inflation Adjustment Act. This final rule raises the maximum smoking penalty to $375.
Executive Order 12866 requires that regulatory agencies assess both the costs and benefits of significant regulatory actions. Under the Executive Order, a “significant regulatory action” is one meeting any of a number of specified conditions, including the following: Having an annual effect on the economy of $100 million or more, creating a serious inconsistency or interfering with an action of another agency, materially altering the budgetary impact of entitlements or the rights of entitlement recipients, or raising novel legal or policy issues. This rule is not classified as a “significant” regulatory action. MSHA, however, is providing the following summary of the costs and benefits of this regulatory action.
This final rule will apply to the entire mining industry. Based on 2006 data, this rule covers 2,113 coal mines employing 81,985 miners and 3,708 office workers; and 12,772 metal and nonmetal mines employing 157,850 miners and 26,727 office workers. In addition, this rule covers 2,724 independent contractors in coal mines employing 37,282 workers, and 4,686 independent contractors in metal and nonmetal mines employing 55,945 workers.
MSHA has qualitatively determined that this final rule will yield health and safety benefits by keeping civil penalties at a constant level, adjusted for inflation, in accordance with the Inflation Adjustment Act.
For purposes of analyzing the economic effects of this final rule, MSHA focuses on the likely change in costs to mine operators and independent contractors that receive civil penalties.
The estimated cost of this final rule is the change in dollar amounts paid for civil penalties. There is no real cost of the rule because the increase in the amount of civil penalties adjusts for inflation. However, there is a “nominal” cost attributable to the rule. A nominal cost reflects the increase in absolute dollars, unadjusted for any change in the price level. MSHA addresses the nominal cost of the rule below.
This final rule raises the maximum civil penalty, the maximum daily penalty, and the maximum smoking penalty. In its cost analysis, based upon experience, MSHA estimates that the final rule will not have a significant cost impact due to the adjustment of the maximum civil penalty. MSHA has not estimated costs for increases in the maximum daily penalty and maximum smoking penalty. The Agency concludes that they will result in a de minimis cost impact.
Three types of violations are affected by an increase in the maximum civil penalty:
(1) Violations processed as special assessments that receive the maximum penalty. Based on historical data on special assessments for the maximum penalty, MSHA estimates an average of 13 violations per year. MSHA assumes that the increased cost would be $10,000 for each special assessment receiving the maximum penalty.
(2) Violations processed as regular assessments with 141 or more points that do not receive a 10% discount for timely abatement. MSHA estimates that five violations per year will be of this type. Violations that receive 141-143 points will receive an average increase of $6,142 under this final rule; violations that receive 144 or more points will receive an increase of $10,000. MSHA estimates that two violations will receive 141-143 points and three will receive 144 or more points, for an average increase of $8,457.
(3) Violations processed as regular assessments with 141 or more points that receive a 10% discount for timely abatement. MSHA estimates that approximately 11 violations per year will be of this type. Violations that receive 141-143 points will receive an average increase of $5,528; violations that receive 144 or more penalty points will receive an increase of $9,000. MSHA estimates that four violations will receive 141-143 points and seven will receive 144 or more points, for an average increase of $7,737.
Table IV-1 summarizes MSHA's analysis.
MSHA has concluded that the requirements of this final rule are technologically and economically feasible.
The Regulatory Flexibility Act (RFA) of 1980, as amended by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements unless the agency certifies that the rule will not have a significant impact on a substantial number of small entities. As notice and public comment are not
The annual cost of the rule for coal mines is $229,286, of which $201,180 would be for coal mines with 1-500 employees. The annual cost of the rule for metal and nonmetal mines is $28,106, of which $23,668 would be for metal and nonmetal mines with 1-500 employees. MSHA has concluded that the final rule will not have a significant impact on a substantial number of small entities.
This final rule does not require any paperwork or information collection.
This final rule does not include any Federal mandate that may result in increased expenditures by State, local, or tribal governments; nor does it increase private sector expenditures by more than $100 million annually; nor does it significantly or uniquely affect small governments. Accordingly, the Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1501
This final rule 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.” Accordingly, Executive Order 13132, Federalism, requires no further agency action or analysis.
This final rule will have no effect on family well-being or stability, marital commitment, parental rights or authority, or income or poverty of families and children. Accordingly, § 654 of the Treasury and General Government Appropriations Act of 1999 (5 U.S.C. 601 note) requires no further agency action, analysis, or assessment.
This final rule will not implement a policy with takings implications. Accordingly, Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights, requires no further agency action or analysis.
This final rule was drafted and reviewed in accordance with Executive Order 12988, Civil Justice Reform. This final rule was written to provide a clear legal standard for affected conduct and was carefully reviewed to eliminate drafting errors and ambiguities, so as to minimize litigation and undue burden on the Federal court system. MSHA has determined that this final rule meets the applicable standards provided in § 3 of Executive Order 12988.
This final rule will have no adverse impact on children. Accordingly, Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks, as amended by Executive Orders 13229 and 13296, requires no further agency action or analysis.
This final rule does not have “tribal implications” because it does not “have substantial direct effects 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.” Accordingly, Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, requires no further agency action or analysis.
This final rule has been reviewed for its impact on the supply, distribution, and use of energy because it applies to the coal mining industry. Insofar as this final rule will result in added yearly civil penalty assessments of approximately $229,000 to the coal mining industry, relative to annual revenues of $28.9 billion in 2006, it is not a “significant energy action” because it is not “likely to have a significant adverse effect on the supply, distribution, or use of energy * * * (including a shortfall in supply, price increases, and increased use of foreign supplies).” Accordingly, Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use, requires no further Agency action or analysis.
MSHA has reviewed the final rule to assess and take appropriate account of its potential impact on small businesses, small governmental jurisdictions, and small organizations. MSHA has determined and certified that the final rule will not have a significant economic impact on a substantial number of small entities.
The Congressional Review Act, codified at 5 U.S.C. 801 et seq., provides generally that “major rules” cannot take effect until 60 days after publication of the rule in the
Mine safety and health, Penalties.
30 U.S.C. 815, 820, 957.
(a)
(g) * * *
(c) Any operator who fails to correct a violation for which a citation has been issued under Section 104(a) of the Mine Act within the period permitted for its correction may be assessed a civil penalty of not more than $7,500 for each day during which such failure or violation continues.
(d) Any miner who willfully violates the mandatory safety standards relating to smoking or the carrying of smoking materials, matches, or lighters shall be subject to a civil penalty of not more than $375 for each occurrence of such violation.
Environmental Protection Agency (EPA).
Final rule.
EPA is issuing amendments to the national emission standards for hazardous air pollutants (NESHAP) for iron and steel foundries. These final amendments add alternative compliance options for cupolas at existing foundries and clarify several provisions to increase operational flexibility and improve understanding of the final rule requirements.
These final amendments are effective on February 7, 2008. The incorporation by reference of certain publications listed in these amendments is approved by the Director of the Federal Register as of February 7, 2008.
EPA has established a docket for this action under Docket ID No. EPA-HQ-OAR-2002-0034. All documents in the docket are listed in the Federal Docket Management System index at
Mr. Phil Mulrine, Sector Policies and Programs Division, Office of Air Quality Planning and Standards (D243-02), Environmental Protection Agency, Research Triangle Park, North Carolina 27711, telephone number: (919) 541-5289; fax number: (919) 541-3207; e-mail address:
The information presented in this preamble is organized as follows:
The regulated categories and entities potentially affected by these final amendments include:
This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be affected by this action. To determine whether your facility would be regulated by this action, you should examine the applicability criteria in 40 CFR 63.7682 of subpart EEEEE (NESHAP for Iron and Steel Foundries). If you have any questions regarding the applicability of this action to a particular entity, consult either the air permit authority for the entity or your EPA regional representative as listed in 40 CFR 63.13 of subpart A (General Provisions).
In addition to being available in the docket, an electronic copy of this final action will also be available on the Worldwide Web (WWW) through the Technology Transfer Network (TTN). Following signature, a copy of this final action will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at the following address:
Under section 307(b)(1) of the Clean Air Act (CAA), judicial review of these final amendments is available only by filing a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit by April 7, 2008. Under section 307(d)(7)(B) of the CAA, only an objection to these final amendments that was raised with reasonable specificity during the period for public comment can be raised during judicial review. Moreover, under section 307(b)(2) of the CAA, the requirements established by these final amendments may not be challenged separately in any civil or criminal proceedings brought by EPA to enforce these requirements.
The NESHAP for iron and steel foundries (40 CFR part 63, subpart EEEEE) establishes emissions limitations and work practice requirements for the control of hazardous air pollutants (HAP) from foundry operations. The NESHAP implements section 112(d) of the CAA by requiring all iron and steel foundries that are major sources of HAP to meet standards reflecting application of the maximum achievable control technology (MACT). The compliance date for most of the subpart EEEEE requirements was April 23, 2007.
After publication of the NESHAP (69 FR 21906, April 22, 2004), the American Foundry Society, the Alliance of Automobile Manufacturers, and the Steel Founders' Society of America filed petitions for reconsideration of the final rule. The American Foundry Society and the Steel Founders' Society of America also filed petitions for review of the final rule (
In accordance with section 113(g) of the CAA, EPA published a notice of a proposed settlement agreement between EPA and the petitioner (72 FR 1986, January 17, 2007) and provided a 30-day comment period which ended on February 16, 2007. The settlement agreement became final on March 9, 2007. On April 17, 2007 (72 FR 19150), we proposed rule amendments which addressed the need for alternative emissions limits for cupolas at existing foundries and clarification of other rule requirements as set forth in Attachment A to the settlement agreement. The proposed amendments also included corrections to a few minor editorial errors.
These final amendments are materially the same as the proposed amendments. EPA expects these final amendments to resolve the remaining issues raised by the petitioner.
These final amendments include two changes since proposal. The first change is in the wording used to describe the emission limit for the new compliance option for cupola melting furnaces; instead of abbreviating the limit as lb/
These final amendments add a new compliance option to § 73.7690(a)(2) of the NESHAP. The new alternative emissions limits for cupola metal melting furnaces at existing iron and steel foundries allows the use of control technologies that are designed on a mass removal basis rather than an outlet concentration basis. The levels of the new alternative emissions limits are the same as proposed: 0.10 pound of PM per ton of metal charged or 0.008 pound of total HAP per ton of metal charged. In response to public comment, we have revised the manner in which the emissions limits are stated in the rule for clarity. We have also revised associated compliance provisions in §§ 63.7732(b)(6) and (c)(6), 63.7734(a)(2)(iii) and (iv), and 63.7743(a)(2)(iii) and (iv) to refer to the new alternative limits in terms of pounds of PM per ton (lb/ton) of metal charged or pounds of total metal HAP per ton of metal charged instead of lb/ton of PM or lb/ton of total metal HAP, respectively.
These final amendments specify that the opacity limitations apply only to buildings that house iron and steel foundry emissions sources. If nonfoundry operations are housed in the same building as the foundry operations, the foundry must comply with the opacity limits for that building.
These final amendments replace the reference to test conditions (“as determined when scrubbing with fresh acid solution”) with the phrase “according to the performance test procedures in § 63.7732(g)” since § 63.7732(g) contains the requirement to conduct the test when scrubbing with fresh acid solution.
These final amendments delete the word “standard” from 40 CFR 63.7690(b)(1) to clarify that capture and collection systems are required for emissions sources subject to an emissions limit but not for emissions sources subject to work practice standards.
These final amendments specify that “chlorinated” plastics are to be removed from the scrap material (instead of all plastic). These final amendments also revise the requirement in 40 CFR 63.7700(c)(2) for the owner or operator to obtain and maintain onsite a copy of the procedures used by the scrap supplier for either removing accessible mercury switches or for purchasing automobile bodies that have had the switches removed. These final amendments include an alternative procedure that allows the plant to document their attempts to obtain a copy of the procedures from the scrap suppliers servicing their area. We note, however, that under 40 CFR 63.7700(c)(2) the materials acquisition program must specify that the scrap supplier remove accessible mercury switches from the trunks and hoods of any automotive bodies contained in the scrap in addition to accessible lead components such as batteries and wheel weights. It is incumbent on the foundry owner or operator to communicate these specifications to their scrap suppliers.
The existing rule requires the owner or operator to install, operate, and maintain a gas-fired preheater according to 40 CFR 63.7700(e)(1) or charge only certain materials according to 40 CFR 63.7700(e)(2). These final amendments revise the language of § 63.7700(e)(1) to clarify that foundries are not required to install gas-fired preheaters when not necessary for foundry operations. It was not our intent to mandate installation of preheaters, but rather to establish requirements for those existing facilities that use scrap preheaters in lieu of selecting the option in 40 CFR 63.7700(e)(2). Therefore, these final amendments clarify § 63.7700(e)(1) by deleting the word “install”. Instead, these final amendments require the owner or operator to operate and maintain a gas-fired preheater where the flame directly contacts the scrap charged.
These final amendments clarify that the requirement in 40 CFR 63.7700(e)(2) applies to each capture and collection system and control device for an emissions source subject to a PM, metal HAP, triethylamine (TEA), or volatile organic hazardous pollutants (VOHAP) emissions limit in 40 CFR 63.7690(a).
The existing NESHAP establishes PM emissions limits and alternative emissions limits expressed in total metal HAP for cupolas and other foundry processes. These final amendments clarify our original intent to allow foundries to demonstrate compliance with any of the applicable alternative emissions limitations that are provided for a specific emissions source. When multiple alternative emissions limitations are provided for a specific emissions source, iron and steel foundries can demonstrate initial compliance with any of the alternative limits; they are not required to comply with all of the alternative emissions limits at any one time. These final amendments also clarify a facility's ability to change their selected compliance alternative and the procedures needed to effect that change. However, regarding continuous compliance, the facility is expected to continuously comply with the alternative emissions limit that was selected as their compliance option as demonstrated in their most recent performance test. The facility may choose to alter their selected alternative but must continue to comply with the previously selected alternative until they successfully demonstrate compliance with the new alternative emissions limitation.
We are also finalizing requirements for determining initial compliance for cupola melting furnaces at existing iron and steel foundries that are subject to the new mass rate emissions limit. The final amendments to 40 CFR 63.7732(b) and (c) include new equations for determining PM or total metal HAP emissions from cupolas in the lb/ton of metal charged format. Other amendments to 40 CFR 63.7732(b) and (c) clarify test methods source sampling requirements.
Section 63.7734 of the NESHAP requires iron and steel foundries to demonstrate initial compliance with PM emissions limits by conducting a performance test for each process unit according to the procedures in 40 CFR 63.7732. One petitioner pointed out that a common emissions control system may serve two similar or identical cupolas or serve multiple furnaces or process units. According to the petitioner, a requirement for separate tests of the control device while the
As proposed, we are clarifying the sampling instructions in 40 CFR 63.7732(c)(4) and (5) to state that the initial compliance demonstrations for electric arc metal melting furnaces, electric induction metal melting furnaces, and scrap preheaters must be conducted under normal production conditions. These final amendments require sampling during normal operating conditions, which may include charging, melting, alloying, refining, slagging, and tapping (for a furnace) or charging, heating, and discharging (for a scrap preheater).
As proposed, these final amendments remove the requirement in 40 CFR 63.7732(c)(2) for a minimum sample volume for test runs by EPA Method 29 (40 CFR part 60, appendix A) because the method already includes such a requirement.
Section 63.7732(d) of the existing NESHAP establishes the requirements for opacity tests. These final amendments instruct the certified observer how to take opacity readings by Method 9 (40 CFR part 60, appendix A) for a building that has many openings. As proposed, these final amendments allow the observer to take readings from a limited number of openings or vents that appear to have the highest opacities instead of making observations for each opening or vent from the building or structure. Alternatively, a single observation for the entire building is allowed if the fugitive release points afford such an observation. These final amendments also revise the language of 40 CFR 63.7732(d)(2) to clarify that opacity tests are to be conducted during PM performance tests, but that PM performance tests are not required to occur during the semiannual opacity tests.
Section 63.7732(g)(v) of the existing NESHAP requires the use of EPA Method 18 (40 CFR part 60, appendix A) to determine the TEA concentration of gases from the TEA cold box mold or core-making line. As proposed, these final amendments allow NIOSH Method 2010, “Amines, Aliphatic” (incorporated by reference—see § 63.14) as an alternative to EPA Method 18 (40 CFR part 60, appendix A) provided the performance requirements outlined in section 13.1 of EPA Method 18 are satisfied. Method 2010 is included in the
As proposed, these final amendments clarify the procedures for establishing control device operating limits in 40 CFR 63.7733(b) through (d) by deleting the reference to the 3-hour average from the test procedures. These final amendments specify that the owner or operator is to compute and record the average operating parameter value for each valid sampling run in which the applicable limit is met.
As proposed, these final amendments revise the requirements for repeat performance in 40 CFR 63.7731(a) to clarify that demonstrating compliance by one method does not preclude a plant from demonstrating compliance using an alternative method at a later date. A plant may elect to demonstrate compliance with an alternative emissions limit during the repeat performance tests conducted at least every 5 years. Furthermore, a plant may elect to conduct a performance test earlier than 5 years in order to change an operating limit or to demonstrate compliance with a different alternative emissions limit. A test conducted for the purpose of changing operating limits is subject to notification requirements in 40 CFR 63.7750(d).
Section 63.7740(b) of the existing NESHAP requires a bag leak detection system for each negative pressure baghouse and for each positive pressure baghouse equipped with a stack where the baghouse is applied to meet any PM or total metal HAP emissions limitation in subpart EEEEE. This provision also requires inspection of each baghouse according to the requirements in 40 CFR 63.7740(b)(1) through (8). As proposed, these final amendments include monitoring requirements for the visual inspection of positive pressure baghouses that are not equipped with a stack. As proposed, these final amendments to 40 CFR 63.7740(b) clarify the text to ensure that the requirements in this paragraph for installing and using a bag leak detection system apply only to negative pressure baghouses and positive pressure baghouses equipped with a stack. The inspection requirements are separated and placed in a new paragraph (c) and clarified to state that the inspection requirements apply to each baghouse regardless of type. These final amendments to 40 CFR 63.7740 also renumber the paragraphs which follow new paragraph (c). Similar clarifications are made to the requirements for demonstrating continuous compliance in 40 CFR 63.7743(c).
Section 63.7736(c) of the existing NESHAP instructs the owner or operator how to demonstrate initial compliance with the requirements for bag leak detection systems. Under 40 CFR 63.7736(c)(1), the owner or operator must submit the bag leak detection system monitoring plan to the Administrator for approval according to the requirements in 40 CFR 63.7710(b). As proposed, these final amendments to 40 CFR 63.7736(c)(1) revise this provision to clarify that submission of the monitoring plan independent of the operation and maintenance plan is not necessary. Our intent is to include the bag leak detection system information in the operation and maintenance plan to streamline the approval process and avoid the administrative costs associated with a separate submission.
As proposed, these final amendments revise the requirements for operation and maintenance of continuous parameter monitoring systems to more clearly describe the inspection requirements. Under the operation and maintenance requirements for flow measurement devices in 40 CFR 63.7741(a)(1)(iv), the owner or operator must perform monthly inspections of all flow sensor components for integrity, all electrical connections for continuity, and all mechanical connections for leakage. These final amendments change this provision to require a monthly visual inspection of all components, including all electrical and mechanical connections for proper functioning. The same changes are made to the monthly inspection requirements for other types of monitoring devices in §§ 63.7741(a)(2)(vi), (c)(1)(vi), (c)(2)(iv), (d)(8), and (e)(2)(iv).
As proposed, these final amendments also revise the requirement for pressure measurement devices in 40 CFR 63.7741(a)(2)(iii) and 40 CFR 63.7741(c)(1)(iv) for a “daily check of the pressure tap for pluggage.” We are requiring a daily check for pluggage when using a regular pressure tap and a monthly check when using a non-clogging pressure tap. These final amendments also clarify the requirements for pressure measurement devices in 40 CFR 63.7741(a)(2)(iv) and 40 CFR 63.7741(c)(1)(iv) to allow the use of a manometer or equivalent device for calibrations.
As proposed, these final amendments clarify two of the recordkeeping requirements in 40 CFR 63.7752(a)(4). The requirement for the annual quantity of chemical binder or coating materials used to make molds and cores is revised to require the annual quantity of chemical binder or coating materials used to coat or make molds and cores. (We inadvertently omitted the word “coat” from the original rule language.) The final requirement for records of the annual quantity of HAP used states that records are required of the annual quantity of HAP used in these chemical binder or coating materials at the foundry, as calculated from the recorded quantities and chemical compositions (from Material Data Safety Sheet or other documentation). This final amendment clarifies that the HAP records requirement is specific to the chemicals used in the mold and core-making and coating operations and not to other HAP materials used at the foundry such as solvents used to clean or degrease equipment.
These final amendments to the reporting requirements allow foundries to report the results of the semiannual opacity tests within the semiannual reports rather than having to submit these semiannual documents separately. Other final amendments to the reporting requirements clarify the requirements for an immediate startup, shutdown, and malfunction report by adding the same language used in 40 CFR 63.10(d)(5)(ii). These final amendments require an immediate report if a foundry has a startup, shutdown, or malfunction and exceeds any applicable emissions limitation in 40 CFR 63.7690.
We are amending the definition of the term “Deviation” in 40 CFR 63.7765 to clarify that the enforcement authority determines if a deviation is a violation. The proposed amendment appeared at 72 FR 19164: however, due to a publication error, the new language was added after the first sentence of the original definition, rather than at the end. In these final amendments, we are correcting the placement of the new language.
As proposed, we are adding definitions of the terms “off blast” and “on blast” to 40 CFR 63.7765. The term “off blast” is defined as those periods of cupola operation when the cupola is not actively being used to produce molten metal. Off-blast conditions include cupola startup procedures as defined in the startup, shutdown, and malfunction plan. Off-blast conditions also include idling conditions when the blast air is turned off or down to the point that the cupola does not produce additional molten metal. The term “on blast” means those periods of cupola operation when combustion (blast) air is introduced to the cupola furnace and the furnace is capable of producing molten metal. On blast conditions are characterized by both blast air introduction and molten metal production.
As proposed, these final amendments revise the definition of “total metal HAP” to specify the analytes to be included and how non-detect values are to be used in calculating the total metal HAP quantity. The definition of “total metal HAP” is the sum of the concentrations of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, mercury, nickel, and selenium as measured by EPA Method 29 (40 CFR part 60, appendix A). Only the measured concentration of the listed analytes that are present at concentrations exceeding one-half of the quantification limit of the analytical method are used in the sum. If any of the analytes are not detected or are detected at concentrations less than one-half the quantification limit of the analytical method, the concentration of those analytes is assumed to be zero for the purposes of calculating the total metal HAP for this subpart.
As proposed, we are also clarifying the definition of “scrap preheater” to differentiate scrap dryers that are used solely to remove moisture from the scrap metal from scrap preheaters. The revised definition of “scrap preheater” states that scrap dryers, which are used solely to remove water from metal scrap that does not contain any volatile impurities or other tramp materials, are not considered to be scrap preheaters for purposes of this subpart.
As proposed, we are revising the applicability provisions in 40 CFR 63.7681 to reference the definition of “major source” in 40 CFR 63.2. This amendment clarifies that when we refer to a “major source” of hazardous air pollutants in 40 CFR 63.7681, we are referring to the definition of major source in 40 CFR 63.2, and not, for example, to the definition of major source in 40 CFR 51.166.
As proposed, we are correcting a grammatical error in 40 CFR 63.7710(b), which should refer to an emissions source subject to
A re-evalulation of the MACT floor for the Iron and Steel NESHAP in light of new control systems added to iron and steel foundries since the NESHAP was first promulgated is outside the scope of the current package of amendments. We did not include or take comment on a separate mercury limit in our April 17, 2007 Notice of Proposed Rulemaking. Therefore, we are not including specific emission limits for mercury in the final amendments. A technology review of the MACT standards is required by the CAA eight years after promulgation. These newly installed mercury controls will be considered in detail during this technology review.
The commenter stated that this proposed amendment increases mercury emissions and that EPA did not provide an estimate of the health, environmental, and economic impacts of the increase. The commenter also claimed that because of limitations currently enforced on some sources, the proposed amendment reduces the stringency of the rule below the MACT floor for new sources and possibly for existing sources. According to the commenter, the proposed amendment is inconsistent with the CAA.
This action is not a “significant regulatory action” under the terms of Executive Order 12866 (58 FR 51735,
This action does not impose any new information collection burden. These final amendments add a new compliance alternative, allow a new alternative test method, and clarify requirements in the existing rule. One amendment to the baghouse monitoring requirements clarifies our original intent to require inspections of positive pressure baghouses not equipped with a stack. No new burden is associated with this requirement because the burden was included in the approved information collection request (ICR) for the existing rule. However, the Office of Management and Budget (OMB) has previously approved the information collection requirements contained in the existing regulation (40 CFR part 63, subpart EEEEE) under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501,
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, 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 part 63 are listed in 40 CFR part 9.
The Regulatory Flexibility Act 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 would not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small not-for-profit enterprises, and small governmental jurisdictions.
For the purposes of assessing the impacts of these final amendments on small entities, small entity is defined as: (1) A small business that meets the Small Business Administration size standards for small businesses found at 13 CFR 121.201 (less than 500 employees for NAICS codes 331511, 331512, and 331513); (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.
After considering the economic impacts of these final amendments on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. In determining whether a rule has a significant economic impact on a substantial number of small entities, the impact of concern is any significant
There would not be any adverse impacts on any source (including any small entity) as a result of the final amendments because the final amendments do not create any new requirements or burdens that were not already included in the economic impact assessment for the existing rule. These final amendments relieve regulatory burden for all entities as a result of the operational flexibility afforded by the alternative compliance option, alternative test method, and provisions allowing plants to combine multiple reports into a single submission. We have therefore concluded that these final amendments will relieve regulatory burden for all affected 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 by State, local, and tribal governments, in the aggregate, or by 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 proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements.
EPA has determined that these final amendments do 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. The final amendments are expected to result in an overall reduction in expenditures for the private sector and are not expected to impact State, local, or tribal governments. Thus, the final amendments are not subject to the requirements of sections 202 and 205 of the UMRA. EPA has determined that these final amendments contain no regulatory requirements that might significantly or uniquely affect small governments. These final amendments
Executive Order 13132 (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” are 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.”
These final amendments do not have federalism implications. They 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. These final amendments do not impose any requirements on State and local governments. Thus, Executive Order 13132 does not apply to these final amendments.
Executive Order 13175 (65 FR 67249, November 6, 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.” These final amendments do not have tribal implications, as specified in Executive Order 13175. These final amendments impose no requirements on tribal governments. Thus, Executive Order 13175 does not apply to these final amendments.
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, EPA 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 are based on health or safety risks, such that the analysis required under section 5-501 of the Executive Order has the potential to influence the regulation. These final amendments are not subject to Executive Order 13045 because they are based on technology performance and not on health or safety risks.
These final amendments are not subject to Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001) because they are not a significant regulatory action under Executive Order 12866.
As noted in the proposed rule, Section 12(d) of the National Technology Transfer and Advancement Act (NTTAA) of 1995 (Pub. L. 104-113, Section 12(d), 15 U.S.C. 272 note) directs EPA to use voluntary consensus standards (VCS) in its regulatory activities, unless to do so would be inconsistent with applicable law or otherwise impractical. The VCS are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by VCS bodies. The NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency does not use available and applicable VCS.
These final amendments involve technical standards. Therefore the Agency conducted a search to identify potential VCS in addition to the EPA and alternative method. However, we identified no such standards and none were brought to our attention in comments. Therefore EPA has decided to use an alternative methodology, the NIOSH Method 2010, “Amines, Aliphatic” (incorporated by reference in § 63.14) for EPA Method 18 (40 CFR part 60, appendix A) to determine the TEA concentration of gases from the TEA cold box mold or core making line provided the performance requirements outlined in section 13.1 of EPA Method 18 are satisfied.
For the methods required or referenced by these final amendments, a source may apply to EPA for permission to use alternative test methods or alternative monitoring requirements in place of any required testing methods, performance specifications, or procedures under §§ 63.7(f) and 63.8(f) of subpart A of the General Provisions.
Executive Order 12898 (59 FR 7629, February 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 has determined that these final amendments will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because they do not affect the level of protection provided to human health or the environment. These final amendments do not relax the control measures on sources regulated by the rule and therefore will not cause emissions increases from these sources.
The Congressional Review Act, 5 U.S.C. 801,
Environmental protection, Air pollution control, Hazardous substances, Incorporation by reference,
42 U.S.C. 7401,
(k) * * *
(2) The following method as published in the National Institute of Occupational Safety and Health (NIOSH) test method compendium, “NIOSH Manual of Analytical Methods”, NIOSH publication no. 94-113, Fourth Edition, August 15, 1994.
(i) NIOSH Method 2010, “Amines, Aliphatic,” Issue 2, August 15, 1994, IBR approved for § 63.7732(g)(1)(v) of Subpart EEEEE of this part.
(ii) [Reserved]
* * * Your iron and steel foundry is a major source of HAP for purposes of this subpart if it emits or has the potential to emit any single HAP at a rate of 10 tons or more per year or any combination of HAP at a rate of 25 tons or more per year or if it is located at a facility that emits or has the potential to emit any single HAP at a rate of 10 tons or more per year or any combination of HAP at a rate of 25 tons or more per year as defined in § 63.2.
(a) You must meet the emissions limits or standards in paragraphs (a)(1) through (11) of this section that apply to you. When alternative emissions limitations are provided for a given emissions source, you are not restricted in the selection of which applicable alternative emissions limitation is used to demonstrate compliance.
(2) For each cupola metal melting furnace at an existing iron and steel foundry, you must not discharge emissions through a conveyance to the atmosphere that exceed either the limit for PM in paragraph (a)(2)(i) or (ii) of this section or, alternatively the limit for total metal HAP in paragraph (a)(2)(iii) or (iv) of this section:
(i) 0.006 gr/dscf of PM; or
(ii) 0.10 pound of PM per ton (lb/ton) of metal charged, or
(iii) 0.0005 gr/dscf of total metal HAP; or
(iv) 0.008 pound of total metal HAP per ton (lb/ton) of metal charged.
(7) For each building or structure housing any iron and steel foundry emissions source at the iron and steel foundry, you must not discharge any fugitive emissions to the atmosphere from foundry operations that exhibit opacity greater than 20 percent (6-minute average), except for one 6-minute average per hour that does not exceed 27 percent opacity.
(11) * * *
(i) You must not discharge emissions of TEA through a conveyance to the atmosphere that exceed 1 ppmv, as determined according to the performance test procedures in § 63.7732(g); or
(ii) You must reduce emissions of TEA from each TEA cold box mold or core making line by at least 99 percent, as determined according to the performance test procedures in § 63.7732(g).
(b) * * *
(1) You must install, operate, and maintain a capture and collection system for all emissions sources subject to an emissions limit for VOHAP or TEA in paragraphs (a)(8) through (11) of this section.
(b) * * * Any post-consumer engine blocks, post-consumer oil filters, or oily turnings that are processed and/or cleaned to the extent practicable such that the materials do not include lead components, mercury switches, chlorinated plastics, or free organic liquids can be included in this certification.
(c) * * *
(1) * * *
(i) For scrap charged to a scrap preheater, electric arc metal melting furnace, or electric induction metal melting furnace, specifications for scrap materials to be depleted (to the extent practicable) of the presence of used oil filters, chlorinated plastic parts, organic liquids, and a program to ensure the scrap materials are drained of free liquids; or
(ii) For scrap charged to a cupola metal melting furnace, specifications for scrap materials to be depleted (to the extent practicable) of the presence of chlorinated plastic, and a program to ensure the scrap materials are drained of free liquids.
(2) * * * You must either obtain and maintain onsite a copy of the procedures used by the scrap supplier for either removing accessible mercury switches or for purchasing automobile bodies that have had mercury switches removed, as applicable, or document your attempts to obtain a copy of these procedures from the scrap suppliers servicing your area.
(3) * * *
(iii) The inspection procedures must include provisions for rejecting or returning entire or partial scrap shipments that do not meet specifications and limiting purchases from vendors whose shipments fail to meet specifications for more than three inspections in one calendar year.
(e) * * *
(1) You must operate and maintain a gas-fired preheater where the flame directly contacts the scrap charged; or
(b) You must prepare and operate at all times according to a written
(a) You must conduct subsequent performance tests to demonstrate compliance with all applicable PM or total metal HAP, VOHAP, and TEA emissions limitations in § 63.7690 for your iron and steel foundry no less frequently than every 5 years and each time you elect to change an operating limit or to comply with a different alternative emissions limit, if applicable. * * *
(a) You must conduct each performance test that applies to your iron and steel foundry based on your selected compliance alternative, if applicable, according to the requirements in § 63.7(e)(1) and the conditions specified in paragraphs (b) through (i) of this section.
(b) To determine compliance with the applicable emissions limit for PM in § 63.7690(a)(1) through (6) for a metal melting furnace, scrap preheater, pouring station, or pouring area, follow the test methods and procedures in paragraphs (b)(1) through (6) of this section.
(4) For electric arc and electric induction metal melting furnaces, sample only during normal production conditions, which may include, but are not limited to the following cycles: Charging, melting, alloying, refining, slagging, and tapping.
(5) For scrap preheaters, sample only during normal production conditions, which may include, but are not limited to the following cycles: Charging, heating, and discharging.
(6) Determine the total mass of metal charged to the furnace or scrap preheater. For a cupola metal melting furnace at an existing iron and steel foundry that is subject to the PM emissions limit in § 63.7690(a)(ii), calculate the PM emissions rate in pounds of PM per ton (lb/ton) of metal charged using Equation 1 of this section:
(c) To determine compliance with the applicable emissions limit for total metal HAP in § 63.7690(a)(1) through (6) for a metal melting furnace, scrap preheater, pouring station, or pouring area, follow the test methods and procedures in paragraphs (c)(1) through (6) of this section.
(2) A minimum of three valid test runs are needed to comprise a performance test.
(4) For electric arc and electric induction metal melting furnaces, sample only during normal production conditions, which may include, but are not limited to the following cycles: Charging, melting, alloying, refining, slagging, and tapping.
(5) For scrap preheaters, sample only during normal production conditions, which may include, but are not limited to the following cycles: Charging, heating, and discharging.
(6) Determine the total mass of metal charged to the furnace or scrap preheater during each performance test run and calculate the total metal HAP emissions rate (pounds of total metal HAP per ton (lb/ton) of metal charged) using Equation 2 of this section:
(d) To determine compliance with the opacity limit in § 63.7690(a)(7) for fugitive emissions from buildings or structures housing any iron and steel foundry emissions source at the iron and steel foundry, follow the procedures
(1) * * * The certified observer may identify a limited number of openings or vents that appear to have the highest opacities and perform opacity observations on the identified openings or vents in lieu of performing observations for each opening or vent from the building or structure. Alternatively, a single opacity observation for the entire building or structure may be performed, if the fugitive release points afford such an observation.
(2) During testing intervals when PM performance tests, if applicable, are being conducted, conduct the opacity test such the opacity observations are recorded during the PM performance tests.
(e) * * *
(3) For a cupola metal melting furnace, correct the measured concentration of VOHAP, TGNMO, or TOC for oxygen content in the gas stream using Equation 3 of this section:
(f) * * *
(2) * * *
(ix) Calculate the site-specific VOC emissions limit using Equation 4 of this section:
(3) For two or more exhaust streams from one or more automated conveyor and pallet cooling lines or automated shakeout lines, compute the flow-weighted average concentration of VOHAP emissions for each combination of exhaust streams using Equation 5 of this section:
(g) * * *
(1) * * *
(v) Method 18 to determine the TEA concentration. Alternatively, you may use NIOSH Method 2010 (incorporated by reference—see § 63.14) to determine the TEA concentration provided the performance requirements outlined in section 13.1 of EPA Method 18 are satisfied. The sampling option and time must be sufficiently long such that either the TEA concentration in the field sample is at least 5 times the limit of detection for the analytical method or the test results calculated using the laboratory's reported analytical detection limit for the specific field samples are less than
(2) If you use a wet acid scrubber, conduct the test as soon as practicable after adding fresh acid solution and the system has reached normal operating conditions.
(4) If you are subject to the 99 percent reduction standard, calculate the mass emissions reduction using Equation 6 of this section:
(h) * * *
(2) * * *
(ii) Calculate the flow-weighted average emissions limit, considering only the regulated streams, using Equation 5 of this section, except C
(3) * * *
(ii) Measure the flow rate and PM or total metal HAP concentration of the combined exhaust stream both before and after the control device and calculate the mass removal efficiency of the control device using Equation 6 of this section, except E
(iii) Meet the applicable emissions limit based on the calculated PM or total metal HAP concentration for the regulated emissions sources using Equation 7 of this section:
(i) To determine compliance with an emissions limit for situations when multiple sources are controlled by a single control device, but only one source operates at a time, or other situations that are not expressly considered in paragraphs (b) through (h) of this section, a site-specific test plan should be submitted to the Administrator for approval according to the requirements in § 63.7(c)(2) and (3).
(b) * * *
(2) Compute and record the average pressure drop and average scrubber water flow rate for each valid sampling run in which the applicable emissions limit is met.
(c) * * *
(2) Compute and record the average combustion zone temperature for each valid sampling run in which the applicable emissions limit is met.
(d) * * *
(2) Compute and record the average scrubbing liquid flow rate for each valid sampling run in which the applicable emissions limit is met.
(a) You have demonstrated initial compliance with the emissions limits in § 63.7690(a) by meeting the applicable conditions in paragraphs (a)(1) through (11) of this section. When alternative emissions limitations are provided for a given emissions source, you are not restricted in the selection of which applicable alternative emissions limitation is used to demonstrate compliance.
(2) * * *
(ii) The average total metal HAP concentration in the exhaust stream, determined according to the performance test procedures in § 63.7732(c), did not exceed 0.0005 gr/dscf; or
(iii) The average PM mass emissions rate, determined according to the performance test procedures in § 63.7732(b), did not exceed 0.10 pound of PM per ton (lb/ton) of metal charged; or
(iv) The average total metal HAP mass emissions rate, determined according to the performance test procedures in § 63.7732(c), did not exceed 0.008 pound of total metal HAP per ton (lb/ton) of metal charged.
(7) For each building or structure housing any iron and steel foundry emissions source at the iron and steel foundry, the opacity of fugitive emissions from foundry operations discharged to the atmosphere, determined according to the performance test procedures in § 63.7732(d), did not exceed 20 percent (6-minute average), except for one 6-minute average per hour that did not exceed 27 percent opacity.
(11) For each TEA cold box mold or core making line in a new or existing iron and steel foundry, the average TEA concentration, determined according to the performance test procedures in § 63.7732(g), did not exceed 1 ppmv or was reduced by 99 percent.
(c) * * *
(1) You have submitted the bag leak detection system monitoring information to the Administrator within the written O&M plan for approval according to the requirements of § 63.7710(b);
(b) For each negative pressure baghouse or positive pressure baghouse equipped with a stack that is applied to meet any PM or total metal HAP emissions limitation in this subpart, you must at all times monitor the relative change in PM loadings using a bag leak detection system according to the requirements in § 63.7741(b).
(c) For each baghouse, regardless of type, that is applied to meet any PM or total metal HAP emissions limitation in this subpart, you must conduct inspections at their specified frequencies according to the requirements specified in paragraphs (c)(1) through (8) of this section.
(1) Monitor the pressure drop across each baghouse cell each day to ensure pressure drop is within the normal operating range identified in the manual.
(2) Confirm that dust is being removed from hoppers through weekly visual inspections or other means of ensuring the proper functioning of removal mechanisms.
(3) Check the compressed air supply for pulse-jet baghouses each day.
(4) Monitor cleaning cycles to ensure proper operation using an appropriate methodology.
(5) Check bag cleaning mechanisms for proper functioning through monthly visual inspections or equivalent means.
(6) Make monthly visual checks of bag tension on reverse air and shaker-type baghouses to ensure that bags are not kinked (kneed or bent) or lying on their sides. You do not have to make this check for shaker-type baghouses using self-tensioning (spring-loaded) devices.
(7) Confirm the physical integrity of the baghouse through quarterly visual inspections of the baghouse interior for air leaks.
(8) Inspect fans for wear, material buildup, and corrosion through quarterly visual inspections, vibration detectors, or equivalent means.
(a) * * *
(1) * * *
(iv) At least monthly, visually inspect all components, including all electrical and mechanical connections, for proper functioning.
(2) * * *
(i) Locate the pressure sensor(s) in or as close as possible to a position that provides a representative measurement of the pressure and that minimizes or eliminates pulsating pressure, vibration, and internal and external corrosion.
(iii) Check the pressure tap for pluggage daily. If a “non-clogging” pressure tap is used, check for pluggage monthly.
(iv) Using a manometer or equivalent device such as a magnahelic or other pressure indicating transmitter, check gauge and transducer calibration quarterly.
(vi) At least monthly, visually inspect all components, including all electrical and mechanical connections, for proper functioning.
(b) For each negative pressure baghouse or positive pressure baghouse equipped with a stack that is applied to meet any PM or total metal HAP emissions limitation in this subpart, you must install, operate, and maintain a bag leak detection system according to the requirements in paragraphs (b)(1) through (7) of this section.
(c) * * *
(1) * * *
(iii) Check the pressure tap for pluggage daily. If a “non-clogging” pressure tap is used, check for pluggage monthly.
(iv) Using a manometer or equivalent device such as a magnahelic or other pressure indicating transmitter, check gauge and transducer calibration quarterly.
(vi) At least monthly, visually inspect all components, including all electrical and mechanical connections, for proper functioning.
(2) * * *
(iv) At least monthly, visually inspect all components, including all electrical and mechanical connections, for proper functioning.
(d) * * *
(8) At least monthly, visually inspect all components, including all electrical and mechanical connections, for proper functioning.
(e) * * *
(2) * * *
(iv) At least monthly, visually inspect all components, including all electrical and mechanical connections, for proper functioning.
(a) * * * When alternative emissions limitations are provided for a given emissions source, you must comply with the alternative emissions limitation most recently selected as your compliance alternative.
(2) * * *
(ii) Maintaining the average total metal HAP concentration in the exhaust stream at or below 0.0005 gr/dscf; or
(iii) Maintaining the average PM mass emissions rate at or below 0.10 pound of PM per ton (lb/ton) of metal charged; or
(iv) Maintaining the average total metal HAP mass emissions rate at or below 0.008 pound of total metal HAP per ton (lb/ton) of metal charged.
(7) For each building or structure housing any iron and steel foundry emissions source at the iron and steel foundry, maintaining the opacity of any fugitive emissions from foundry operations discharged to the atmosphere at or below 20 percent opacity (6-minute average), except for one 6-minute average per hour that does not exceed 27 percent opacity.
(c) For each baghouse,
(1) Inspecting and maintaining each baghouse according to the requirements of § 63.7740(c)(1) through (8) and recording all information needed to document conformance with these requirements; and
(2) If the baghouse is equipped with a bag leak detection system, maintaining records of the times the bag leak detection system sounded, and for each valid alarm, the time you initiated corrective action, the corrective action taken, and the date on which corrective action was completed.
(e) * * * For opacity performance tests, the notification of compliance status may be submitted with the semiannual compliance report in § 63.7751(a) and (b) or the semiannual part 70 monitoring report in § 63.7551(d).
(c) Immediate startup, shutdown, and malfunction report. If you had a startup, shutdown, or malfunction during the semiannual reporting period that was not consistent with your startup, shutdown, and malfunction plan and the source exceeds any applicable emissions limitation in § 63.7690, you must submit an immediate startup, shutdown, and malfunction report according to the requirements of § 63.10(d)(5)(ii).
(a) * * *
(4) Records of the annual quantity of each chemical binder or coating material used to coat or make molds and cores, the Material Data Safety Sheet or other documentation that provides the chemical composition of each component, and the annual quantity of HAP used in these chemical binder or coating materials at the foundry as calculated from the recorded quantities and chemical compositions (from Material Data Safety Sheets or other documentation).
(1) Fails to meet any requirement or obligation established by this subpart
(2) Fails to meet any term or condition that is adopted to implement an applicable requirement in this subpart and that is included in the operating permit for any iron and steel foundry required to obtain such a permit; or
(3) Fails to meet any emissions limitation (including operating limits) or work practice standard in this subpart during startup, shutdown, or malfunction, regardless of whether or not such failure is permitted by this subpart.
A deviation is not always a violation. The determination of whether a deviation constitutes a violation of the standard is up to the discretion of the entity responsible for enforcement of the standards.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Temporary rule; closure.
NMFS closes the commercial run-around gillnet fishery for king mackerel in the exclusive economic zone (EEZ) in the southern Florida west coast subzone. This closure is necessary to protect the Gulf king mackerel resource.
The closure is effective 6 a.m., local time, February 5, 2008, through 6 a.m., January 20, 2009.
Susan Gerhart, telephone: 727-824-5305, fax: 727-824-5308, e-mail:
The fishery for coastal migratory pelagic fish (king mackerel, Spanish mackerel, cero, cobia, little tunny, and, in the Gulf of Mexico only, dolphin and bluefish) is managed under the Fishery Management Plan for the Coastal Migratory Pelagic Resources of the Gulf of Mexico and South Atlantic (FMP). The FMP was prepared by the Gulf of Mexico and South Atlantic Fishery Management Councils (Councils) and is implemented under the authority of the Magnuson-Stevens Fishery Conservation and Management Act (Magnuson-Stevens Act) by regulations at 50 CFR part 622.
Based on the Councils' recommended total allowable catch and the allocation ratios in the FMP, on April 30, 2001 (66 FR 17368, March 30, 2001), NMFS implemented a commercial quota of 2.25 million lb (1.02 million kg) for the eastern zone (Florida) of the Gulf migratory group of king mackerel. That quota is further divided into separate quotas for the Florida east coast subzone and the northern and southern Florida west coast subzones. On April 27, 2000, NMFS implemented the final rule (65 FR 16336, March 28, 2000) that divided the Florida west coast subzone of the eastern zone into northern and southern subzones, and established their separate quotas. The quota implemented for the southern Florida west coast subzone is 1,040,625 lb (472,020 kg). That quota is
The southern subzone is that part of the Florida west coast subzone which from November 1 through March 31 extends south and west from 26°19.8′ N. lat. (a line directly west from the Lee/Collier County, FL, boundary), to 25°20.4′ N. lat. (a line directly east from the Monroe/Miami-Dade County, FL, boundary), i.e., the area off Collier and Monroe Counties. From April 1 through October 31, the southern subzone is that part of the Florida west coast subzone which is between 26°19.8′ N. lat. (a line directly west from the Lee/Collier County, FL, boundary) and 25°48′ N. lat. (a line directly west from the Collier/Monroe County, FL, boundary), i.e., the area off Collier County.
Under 50 CFR 622.43(a)(3), NMFS is required to close any segment of the king mackerel commercial fishery when its quota has been reached, or is projected to be reached, by filing a notification at the Office of the
This action responds to the best available information recently obtained from the fisheries. The Assistant Administrator for Fisheries, NOAA, finds that the need to immediately implement this action to close the fishery constitutes good cause to waive the requirements to provide prior notice and opportunity for public comment pursuant to the authority set forth in 5 U.S.C. 553(b)(B), as such procedures would be unnecessary and contrary to the public interest. Such procedures would be unnecessary because the rule itself already has been subject to notice and comment, and all that remains is to notify the public of the closure.
NMFS also finds good cause that the implementation of this action cannot be delayed for 30 days. There is a need to implement this measure in a timely fashion to prevent an overrun of the commercial run-around gillnet fishery for king mackerel in the southern Florida west coast subzone, given the capacity of the fishing fleet to harvest the quota quickly. Any delay in implementing this action would be contrary to the Magnuson-Stevens Act and the FMP. Accordingly, under 5 U.S.C. 553(d), a delay in the effective date is waived.
This action is taken under 50 CFR 622.43(a) and is exempt from review under Executive Order 12866.
16 U.S.C. 1801
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Temporary rule; closure.
NMFS is prohibiting directed fishing for the A season allowance of the 2008 Pacific cod sideboard limits apportioned to non-American Fisheries Act (AFA) crab vessels catching Pacific cod for processing by the inshore component in the Western Regulatory Area of the Gulf of Alaska (GOA). This action is necessary to prevent exceeding the A season allowance of the 2008 Pacific cod sideboard limits apportioned to non-AFA crab vessels catching Pacific cod for processing by the inshore component in the Western Regulatory Area of the GOA.
Effective 1200 hrs, Alaska local time (A.l.t.), February 4, 2008, until 1200 hrs, A.l.t., September 1, 2008.
Jennifer Hogan, 907-586-7228.
NMFS manages the groundfish fishery in the GOA exclusive economic zone according to the Fishery Management Plan for Groundfish of the Gulf of Alaska (FMP) prepared by the North Pacific Fishery Management Council under authority of the Magnuson-Stevens Fishery Conservation and Management Act. Regulations governing fishing by U.S. vessels in accordance with the FMP appear at subpart H of 50 CFR part 600 and 50 CFR part 679. Regulations governing sideboard protections for GOA groundfish fisheries appear at subpart B of 50 CFR part 680.
The A season allowance of 2008 Pacific cod sideboard limits apportioned to non-AFA crab vessels catching Pacific cod for processing by the inshore component in the Western Regulatory Area of the GOA is 1,017 metric tons (mt) for the GOA, as established by the 2007 and 2008 harvest specifications for groundfish of the GOA (72 FR 9676, March 5, 2007) and revision (72 FR 71802, December 19, 2007).
In accordance with § 680.22(e)(2)(i), the Administrator, Alaska Region, NMFS (Regional Administrator), has determined that the A season allowance of the 2008 Pacific cod sideboard limits apportioned to non-AFA crab vessels catching Pacific cod for processing by the inshore component in the Western Regulatory Area of the GOA will soon be reached. Therefore, the Regional Administrator is establishing a sideboard directed fishing allowance for Pacific cod as 1,007 mt in the Gulf of Alaska. The remaining 10 mt in the Gulf of Alaska will be set aside as bycatch to support other anticipated groundfish fisheries. In accordance with § 680.22(e)(3), the Regional Administrator finds that this sideboard directed fishing allowance has been reached. Consequently, NMFS is prohibiting directed fishing for Pacific cod by non-AFA crab vessels catching Pacific cod for processing by the inshore component in the Western Regulatory Area of the GOA.
After the effective date of this closure the maximum retainable amounts at § 679.20(e) and (f) apply at any time during a trip.
This action responds to the best available information recently obtained from the fishery. The Assistant Administrator for Fisheries, NOAA (AA), finds good cause to waive the requirement to provide prior notice and opportunity for public comment pursuant to the authority set forth at 5 U.S.C. 553(b)(B) as such requirement is impracticable and contrary to the public interest. This requirement is impracticable and contrary to the public interest as it would prevent NMFS from
The AA also finds good cause to waive the 30-day delay in the effective date of this action under 5 U.S.C. 553(d)(3). This finding is based upon the reasons provided above for waiver of prior notice and opportunity for public comment.
This action is required by § 680.22 and is exempt from review under Executive Order 12866.
16 U.S.C. 1801
Agricultural Marketing Service, USDA.
Proposed rule.
This proposed rule would adjust representation on the Cattlemen's Beef Promotion and Research Board (Board), established under the Beef Promotion and Research Act of 1985 (Act), to reflect changes in cattle inventories and cattle and beef imports that have occurred since the most recent Board reapportionment rule became effective in February of 2005. These adjustments are required by the Beef Promotion and Research Order (Order) and would result in an increase in Board membership from 104 to 106, effective with the Department of Agriculture's (Department) appointments for terms beginning early in the year 2009.
Written comments must be received by March 10, 2008.
Comments must be posted online at
Kenneth R. Payne, Chief, Marketing Programs Branch, on 202/720-1115, fax 202/720-1125, or by e-mail at
The Office of Management and Budget (OMB) has waived the review process required by Executive Order 12866 for this action.
This proposed rule has been reviewed under Executive Order 12988, Civil Justice Reform. It is not intended to have retroactive effect.
Section 11 of the Act provides that nothing in the Act may be construed to preempt or supersede any other program relating to beef promotion organized and operated under the laws of the United States or any State. There are no administrative proceedings that must be exhausted prior to any judicial challenge to the provisions of this rule.
Pursuant to the requirements set forth in the Regulatory Flexibility Act (RFA) (5 U.S.C. 601-612), the Administrator of the Agricultural Marketing Service (AMS) has considered the economic effect of this action on small entities and has determined that this proposed rule will not have a significant economic impact on a substantial number of small entities. The purpose of RFA is to fit regulatory actions to the scale of businesses subject to such actions in order that small businesses will not be unduly burdened.
In the February 2007 publication of “Farms, Land in Farms, and Livestock Operations,” the Department's National Agricultural Statistics Service (NASS) estimates that in 2006 the number of operations in the United States with cattle totaled approximately 970,000. The majority of these operations that are subject to the Order may be classified as small entities.
The proposed rule imposes no new burden on the industry. It only adjusts representation on the Board to reflect changes in domestic cattle inventory and cattle and beef imports. The adjustments are required by the Order and would result in an increase in Board membership from 104 to 106.
The Board was initially appointed August 4, 1986, pursuant to the provisions of the Act (7 U.S.C. 2901-2911) and the Order issued thereunder. Domestic representation on the Board is based on cattle inventory numbers, and importer representation is based on the conversion of the volume of imported cattle, beef, or beef products into live animal equivalencies.
Section 1260.141(b) of the Order provides that the Board shall be composed of cattle producers and importers appointed by the Department from nominations submitted by certified producer organizations. A producer may only be nominated to represent the unit in which that producer is a resident.
Section 1260.141(c) of the Order provides that at least every 3 years and not more than every 2 years, the Board shall review the geographic distribution of cattle inventories throughout the United States and the volume of imported cattle, beef, and beef products and, if warranted, shall reapportion units and/or modify the number of Board members from units in order to reflect the geographic distribution of cattle production volume in the United States and the volume of cattle, beef, or beef products imported into the United States.
Section 1260.141(d) of the Order authorizes the Board to recommend to the Department modifications to the number of cattle per unit necessary for representation on the Board.
Section 1260.141(e)(1) provides that each geographic unit or State that includes a total cattle inventory equal to or greater than 500,000 head of cattle shall be entitled to one representative on the Board. Section 1260.141(e)(2) provides that States that do not have total cattle inventories equal to or greater than 500,000 head shall be grouped, to the extent practicable, into geographically-contiguous units, each of which have a combined total inventory of not less than 500,000 head. Such grouped units are entitled to at least one representative on the Board. Each unit that has an additional 1 million head of cattle within a unit qualifies for additional representation on the Board as provided in § 1260.141(e)(4). As provided in § 1260.141(e)(3), importers are represented by a single unit, with the number of Board members based on a conversion of the total volume of imported cattle, beef, or beef products into live animal equivalencies.
The initial Board appointed in 1986 was composed of 113 members. Reapportionment, based on a 3-year average of cattle inventory numbers and import data, reduced the Board to 111 members in 1990 and 107 members in 1993 before the Board was increased to 111 members in 1996. The Board was decreased to 110 members in 1999, 108 members in 2001, 104 members in 2005, and will be increased to 106 members with appointments for terms effective early in 2009.
The current Board representation by States or units was based on an average of the January 1, 2002, 2003, and 2004, inventory of cattle in the various States as reported by NASS. Current importer representation was based on a combined total average of the 2001, 2002, and 2003 live cattle imports as published by the Department's Foreign Agricultural Service and the average of the 2001, 2002, and 2003 live animal equivalents for imported beef products.
Recommendations concerning Board reapportionment were presented to the Board at its September 20, 2007, meeting, and were approved by the Executive Committee, on behalf of the Board, on October 16, 2007. In considering reapportionment, the Board reviewed cattle inventories as well as cattle, beef, and beef product import data for the period of January 1, 2005, to January 1, 2007. The Board recommended that a 3-year average of cattle inventories and import numbers should be continued. The Board determined that an average of the January 1, 2005, 2006, and 2007, Department cattle inventory numbers would best reflect the number of cattle in each State or unit since publication of the last reapportionment rule published in 2005.
The Board reviewed data published by the Department's Economic Research Service to determine proper importer representation. The Board recommended the use of a combined total of the average of the 2004, 2005, and 2006, cattle import data and the average of the 2004, 2005, and 2006, live animal equivalents for imported beef products. The method used to calculate the total number of live animal equivalents was the same as that used in the previous reapportionment of the Board, except that the live animal equivalent weight was changed in 2006 from 509 pounds to 592 pounds. The recommendation for importer representation is based on the most recent 3-year average of data available to the Board at its September 20, 2007, meeting to be consistent with the procedures used for domestic representation.
The Board's recommended reapportionment plan would increase the number of representatives on the Board from 104 to 106. One State—Nebraska—would gain one member. The importer unit would also gain one member. The States and units affected by the reapportionment plan and the current and proposed member representation per unit are as follows:
The 2008 nomination and appointment process was in progress while the Board was developing its recommendations. Thus, the Board reapportionment as proposed by this rulemaking would be effective, if adopted, with appointments that will be effective early in the year 2009.
A 30-day comment period is provided to allow interested persons to respond to this proposal. Thirty days is deemed appropriate to facilitate the adjustment of the representation on the Board, which is required by the Order at least every 3 years, and not more than every 2 years. To permit timely execution of the annual nomination and appointment process, publication of a subsequent final rule must occur as soon as practical.
Administrative practice and procedure, Advertising, Agricultural research, Imports, Marketing agreement, Meat and meat products, Reporting and recordkeeping requirements.
For reasons set forth in the preamble, it is proposed that 7 CFR part 1260 be amended as follows:
1. The authority citation for 7 CFR part 1260 continues to read as follows:
7 U.S.C. 2901-2911.
2. In § 1260.141, paragraph (a) and the table immediately following it, are revised to read as follows:
(a) Beginning with the 2008 Board nominations and the associated appointments effective early in the year 2009, the United States shall be divided into 39 geographical units and 1 unit representing importers, and the number of Board members from each unit shall be as follows:
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking.
This action proposes to establish Class E airspace at Point Roberts, WA. Additional controlled airspace is necessary to support flight operations at Abbotsford Airport, BC. The FAA is proposing this action to enhance the safety and management of Instrument Flight Rules (IFR) operations at the request of the Canadian Government.
Comments must be received on or before March 24, 2008.
Send comments on this proposal to the U.S. Department of Transportation, Docket Operations, M-30, West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue, SE., Washington, DC 20590. Telephone (202) 366-9826. You must identify FAA Docket No. FAA-2007-29036; Airspace Docket No. 07-ANM-13, at the beginning of your comments. You may also submit comments through the Internet at
Richard Roberts, Federal Aviation Administration, Western Service Area, System Support Group, 1601 Lind Avenue, SW., Renton, WA 98057; telephone (425) 917-6728.
Interested parties are invited to participate in this proposed 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 (FAA Docket No. FAA-2007-29036 and Airspace Docket No. 07-ANM-13) and be submitted in triplicate to the Docket Management System (see
Commenters wishing the FAA to acknowledge receipt of their comments on this action must submit with those comments a self-addressed stamped postcard on which the following statement is made: “Comments to FAA Docket No. FAA-2007-29036 and Airspace Docket No. 07-ANM-13”. The postcard will be date/time stamped and returned to the commenter.
All communications received on or before the specified closing date for comments will be considered before taking action on the proposed rule. The proposal contained in this action may be changed in light of comments received. All comments submitted will be available for examination in the public docket both before and after the closing date for comments. A report summarizing each substantive public contact with FAA personnel concerned with this rulemaking will be filed in the docket.
An electronic copy of this document may be downloaded through the Internet at
You may review the public docket containing the proposal, any comments received, and any final disposition in person in the Dockets Office (see the
Persons interested in being placed on a mailing list for future NPRMs should contact the FAA's Office of Rulemaking, (202) 267-9677, for a copy of Advisory Circular No. 11-2A, Notice of Proposed Rulemaking Distribution System, which describes the application procedure.
The FAA is proposing an amendment to Title 14 Code of Federal Regulations (14 CFR) part 71 to establish Class E airspace at Point Roberts, WA (Abbotsford, BC). Controlled airspace is necessary to allow east bound departures to transition into the en route environment for the safety and management of IFR operations at Abbotsford Airport, BC.
Class E airspace designations are published in paragraph 6005 of FAA Order 7400.9R, signed August 15, 2007, and effective September 15, 2007, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designation listed in this document will be published subsequently in this Order.
The FAA has determined that this proposed regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. Therefore, this proposed regulation: (1) Is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. Since this is a routine matter that will only affect air traffic procedures and air navigation, it is certified that this proposed rule, when promulgated, would not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the U.S. Code. Subtitle 1, section 106, describes the authority for the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority. This rulemaking is promulgated under the authority described in subtitle II, 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 as it would allow for the safety of departing aircraft transitioning to the en route environment at Abbotsford Airport, BC, through United States airspace.
Airspace, Incorporation by reference, Navigation (air).
Accordingly, pursuant to the authority delegated to me, the Federal Aviation Administration proposes to amend 14 CFR part 71 as follows:
1. The authority citation for 14 CFR part 71 continues to read as follows:
49 U.S.C. 106(g), 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959-1963 Comp., p. 389.
2. The incorporation by reference in 14 CFR 71.1 of the FAA Order 7400.9R, Airspace Designations and Reporting Points, signed August 15, 2007, and effective September 15, 2007, is amended as follows:
That airspace extending upward from 1,200 feet above the surface bounded by a line beginning at lat. 49°00′00″ N., long. 122°15′00″ W.; thence east along the Canadian U.S. Border to lat. 49°00′00″ N., long. 121°20′15″ W.; thence south to lat. 48°51′40″ N., long. 121°20′15″ W.; thence west to lat. 48°51′40″ N., long. 122°15′00″ W.; thence back to the point of origination.
Coast Guard, DHS.
Notice of proposed rulemaking.
The Coast Guard proposes a temporary safety zone in the Lake Moolvalya region on the navigable waters of the Colorado River in Parker, Arizona for the Bluewater Resort and Casino ‘Spring Classic’ Boat Race. This temporary safety zone is necessary to provide for the safety of the participants, crew, spectators, participating vessels and other vessels and users of the waterway. Persons and vessels are 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 March 3, 2008.
You may submit comments identified by Coast Guard docket number USCG-2007-0145 to the Docket Management Facility at the U.S. Department of Transportation. To avoid duplication, please use only one of the following methods:
(1)
(2)
(3)
(4)
If you have questions on this proposed rule, call Petty Officer Kristen Beer, USCG, Waterways Management, U.S. Coast Guard Sector San Diego at (619) 278-7233. If you have questions on viewing or submitting material to the docket, call Renee V. Wright, Program Manager, Docket Operations, telephone 202-366-9826.
We encourage you to participate in this rulemaking by submitting comments and related materials. All comments received will be posted, without change, to
If you submit a comment, please include the docket number for this rulemaking (USCG-2007-0145), indicate the specific section of this document to which each comment applies, and give the reason for each comment. We recommend that you include your name and a mailing address, an e-mail address, or a phone number in the body of your document so that we can contact you if we have questions regarding your submission. You may submit your comments and material by electronic means, mail, fax, or delivery to the Docket Management Facility at the address under
To view comments, as well as documents mentioned in this preamble as being available in the docket, go to
Anyone can search the electronic form of all comments received into any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review the Department of Transportation's Privacy Act Statement in the
We do not now plan to hold a public meeting. But you may submit a request for one to the Docket Management Facility at the address under
The Southern California Speedboat Club is sponsoring the Bluewater Resort and Casino ‘Spring Classic' Boat Race, which is held on the Lake Moolvalya region on the Colorado River in Parker, Arizona. This temporary safety zone is necessary to provide for the safety of the participants, crew, spectators, sponsor vessels, and other users of the waterway. This event involves powerboats racing along a circular track. The size of the boats varies from twelve (12) to (twenty-two) 22 feet. Approximately eighty-five (85) boats will participate in this event. The sponsor will provide two (2) water rescue and two (2) patrol vessels to patrol this event.
The Coast Guard proposes to establish one (1) safety zone that will be enforced from 6 a.m. to 6 p.m. on April 11, 2008 through April 13, 2008. This safety zone is necessary to provide for the safety of the crews, spectators, and participants of the event and to protect 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. The limits of this temporary safety are the portion of the Colorado River from Headgate Dam to 0.5 miles north of Bluewater Marina, Parker, Arizona.
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.
We expect the economic impact of this proposed rule to be so minimal that a full Regulatory Evaluation is unnecessary.
This determination is based on the size and location of the safety zone. Commercial vessels will be hindered by the safety zone. Recreational vessels will not be allowed to transit through the designated safety zone during the specified times.
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.
(1) This proposed rule would affect the following entities, some of which might be small entities: the owners or operators of vessels intending to transit or anchor in a portion of the Colorado River from 6 a.m. to 6 p.m. on April 11, 2008 through April 13, 2008.
(2) This safety zone would not have a significant economic impact on a substantial number of small entities for the following reasons. This rule would be in effect for only twelve (12) hours per day for a period of three (3) days. Although the safety zone would apply to the entire width of the river, traffic would be allowed to pass through the zone with the permission of the Coast Guard patrol commander. Before the effective period, we would publish local notice to mariners (LNM) before the safety zone is enforced.
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 Petty Officer Kristen Beer, U.S. Coast Guard Sector San Diego at (619) 278-7233. 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 this action is not likely to have a significant effect on the human environment. A preliminary “Environmental Analysis Check List” supporting this preliminary determination is available in the docket where indicated under
Harbors, Marine Safety, Navigation (water), Reporting and recordkeeping requirements, and 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, 6.04-6, 160.5; Pub. L. 107-295, 116 Stat, 2064; Department of Homeland Security Delegation No. 0170.1
2. Add a new temporary § 165.T11-001 to read as follows:
(a)
(b)
(c)
Coast Guard, DHS.
Notice of proposed rulemaking.
The Coast Guard proposes to establish a temporary safety zone within the Lake Moolvalya region on the navigable waters of the Colorado River in Parker, Arizona for the Bluewater Resort and Casino American Powerboat Association (APBA) National Tour/Regional Championship. This temporary safety zone is necessary to provide for the safety of the participants, crew, spectators, sponsor vessels of the race, and general users of the waterway. Persons and vessels are prohibited from entering into, transiting through, or anchoring within this safety zone unless authorized by the Captain of the Port, or his designation representative.
Comments and related material must reach the Coast Guard on or before March 3, 2008.
You may submit comments identified by Coast Guard docket number USCG-2007-0140 to the Docket Management Facility at the U.S. Department of Transportation. To avoid duplication, please use only one of the following methods:
(1)
(2)
(3)
(4)
If you have questions on this proposed rule, call MST3 Kristen Beer, USCG, c/o U.S. Coast Guard Captain of the Port, at (619) 278-7233. If you have questions on viewing or submitting material to the docket, call Renee V. Wright, Program Manager, Docket Operations, telephone 202-366-9826.
We encourage you to participate in this rulemaking by submitting comments and related materials. All comments received will be posted, without change, to
If you submit a comment, please include the docket number for this rulemaking (USCG-2007-0140), indicate the specific section of this document to which each comment applies, and give the reason for each comment. We recommend that you include your name and a mailing address, an e-mail address, or a phone number in the body of your document so that we can contact you if we have questions regarding your submission. You may submit your comments and material by electronic means, mail, fax, or delivery to the Docket Management Facility at the address under
To view comments, as well as documents mentioned in this preamble as being available in the docket, go to
Anyone can search the electronic form of all comments received into any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review the Department of Transportation's Privacy Act Statement in the
We do not now plan to hold a public meeting. But you may submit a request for one to the Docket Management Facility at the address under
RPM Racing Enterprises is sponsoring the Bluewater Resort and Casino APBA National Tour/Regional Championship, which is held on the Lake Moolvalya region on the Colorado River in Parker, AZ. This temporary safety zone is necessary to provide for the safety of the participants, crew, spectators, sponsor vessels, and other users of the waterway.
This event involves powerboats racing along a circular track. The size of the boats varies from eight to 15 feet. Approximately 130 to 150 boats will participate in this event. The sponsor has provided two water rescue and two patrol vessels to patrol this event.
The proposed temporary safety zone would be comprised of the following area: The portion of the navigable waterway of Lake Moolvalya, from the north part of Headgate Dame to 0.5 nautical headed north of Bluewater Marina, Parker, AZ.
The Coast Guard proposes to establish one safety zone that will be enforced from 6 a.m. to 6 p.m. from May 2, 2008 through May 4, 2008. 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.
U.S. Coast Guard personnel will enforce this safety zone. The Coast Guard may be assisted by other federal, state, or local agencies, including the Coast Guard Auxiliary. Section 165.23 of Title 33, Code of Federal Regulations, prohibits any unauthorized person or vessel from entering or remaining in a safety zone. Vessels or persons violating this section will 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.
We expect the economic impact of this proposed rule to be so minimal that a full Regulatory Evaluation is unnecessary.
This determination is based on the size and location of the safety zone. Commercial vessels will not be hindered by the safety zone. Recreational vessels will not be allowed to transit through the designated safety zone during the specified times.
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.
(1) This proposed rule would affect the following entities, some of which might be small entities: The owners or operators of vessels intending to transit or anchor in a portion of the Colorado River, Parker, AZ from 6 a.m. to 6 p.m. on May 2, 2008 through May 4, 2008.
(2) This safety zone would not have a significant economic impact on a substantial number of small entities for the following reasons. This rule would be in effect for only 12 hours per day for a period of three days. Although the safety zone would apply to the entire width of the river, traffic would be allowed to pass through the zone with the permission of the Coast Guard patrol commander. Before the effective period, we would publish local notice to mariners (LNM) before the safety zone is enforced.
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 MST3 Kristen Beer, Waterways Management, U.S. Coast Guard Sector San Diego at
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 (e.g., specifications of materials, performance, design, or operation; test methods; sampling procedures; and related management systems practices) that are developed or adopted by voluntary consensus standards bodies.
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 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 this action is not likely to have a significant effect on the human environment. A preliminary “Environmental Analysis Check List” supporting this preliminary determination is available in the docket where indicated under
Harbors, Marine safety, Navigation (water), Reporting and recordkeeping requirements, Security measures, and 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, 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.
2. A new temporary § 165.T11-261 is added to read as follows:
(a)
(b)
(c)
Environmental Protection Agency (EPA).
Proposed rule.
The EPA is proposing to determine that the Boston-Manchester-Portsmouth (SE), New Hampshire moderate 8-hour ozone nonattainment area has attained the 8-hour National Ambient Air Quality Standard (NAAQS) for ozone. This determination is based upon certified ambient air monitoring data that show the area has monitored attainment of the 8-hour ozone NAAQS since the 2002-2004 monitoring period, and continues to monitor attainment of the NAAQS based on 2004-2006 data. In addition, quality controlled and quality assured ozone data for 2007 that are available in the EPA Air Quality System database, but not yet certified, show this area continues to attain the 8-hour ozone NAAQS. If this proposed determination is made final, the requirements for this area to submit an attainment demonstration, a reasonable further progress plan, contingency measures, and other planning State Implementation Plans related to attainment of the 8-hour ozone NAAQS shall be suspended for so long as the area continues to attain the ozone NAAQS.
Written comments must be received on or before March 10, 2008.
Submit your comments, identified by Docket ID Number EPA-R01-OAR-2008-0069 by one of the following methods:
1.
2.
3.
4.
Richard P. Burkhart, Air Quality Planning Unit, U.S. Environmental Protection Agency, EPA New England Regional Office, One Congress Street, Suite 1100 (CAQ), Boston, MA 02114-2023, telephone number (617) 918-1664, fax number (617) 918-0664, e-mail
Throughout this document whenever “we,” “us,” or “our” is used, we mean EPA.
Organization of this document. The following outline is provided to aid in locating information in this preamble.
EPA is proposing to determine that the Boston-Manchester-Portsmouth (SE), New Hampshire moderate 8-hour ozone nonattainment area has attained the 8-hour National Ambient Air Quality Standard (NAAQS) for ozone. This determination is based upon certified ambient air monitoring data that show the area has monitored attainment of the ozone NAAQS since the 2002-2004 monitoring period, and monitoring data that continue to show attainment of the NAAQS based on 2004-2006 data. In addition, quality controlled and quality assured ozone data for 2007 that are available in the EPA Air Quality System (AQS) database, but not yet certified, show this area continues to attain the ozone NAAQS.
If this determination is made final, under the provisions of EPA's ozone implementation rule (see 40 CFR Section 51.918), the requirements for the Boston-Manchester-Portsmouth (SE), New Hampshire moderate ozone nonattainment area to submit an attainment demonstration, a reasonable further progress plan, section 172(c)(9) contingency measures, and any other planning State Implementation Plans (SIPs) related to attainment of the 8-hour ozone NAAQS would be suspended for so long as the area continues to attain the ozone NAAQS.
This proposed action, if finalized, would not constitute a redesignation to
If this rulemaking is finalized and EPA subsequently determines, after notice-and-comment rulemaking in the
On April 30, 2004 (69 FR 23857), EPA designated as nonattainment any area that was violating the 8-hour ozone NAAQS based on the three most recent years (2001-2003) of air quality data. Portions of Hillsborough, Merrimack, and Rockingham, and Strafford Counties in New Hampshire were designated as a moderate ozone nonattainment area (specifically, the Boston-Manchester-Portsmouth (SE), New Hampshire area). The rest of New Hampshire was designated as attainment of the 8-hour ozone NAAQS. (See 40 CFR 81.330.) More recent air quality data, however, indicate that the Boston-Manchester-Portsmouth (SE), New Hampshire area is now attaining the 8-hour ozone standard.
The EPA has reviewed the ambient air monitoring data for ozone, consistent with the requirements contained in 40 CFR Part 50 and recorded in the EPA Air Quality System (AQS) database, for the Boston-Manchester-Portsmouth (SE), New Hampshire ozone nonattainment area, from 2002 through the present time. On the basis of that review, EPA has concluded that this area attained the 8-hour ozone standard at the end of the 2004 ozone season, based on certified 2002-2004 ozone data, and continued to attain the standard through and inclusive of the 2004-2006 ozone seasons. In addition, quality controlled and quality assured ozone data for 2007, that are available in AQS, but not yet certified, show this area continues to attain the 8-hour ozone NAAQS.
Under EPA regulations at 40 CFR Part 50, the 8-hour ozone standard is attained when the 3-year average of the annual fourth-highest daily maximum 8-hour average ozone concentrations at an ozone monitor is less than or equal to 0.08 parts per million (ppm) (i.e., 0.084 ppm, based on the rounding convention in 40 CFR part 50, Appendix I). This 3-year average is referred to as the design value. When the design value is less than or equal to 0.084 ppm (84 parts per billion (ppb)) at each monitor within the area, then the area is meeting the NAAQS. (See 69 FR 23857 (April 30, 2004) for further information.) Also, the data completeness requirement is met when the average percent of days with valid ambient monitoring data is greater than 90%, and no single year has less than 75% data completeness as determined in Appendix I of 40 CFR Part 50.
Table 1 shows the fourth-highest daily maximum 8-hour average ozone concentrations for the Boston-Manchester-Portsmouth (SE), New Hampshire nonattainment area monitors for the years 2004-2007. Table 2 shows the ozone design values for these same monitors based on the following 3-year periods: 2002-2004; 2003-2005; 2004-2006; and 2005-2007.
EPA's review of these data indicate that the Boston-Manchester-Portsmouth (SE), New Hampshire ozone nonattainment area has met and continues to meet the 8-hour ozone NAAQS. EPA is soliciting public comments on the issues discussed in this notice or on other relevant matters. These comments will be considered before taking final action. Interested parties may participate in the Federal rulemaking procedure by submitting written comments to the EPA New England Regional Office listed in the
EPA is proposing to determine that the Boston-Manchester-Portsmouth (SE), New Hampshire 8-hour ozone nonattainment area has attained the 8-hour ozone standard and continues to attain the standard based on data through the 2007 ozone season. As provided in 40 CFR Section 51.918, if EPA finalizes this determination, it would suspend the requirements for New Hampshire to submit an attainment demonstration, a reasonable further progress plan, and contingency measures under section 172(c)(9), and any other planning SIP related to attainment of the 8-hour ozone NAAQS for this area, for so long as the area continues to attain the standard.
Under Executive Order 12866 (58 FR 51735, October 4, 1993), this proposed action is not a “significant regulatory
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 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), because it merely proposes to make a determination based on air quality data and would, if finalized, result in the suspension of certain Federal requirements, and does not alter the relationship or the distribution of power and responsibilities established in the Clean Air Act. 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 proposes to determine that air quality in the affected area is meeting Federal standards.
The requirements of section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) do not apply because it would be inconsistent with applicable law for EPA, when determining the attainment status of an area, to use voluntary consensus standards in place of promulgated air quality standards and monitoring procedures that otherwise satisfy the provisions of the Clean Air Act.
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,
Under Executive Order 12898, EPA finds that this rule involves a proposed determination of attainment based on air quality data and will not have disproportionately high and adverse human health or environmental effects on any communities in the area, including minority and low-income communities.
Environmental protection, Air pollution control, Intergovernmental relations, Nitrogen dioxide, Ozone, Reporting and recordkeeping requirements, Volatile organic compounds.
42 U.S.C. 7401,
Fish and Wildlife Service, Interior.
Notice; initiation of status review, and solicitation of new information.
We, the U.S. Fish and Wildlife Service (Service), announce the opening of a public comment period regarding the status of the Bonneville cutthroat trout (
To be fully considered for the 12-month finding, comments must be submitted on or before April 7, 2008.
You may submit comments by one of the following methods:
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We will not accept e-mail or faxes. We will post all comments on
Larry Crist, Field Supervisor, Utah Field Office, U.S. Fish and Wildlife Service, at the above address, or phone (801) 975-3330, ext. 126. Additional information is available at
To ensure that the status review is complete and based on the best available scientific and commercial information, we are soliciting information concerning the status of the Bonneville cutthroat trout. We request any additional information, comments, and suggestions from the public, other concerned governmental agencies, Native American Tribes, the scientific community, industry, or any other interested parties. We are opening a 60-day comment period to allow all interested parties an opportunity to provide information on the status of the Bonneville cutthroat trout throughout its range, including:
(1) Information regarding the species' historical and current population status, distribution, and trends; its biology and ecology; and habitat selection;
(2) Information on the effects of potential threat factors that are the basis
(a) The present or threatened destruction, modification, or curtailment of the species' habitat or range;
(b) Overutilization for commercial, recreational, scientific, or educational purposes;
(c) Disease or predation;
(d) Inadequacy of existing regulatory mechanisms; and
(e) Other natural or manmade factors affecting its continued existence.
(3) Information on management programs for the conservation of the Bonneville cutthroat trout.
Please note that comments merely stating support for or opposition to the action under consideration without providing supporting information, although noted, will not be considered in making a determination, because section 4(b)(1)(A) of the Act directs that determinations as to whether any species is a threatened or endangered species must be made “solely on the basis of the best scientific and commercial data available.” At the conclusion of the status review, we will issue a new 12-month finding on the petition, as provided in section 4(b)(3)(B) of the Act.
You may submit your comments and materials concerning this finding by one of the methods listed in the
Before including your address, phone number, e-mail address, or other personal identifying information in your comment, you should be aware that we will post your entire comment—including your personal identifying information-on
Comments and materials we receive, as well as supporting documentation we used in preparing this finding, will be available for public inspection on
Section 1533(b)(3)(A) and (B) of the Endangered Species Act of 1973, as amended (Act) (16 U.S.C. 1531
On October 9, 2001, we announced our 12-month finding (66 FR 51362) in which we found that, after reviewing the best available scientific and commercial information, listing the Bonneville cutthroat trout was not warranted. We were sued by the Center for Biological Diversity on February 17, 2005 on the merits of the 12-month finding. On March 7, 2007, the District Court of Colorado dismissed the lawsuit after determining that Plaintiffs failed to demonstrate the not warranted finding was arbitrary, capricious, or contrary to law. Plaintiffs appealed to the 10th Circuit Court of Appeals. However, due to subsequent development of a formal opinion (Department of the Interior, March 16, 2007) regarding the legal interpretation of the term “significant portion of the range” of a species, we withdrew our finding (Stansell Memorandum, August 24, 2007). The lawsuit was subsequently dismissed and the case was closed on May 14, 2007. The new status review will include an analysis of whether any significant portion of the range of the Bonneville cutthroat trout warrants listing as threatened or endangered under the Act.
At this time, we are soliciting new information on the status and potential threats to the Bonneville cutthroat trout. Information submitted in response to our 2001 12-month finding will be considered and need not be resubmitted. We will base our 12-month finding on a review of the best scientific and commercial information available, including all information received as a result of this notice. For more information on the biology, habitat, and range of the Bonneville cutthroat trout, please refer to our previous 12-month finding published in the
We request any new information concerning the status of the Bonneville cutthroat trout. If you submit information, support it with documentation such as maps, bibliographic references, methods used to gather and analyze the data, or copies of any pertinent publications, reports, or letters by knowledgeable sources. We specifically request information regarding data from any systematic surveys, as well as any studies or analysis of data regarding population size or trends; biology or ecology of the species; effects of current land management on population distribution and abundance; current condition of habitat; and conservation measures that have been implemented to benefit the species. Additionally, we specifically request information on the current distribution of populations, and threats to the subspecies in relation to the five listing factors (as defined in section 4(a)(1) of the Act).
The primary authors of this document are staff of U.S. Fish and Wildlife Service, Utah Field Office—Ecological Services.
The authority for this action is the Endangered Species Act of 1973, as amended (16 U.S.C. 1531
Fish and Wildlife Service, Interior.
Proposed rule; reopening of comment period, notice of availability of draft economic analysis, amended required determinations, and notice of public hearing.
We, the U.S. Fish and Wildlife Service (Service), announce the reopening of the comment period on the proposed designation of critical habitat for the Devils River minnow (
We will accept comments received or postmarked on or before March 10, 2008. We will hold one public hearing on the proposed critical habitat designation and the DEA on February 27, 2008. See Public Hearing section under
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•
We will not accept e-mail or faxes. We will post all comments on
Adam Zerrenner, Field Supervisor, U.S. Fish and Wildlife Service, Austin Ecological Services Field Office, 10711 Burnet Road, Austin, TX 78758; telephone 512/490-0057, extension 248; facsimile 512/490-0974. If you use a telecommunications device for the deaf (TDD), call the Federal Information Relay Service (FIRS) at 800-877-8339.
We will hold a public hearing on the proposed critical habitat designation and the DEA on February 27, 2008 in Del Rio, Texas. An information session will be held from 6 p.m. to 7 p.m. and will precede the hearing. The public hearing will run from 7 p.m. to 8 p.m. See the Public Hearing section under
Persons needing reasonable accommodations to attend and participate in the public hearing should contact the person listed in the
We will accept written comments and information during this reopened comment period, as well as oral or written comments at the scheduled public hearing on our proposed critical habitat designation for the Devils River minnow (
(1) The reasons habitat should or should not be designated as critical habitat under section 4 of the Act, specifically the benefits of excluding or the benefits of including any particular area as critical habitat.
(2) Specific information on:
• The amount and distribution of Devils River minnow habitat,
• What areas occupied at the time of listing that contain features essential for the conservation of the species we should include in the designation and why, and
• What areas not occupied at the time of listing are essential to the conservation of the species and why.
(3) Information on the status of the Devils River minnow in Sycamore Creek and Las Moras Creek watersheds and information that indicates whether or not these areas should be considered essential to the conservation of the species and why.
(4) Land use designations and current or planned activities in the subject areas and their possible impacts on proposed critical habitat.
(5) Information on whether the DEA identifies all State and local costs and benefits attributable to the proposed critical habitat designation, and information on any costs or benefits that we have overlooked.
(6) Information on whether the DEA makes appropriate assumptions regarding current practices and any regulatory changes likely if we designate critical habitat.
(7) Any foreseeable economic, national security, or other potential impacts resulting from the proposed designation and, in particular, any impacts on small entities and information about the benefits of including or excluding any areas that exhibit those impacts.
(8) Whether our approach to designating critical habitat could be improved or modified in any way to provide for greater public participation and understanding, or to assist us in accommodating public concerns and comments.
If you submitted comments or information during the initial comment period from July 31, 2007, to October 1, 2007, on the proposed rule (72 FR 41679), they need not be resubmitted. They will be fully considered in the preparation of our final determination. Our final determination concerning critical habitat for the Devils River minnow will take into consideration all written comments we receive, oral or written comments we receive at the public hearing, and any additional information we receive during both comment periods. On the basis of public comments, we may, during the development of our final determination, find that areas proposed are not essential or are appropriate for exclusion under section 4(b)(2) of the Act.
You may submit your comments and materials concerning our proposed rule, the associated DEA of the proposed designation, and the amended required determinations section by one of the methods listed in the
We will post your entire comment—including your personal identifying information—on
Comments and materials we receive, as well as supporting documentation we used in preparing this notice, will be available for public inspection on
You may obtain copies of the original proposed rule and the DEA by mail from the Austin Ecological Services Field Office (see
It is our intent to discuss only those topics directly relevant to designation of critical habitat in this notice. For more information on Devils River minnow, refer to the final listing rule published in the
The Devils River minnow was listed as threatened on October 20, 1999 (64 FR 56596). Critical habitat was not designated for this species at the time of listing (64 FR 56606). On October 5, 2005, the Forest Guardians, Center for Biological Diversity, and Save Our Springs Alliance filed suit against the Service for failure to designate critical habitat for this species (
On July 31, 2007, we published a proposed rule (72 FR 41679) to designate critical habitat for Devils River minnow. We proposed three units as critical habitat, including approximately 73.5 total stream kilometers (km) (45.7 stream miles (mi)). The proposed critical habitat is located along three Texas streams, two in Val Verde County (Devils River and San Felipe Creek) and one in Kinney County (Pinto Creek). Further, in the proposed rule, we identified two additional areas, Sycamore Creek and Las Moras Creek, which we are considering including in the final critical habitat designation. We requested public comment and information on whether these areas are essential to the conservation of the species.
Section 3 of the Act defines critical habitat as the specific areas within the geographic area occupied by a species, at the time it is listed in accordance with the Act, on which are found those physical or biological features essential to the conservation of the species and that may require special management considerations or protection, and specific areas outside the geographic area occupied by a species at the time it is listed, upon a determination that such areas are essential for the conservation of the species. If the proposed rule is made final, section 7 of the Act will prohibit destruction or adverse modification of critical habitat by any activity funded, authorized, or carried out by any Federal agency. Federal agencies proposing actions affecting areas designated as critical habitat must consult with us on the effects of their proposed actions, pursuant to section 7(a)(2) of the Act.
Under section 4(b)(2), we may exclude an area from critical habitat if we determine that the benefits of such exclusion outweigh the benefits of including that particular area as critical habitat, unless failure to designate that specific area as critical habitat will result in the extinction of the species. We may exclude an area from designated critical habitat based on economic impacts, national security, or any other relevant impact.
In the July 31, 2007, critical habitat proposed rule (72 FR 41679), we address a number of general issues that are relevant to exclusions under section 4(b)(2) of the Act. In addition, we have prepared a DEA analyzing the potential impacts of the proposed critical habitat designation, which is available for public review and comment. Based on public comment on this document and the proposed designation, additional areas may be excluded from final critical habitat by the Secretary under the provisions of section 4(b)(2) of the Act. This is provided for in the Act and in our implementing regulations at 50 CFR 424.19.
Section 4(b)(2) of the Act requires that we designate critical habitat based upon the best scientific and commercial data available, after taking into consideration the economic impact, impact on national security, or any other relevant impact of specifying any particular area as critical habitat. In compliance with section 4(b)(2) of the Act, we have prepared a DEA of the proposed critical habitat designation based on our July 31, 2007, proposed rule (72 FR 41679) to designate critical habitat for the Devils River minnow. In the July 31, 2007, critical habitat proposal, we discussed the uncertainty regarding the inclusion of two areas currently unoccupied by the species. Sycamore Creek and Las Moras Creek were historically occupied by Devils River minnow, but the species has not been collected in either location since 1989 and 1955, respectively. We requested public input during the initial comment period for information to assist our determination to include or not include these areas in the critical habitat designation. We received multiple comments from peer reviewers and the public encouraging inclusion of these areas to further the conservation of the species. In response to these comments, the DEA further evaluates the potential economic costs of designating these two additional areas.
The intent of the DEA is to quantify the economic impacts of all potential conservation efforts for the Devils River minnow; some of these costs are coextensive with listing and recovery and will likely be incurred regardless of whether we designate critical habitat. The DEA also identifies the incremental costs associated specifically with the designation of critical habitat for the species. Incremental conservation efforts and associated impacts are those not expected to occur absent the designation of critical habitat for the Devils River minnow. The DEA describes and quantifies the potential economic impacts associated with the proposed critical habitat designation for the Devils River minnow in relation to the threats identified by the Service. That is, analyzed impacts are due to conservation measures for the Devils River minnow that address one or more of the threats to the species identified by the Service. Based on the proposed rule, the DEA analyzed potential costs of measures taken to address threats related to poor water quality caused by pollution, groundwater and surface water extraction, nonnative species, and stream channel alteration.
The DEA estimates total pre-designation baseline impacts (8-year total from 1999 to 2007) for all 3 proposed units to be $342,000 (undiscounted dollars), which is equivalent to a present value of $380,000, assuming a 3 percent discount rate, and $392,000, assuming a 7 percent discount rate. Post-designation baseline impacts (2008 to 2027) for all 3 proposed units are estimated to be $507,000 (undiscounted dollars) over the next 20 years, which is equivalent to a present value of $391,000, assuming a 3 percent discount rate, and $290,000, assuming a 7 percent discount rate. The post-designation incremental impacts (2008 to 2027) for all 3 proposed units are estimated to be $57,100 (undiscounted dollars), which is equivalent to a present value of $42,600, assuming a 3 percent discount rate, and $30,300, assuming a 7 percent discount rate.
Concerning the two additional areas we considered for inclusion in the designation of critical habitat (Sycamore Creek and Las Moras Creek), the DEA found no costs associated with Devils River minnow conservation or potential inclusion as critical habitat in either area. There were no conservation actions or projects involving consultation under section 7 of the Act related to the species in these areas, either baseline or future projects, with quantifiable costs. Therefore, the estimated economic costs reported above and elsewhere in this document refer to the total costs of the three units (Devils River, San Felipe Creek, and Pinto Creek) we actually proposed for designation.
The DEA considers the potential economic effects of all actions relating to the conservation of the Devils River minnow, including costs associated with sections 4, 7, and 10 of the Act, as well as costs attributable to the designation of critical habitat. The DEA further considers the economic effects of protective measures taken as a result of other Federal, State, and local laws that aid habitat conservation for the species in areas containg features essential to the conservation of the species. The DEA considers both economic efficiency and distributional effects. In the case of habitat conservation, efficiency effects generally reflect the “opportunity costs” associated with the commitment of resources to comply with habitat protection measures (such as lost economic opportunities associated with restrictions on land use).
The DEA also addresses how potential economic impacts are likely to be distributed, including an assessment of any local or regional impacts of habitat conservation and the potential effects of conservation activities on small entities and the energy industry. The DEA measures lost economic efficiency associated with residential and commercial development and public projects and activities, such as economic impacts on water management and transportation projects, Federal lands, small entities, and the energy industry. Decision-makers can use this information to assess whether the effects of the designation might unduly burden a particular group or economic sector.
Finally, the DEA looks retrospectively at costs that have been incurred since we listed the Devils River minnow as threatened on October 20, 1999 (64 FR 56596), and considers those costs that may occur in the 20 years following the designation of critical habitat. Because the DEA considers the potential economic effects of all actions relating to the conservation of the Devils River minnow, including costs associated with sections 4, 7, and 10 of the Act and those attributable to the designation of critical habitat, the DEA may have overestimated the potential economic impacts of the critical habitat designation.
As stated earlier, we are soliciting data and comments from the public on this DEA, as well as on all aspects of the proposal. We may revise the proposal, or its supporting documents, to incorporate or address new information received during the comment period. In particular, we may exclude an area from critical habitat if we determine that the benefits of excluding the area outweigh the benefits of including the area as critical habitat, provided such exclusion will not result in the extinction of the species.
In our July 31, 2007, proposed rule (72 FR 41679), we indicated that we would defer our determination of compliance with several statutes and Executive Orders until the information concerning potential economic impacts of the designation and potential effects on landowners and stakeholders was available in the DEA. We have now made use of the DEA data to make these determinations. In this document we affirm the information contained in the proposed rule concerning Executive Order (E.O.) 13132, E.O. 12988, the Paperwork Reduction Act, the National Environmental Policy Act, and the President's memorandum of April 29, 1994, “Government-to-Government Relations with Native American Tribal Governments” (59 FR 22951). However, based on the information within the DEA, we revise our required determinations concerning E.O. 12866, the Regulatory Flexibility Act, E.O. 13211 (Energy, Supply, Distribution, and Use), the Unfunded Mandates Reform Act, and E.O. 12630 (Takings).
In accordance with E.O. 12866, we evaluate four parameters in determining whether a rule is significant. If any one of the following four parameters are met, the Office of Management and Budget (OMB) will designate that rule as significant under E.O. 12866:
(a) The rule would have an annual economic effect of $100 million or more or adversely affect an economic sector, productivity, jobs, the environment, or other units of the government;
(b) The rule would create inconsistencies with other Federal agencies' actions;
(c) The rule would materially affect entitlements, grants, user fees, loan programs, or the rights and obligations of their recipients; or
(d) The rule would raise novel legal or policy issues.
Based on the economic analysis of the critical habitat designation, we have determined that the designation of critical habitat for Devils River minnow will not result in an annual effect on the economy of $100 million or more or affect the economy in a material way. Based on previous critical habitat designations and the economic analysis, we believe this rule will not materially affect entitlements, grants, user fees, loan programs, or the rights and obligations of their recipients. OMB has requested to informally review this rule, and thus this action may raise novel legal or policy issues. In accordance with the provisions of E.O. 12866, this rule is considered significant.
Executive Order 12866 directs Federal agencies issuing regulations to evaluate regulatory alternatives (Office of Management and Budget, Circular A-4, September 17, 2003). Pursuant to Circular A-4, once it has been determined that the Federal regulatory
In developing our designations of critical habitat, we consider economic impacts, impacts to national security, and other relevant impacts pursuant to section 4(b)(2) of the Act. Based on the discretion allowable under this provision, we may exclude any particular area from the designation of critical habitat providing that the benefits of such exclusion outweigh the benefits of designating the area as critical habitat and that such exclusion would not result in the extinction of the species. We believe that the evaluation of the inclusion or exclusion of particular areas, or combination thereof, in a designation constitutes our regulatory alternative analysis.
Under the Regulatory Flexibility Act (RFA) (5 U.S.C. 601
According to the Small Business Administration (SBA), small entities include small organizations, such as independent nonprofit organizations, and small governmental jurisdictions, including school boards and city and town governments that serve fewer than 50,000 residents, as well as small businesses (13 CFR 121.201). Small businesses include manufacturing and mining concerns with fewer than 500 employees, wholesale trade entities with fewer than 100 employees, retail and service businesses with less than $5 million in annual sales, general and heavy construction businesses with less than $27.5 million in annual business, special trade contractors doing less than $11.5 million in annual business, and agricultural businesses with annual sales less than $750,000. To determine if potential economic impacts to these small entities are significant, we considered the types of activities that might trigger regulatory impacts under this designation as well as types of project modifications that may result. In general, the term significant economic impact is meant to apply to a typical small business firm's business operations.
To determine if the proposed Devils River minnow critical habitat designation would affect a substantial number of small entities, we consider the number of small entities affected within particular types of economic activities (e.g., residential and commercial development, agriculture, oil and gas production). We apply the “substantial number” test individually to each industry to determine if certification is appropriate. However, the SBREFA does not explicitly define “substantial number” or “significant economic impact.” Consequently, to assess whether a “substantial number” of small entities is affected by this designation, this analysis considers the relative number of small entities likely to be impacted in an area. In some circumstances, especially with critical habitat designations of limited extent, we may aggregate across all industries and consider whether the total number of small entities affected is substantial. In estimating the numbers of small entities potentially affected, we also consider whether their activities have any Federal involvement.
Designation of critical habitat only affects activities conducted, funded, or permitted by Federal agencies. Some kinds of activities are unlikely to have any Federal involvement and so will not be affected by critical habitat designation. In areas where the species is present, Federal agencies already are required to consult with us under section 7 of the Act on activities they fund, permit, or implement that may affect the Devils River minnow. Federal agencies also must consult with us if their activities may affect critical habitat. Designation of critical habitat, therefore, could result in an additional economic impact on small entities due to the requirement to reinitiate consultation for ongoing Federal activities.
Appendix B of the DEA examined the potential for Devils River minnow conservation efforts to affect small entities. The analysis was based on the estimated impacts associated with the proposed critical habitat designation. Based on the analysis, the potential for economic impacts of the designation on small entities are expected to be borne primarily by the City of Del Rio and other miscellaneous small entities. The identities of these small entities are not known at this time but are expected to include local developers and private landowners that may represent third parties in section 7 consultations on the Devils River minnow in the future. The City of Del Rio and other miscellaneous small entities are expected to incur, at most, combined annualized administrative costs related to consultations for adverse modification of approximately $3,000, assuming a 3 percent discount rate. This estimated $3,000 in combined annual administrative costs is not expected to have a significant impact on small entities, including the City of Del Rio. In addition, because the annualized post-designation incremental impacts expected for the City of Del Rio and other miscellaneous small entities are relatively small, no future indirect impacts associated with post-designation incremental impacts are expected for the small businesses and entities included in this analysis.
In summary, we have considered whether this rule would result in a significant economic effect on a substantial number of small entities. Based on the above reasoning and currently available information, we certify that the designation of critical habitat for the Devils River minnow will not result in a significant economic impact on a substantial number of small business entities; therefore, a regulatory flexibility analysis is not required.
On May 18, 2001, the President issued E.O. 13211 on regulations that significantly affect energy supply, distribution, or use. E.O. 13211 requires agencies to prepare Statements of Energy Effects when undertaking certain actions. This proposed designation of critical habitat for the Devils River minnow is not considered a significant regulatory action under E.O. 12866. OMB has provided guidance for implementing this Executive Order that outlines nine outcomes that may constitute “a significant adverse effect” when compared without the regulatory
In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501), the Service makes the following findings:
(a) This rule will not produce a Federal mandate. In general, a Federal mandate is a provision in legislation, statute, or regulation that would impose an enforceable duty upon State, local, or Tribal governments, or the private sector, and includes both “Federal intergovernmental mandates” and “Federal private sector mandates.” These terms are defined in 2 U.S.C. 658(5)-(7). “Federal intergovernmental mandate” includes a regulation that “would impose an enforceable duty upon State, local, or tribal governments,” with two exceptions. It excludes “a condition of federal assistance.” It also excludes “a duty arising from participation in a voluntary Federal program,” unless the regulation “relates to a then-existing Federal program under which $500,000,000 or more is provided annually to State, local, and tribal governments under entitlement authority,” if the provision would “increase the stringency of conditions of assistance” or “place caps upon, or otherwise decrease, the Federal Government's responsibility to provide funding” and the State, local, or tribal governments “lack authority” to adjust accordingly. At the time of enactment, these entitlement programs were: Medicaid; Aid to Families with Dependent Children work programs; Child Nutrition; Food Stamps; Social Services Block Grants; Vocational Rehabilitation State Grants; Foster Care, Adoption Assistance, and Independent Living; Family Support Welfare Services; and Child Support Enforcement. “Federal private sector mandate” includes a regulation that “would impose an enforceable duty upon the private sector, except (i) a condition of Federal assistance; or (ii) a duty arising from participation in a voluntary Federal program.”
The designation of critical habitat does not impose a legally binding duty on non-Federal government entities or private parties. Under the Act, the only regulatory effect is that Federal agencies must ensure that their actions do not destroy or adversely modify critical habitat under section 7. Non-Federal entities that receive Federal funding, assistance, permits, or otherwise require approval or authorization from a Federal agency for an action, may be indirectly impacted by the designation of critical habitat. However, the legally binding duty to avoid destruction or adverse modification of critical habitat rests squarely on the Federal agency. Furthermore, to the extent that non-Federal entities are indirectly impacted because they receive Federal assistance or participate in a voluntary Federal aid program, the Unfunded Mandates Reform Act would not apply; nor would critical habitat shift the costs of the large entitlement programs listed above onto State governments.
(b) We do not believe that this rule will significantly or uniquely affect small governments because it will not produce a Federal mandate of $100 million or greater in any year; that is, it is not a “significant regulatory action” under the Unfunded Mandates Reform Act. The proposed designation of critical habitat imposes no obligations on State or local governments. By definition, Federal agencies are not considered small entities, although the activities they fund or permit may be proposed or carried out by small entities. As such, a Small Government Agency Plan is not required.
In accordance with E.O. 12630 (“Government Actions and Interference with Constitutionally Protected Private Property Rights”), we have analyzed the potential takings implications of proposing critical habitat for Devils River minnow. Critical habitat designation does not affect landowner actions that do not require Federal funding or permits, nor does it preclude development of habitat conservation programs or issuance of incidental take permits to permit actions that do require Federal funding or permits to go forward. We conclude that this designation of critical habitat for Devils River minnow does not pose significant takings implications.
A complete list of all references cited in this rulemaking is available on the Internet at
The primary authors of this rulemaking are staff of the Austin Ecological Services Field Office, Austin, Texas.
16 U.S.C. 1361-1407; 16 U.S.C. 1531-1544; 16 U.S.C. 4201-4245; Pub. L. 99-625, 100 Stat. 3500; unless otherwise noted.
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 that the Agricultural Marketing Service (AMS) is requesting approval from the Office of Management of Budget of a new information collection—Application for Export Certification—under the Dairy program.
Comments must be submitted on or before April 7, 2008.
Interested persons are invited to submit written comments concerning this notice. Comments can be sent to Reginald Pasteur, Dairy Standardization Branch, Dairy Programs, Agricultural Marketing Service, U.S. Department of Agriculture, 1400 Independence Avenue, SW., 2734-S; Washington, DC 20250-0230. E-mail address:
All comments should reference docket number DA-08-01 and note the date and page number of this issue of the
Contact Reginald Pasteur, Dairy Standardization Branch, Dairy Programs, AMS, USDA (202) 690-3571, e-mail address:
The Secretary of Agriculture is authorized by the Agricultural Marketing Act of 1946 (AMA), as amended (7 U.S.C. 1621 et seq.), to provide voluntary Federal dairy grading and inspection services to facilitate the orderly marketing of dairy products and to enable consumers to obtain the quality of dairy products they desire. One means of facilitating international marketing of domestically produced dairy products is through the issuance of export certificates. Many importing countries require shipment specific certificates attesting to the acceptability of products and/or the manufacturing operations that produce these products. Some countries accept generic export certificates issued by the Dairy Grading Branch. Other countries have accepted certificates issued by the Dairy Grading Branch that include country specific information. The Dairy Grading Branch coordinates the content of these certificates with other Department of Agriculture (USDA) and Federal agencies when the statements made in these certificates are based on responsibilities of those agencies.
The manufacturing operations that produce products eligible for export certification include those operations participating in the USDA approved plant program administered by the Dairy Grading Branch (7 CFR part 58) and operations identified by the Food and Drug Administration. The AMA provides for the collection of reasonable fees from users of the services provided by the Dairy Grading Branch. Manufacturers and exporters requesting certificates are charged fees commensurate with costs associated with this service.
In order to prepare an export certificate, it is necessary that the manufacturer or exporter provide shipment specific information. This is accomplished by completing a worksheet developed by the Dairy Grading Branch then mailing or faxing this completed worksheet to the Washington, DC office. In some instances a Certificate of Conformance prepared by the manufacturer or exporter must also be completed and provided to the office before an export certificate can be prepared.
The information collection requirements in this request are needed in order for the Dairy Grading Branch to issue export certificates. The Export Certification Program supports the USDA, AMS mission of facilitating the marketing of U.S. agricultural products.
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.
7 U.S.C. 1621-1627.
Agricultural Marketing Service, USDA.
Notice.
The Agricultural Marketing Service (AMS) announces funding of approximately $1 million in competitive grant funds for fiscal year (FY) 2008 to increase domestic consumption of agricultural commodities by expanding direct producer-to-consumer market opportunities. Examples of direct producer-to-consumer market opportunities include new farmers' markets, roadside stands, community supported agriculture programs, and other direct producer-to-consumer infrastructures. AMS hereby requests proposals from eligible entities from the following categories: (1) Agricultural cooperatives, (2) local governments, (3) nonprofit corporations, (4) public benefit corporations, (5) economic development corporations, (6) regional farmers' market authorities, and (7) tribal governments. The maximum award per grant is $75,000. No matching funds are required. AMS strongly recommends that each applicant visit the AMS Web site at
Applications should be received at the address below and must be postmarked not later than March 24, 2008. Applications bearing a postmark after the deadline will not be considered.
Submit proposals and other required materials to Mr. Errol Bragg, Associate Deputy Administrator, Marketing Services Branch, Transportation and Marketing Programs, Agricultural Marketing Service (AMS), USDA, Room 2646-South, 1400 Independence Avenue, SW., Washington, DC 20250-0269, phone 202/720-8317.
For hard-copy (paper) submissions all forms, narrative, letters of support, and other required materials must be forwarded in one application package. AMS will not accept application packages by e-mail; electronic applications will be accepted only if submitted via
Mr. Errol Bragg, Associate Deputy Administrator, Marketing Services Branch, Transportation and Marketing Programs, Agricultural Marketing Service (AMS), on 202/720-8317, fax 202/690-0031, or by e-mail
This solicitation is issued pursuant to Section 6 of the Farmer-to-Consumer Direct Marketing Act of 1976 (7 U.S.C. 3001-3006) as amended by Section 10605 of the Farm Security and Rural Investment Act of 2002 (Pub. L. 107-171) (the Acts) authorizing the establishment of the Farmers' Market Promotion Program (7 U.S.C. 3005)(FMPP). The amended act states that the purposes of the FMPP are “(A) to increase domestic consumption of agricultural commodities by improving and expanding, or assisting in the improvement and expansion of, domestic farmers' markets, roadside stands, community-supported agriculture programs, and other direct producer-to-consumer market opportunities; and (B) to develop, or aid in the development of, new farmers' markets, roadside stands, community-supported agriculture programs, and other direct producer-to-consumer infrastructure.”
Detailed program guidelines may be obtained at
Further, in accordance with the Secretary's Statement of Policy (36 FR 13804), it is found and determined upon good cause that it is impracticable, unnecessary, and contrary to the public interest to engage in further public participation under 5 U.S.C 553 because the applications for the FMPP need to be made available as soon as possible as the program season approaches.
AMS will grant awards for projects that continue developing, promoting, and expanding direct marketing of agricultural commodities from farmers to consumers. Eligible FMPP proposals should support marketing entities where agricultural farmers or vendors sell their own products directly to consumers, and the sales of these farm products should represent the core business of the entity.
All eligible entities shall be domestic entities, i.e., those owned, operated, and located within one or more of the 50 United States and the District of Columbia only. Entities located within U.S. territories are not eligible.
Additionally, under this program eligible entities must apply for FMPP funds on behalf of direct marketing operators that include two or more agricultural farmers/vendors that produce and sell their own products through a common distribution channel. For example, a sole proprietor of a roadside farm market would not be eligible for this program. Individual agricultural producers, including farmers and farmers' market vendors, roadside stand operators, community supported agriculture participants, and other individual direct marketers are not eligible for FMPP funds.
FMPP funds exclude existing routine operational expenses such as management salaries or other's salaries associated with normal operation of existing farmers markets/marketing entities, utility bills, and insurance premiums.
FMPP grant funds must be applied to the specific programs and objectives identified in the application. Proprietary projects and projects that benefit one agricultural producer or individual will not be considered.
In accordance with the Paperwork Reduction Act of 1995, (44 U.S.C. Chapter 35), the FMPP information collection were previously approved by OMB and were assigned OMB control number 0581-0235.
AMS is committed to compliance with the Government Paperwork Elimination Act (GPEA) that requires Government agencies in general to provide the public the option of submitting information or transacting business electronically to the maximum extent possible.
Each applicant must follow the application preparation and submission instructions provided within the FMPP Guidelines at
Following are the options available for submitting proposals and applications to AMS:
FMPP is listed in the “Catalog of Federal Domestic Assistance” under number 10.168 and subject agencies must adhere to Title VI of the Civil Rights Act of 1964, which bars discrimination in all federally assisted programs.
Agricultural Marketing Service, USDA.
Notice.
The Agricultural Marketing Service (AMS) is revising the voluntary United States Standards for Grades of Cantaloups. Specifically, AMS is revising the “Application of Tolerances” section in the cantaloup standards. Additionally, AMS is removing the “Unclassified” category from the standards. These changes will bring the standards for cantaloups in line with current marketing practices, thereby improving the usefulness of the standards in serving the industry.
March 10, 2008.
Vincent J. Fusaro, Standardization Section, Fresh Products Branch, (202) 720-2185. The revised United States Standards for Grades of Cantaloups are available by accessing the Fresh Products Branch Web site at:
Section 203(c) of the Agricultural Marketing Act of 1946 (7 U.S.C. 1621-1627), as amended, directs and authorizes the Secretary of Agriculture “To develop and improve standards of quality, condition, quantity, grade and packaging and recommend and demonstrate such standards in order to encourage uniformity and consistency in commercial practices.” AMS is committed to carrying out this authority in a manner that facilitates the marketing of agricultural commodities. AMS makes copies of official standards available upon request. The United States Standards for Grades of Fruits and Vegetables not connected with Federal Marketing Orders or U.S. Import Requirements no longer appear in the Code of Federal Regulations, but are maintained by USDA, AMS, Fruit and Vegetable Programs.
AMS is revising the United States Standards for Grades of Cantaloups using the procedures that appear in Part 36, Title 7 of the Code of Federal Regulations (7 CFR part 36). These standards were last revised June 30, 1968.
Prior to undertaking detailed work to develop a proposed revision to the standards, AMS published a notice on December 28, 2006, in the
Based on the one initial comment received and information gathered, AMS is revising the grade standards for cantaloups to include these revisions.
The official grades of cantaloups covered by these standards are determined by the procedures set forth in the Regulations Governing Inspection, Certification, and Standards of Fresh Fruits, Vegetables and Other Products (7 CFR 51.1 to 51.62).
The revised United States Standards for Grades of Cantaloups will become effective 30 days after publication in the
7 U.S.C. 1621-1627.
Agricultural Marketing Service, USDA.
Final notice.
The Agricultural Marketing Service (AMS) of the Department of Agriculture (USDA) is revising the voluntary United States Standards for Grades of Pineapples. Specifically, AMS is replacing Tables I and II in the tolerances section with numerical tolerances and numerical application of tolerances. Decay tolerances will also be revised. This change will bring the standards for pineapples in line with current marketing practices, thereby, improving the usefulness of the standards in serving the industry.
March 10, 2008.
Vincent J. Fusaro, Standardization Section, Fresh Products Branch; (202) 720-2185. The revised United States Standards for Grades of Pineapples is available by accessing the AMS, Fresh Products Branch Web site at:
Section 203(c) of the Agricultural Marketing Act of 1946 (7 U.S.C. 1621-1627), as amended, directs and authorizes the Secretary of Agriculture “To develop and improve standards of quality, condition, quantity, grade and packaging and recommend and demonstrate such standards in order to encourage uniformity and consistency in commercial practices.” AMS is committed to carrying out this authority in a manner that facilitates the marketing of agricultural commodities
AMS is revising the voluntary United States Standards for Grades of Pineapples using the procedures that appear in Part 36, Title 7 of the Code of Federal Regulations (7 CFR part 36).
Prior to undertaking detailed work to develop a proposed revision to the standards, AMS published a notice on September 21, 2006, in the
The two supporting comments stated that the revision would facilitate the marketing of pineapples and make the standards for pineapples more uniform. The opposing commentor did not feel the revision was necessary at this time due to more pressing issues, which were not elaborated on by the commentor.
Based on comments received and information gathered, AMS is revising the pineapple standards by replacing Tables I and II in the tolerances section with numerical tolerances and numerical application of tolerances, as well as revising the decay tolerances.
The official grade of a lot of pineapples covered by these standards will be determined by the procedures set forth in the Regulations Governing Inspection, Certification, and Standards of Fresh Fruits, Vegetables and Other Products (Sec. 51.1 to 51.61).
The United States Standards for Grades of Pineapples will be effective 30 days after publication of this notice in the
7 U.S.C. 1621-1627.
Animal and Plant Health Inspection Service, USDA.
Revision and 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 a revision and extension of approval of an information collection associated with regulations to prevent the interstate spread of plant diseases within the United States.
We will consider all comments that we receive on or before April 7, 2008.
You may submit comments by either of the following methods:
Federal eRulemaking Portal: Go to
Postal Mail/Commercial Delivery: Please send two copies of your comment to Docket No. APHIS-2007-0132, Regulatory Analysis and Development, PPD, APHIS, Station 3A-03.8, 4700 River Road Unit 118, Riverdale, MD 20737-1238. Please state that your comment refers to Docket No. APHIS-2007-0132.
For information regarding the domestic quarantine regulations, contact Dr. Osama El Lissy, Director, Emergency Management, Emergency and Domestic Programs, PPQ, APHIS, 4700 River Road Unit 137, Riverdale, MD 20737; (301) 734-8247. For copies of more detailed information on the information collection, contact Mrs. Celeste Sickles, APHIS' Information Collection Coordinator, at (301) 734-7477.
These regulations prohibit or restrict the interstate movement of certain articles from infested areas to noninfested areas to prevent the spread of plant pests such as the Asian longhorned beetle, emerald ash borer, imported fire ant, Mexican fruit fly, and the West Indian fruit fly. For example, if an area of the United States has been placed under quarantine because of a fruit fly infestation, then certain plants and plant products that may present a risk of spreading the fruit fly may be moved interstate from the infested area only under certain conditions (e.g., after treatment or inspection). In this way, we prevent the fruit flies from being spread to noninfested areas of the United States via the movement of the plants and plant products.
Administering these regulations requires APHIS to collect information from a variety of individuals who are involved in growing, packing, handling, and transporting plants and plant products. The information we collect
Collecting this information requires us to use a number of forms and documents, including certificates, limited permits, transit permits, and outdoor household article documents.
We are asking the Office of Management and Budget (OMB) to approve our use of these information collection activities for 3 years.
This notice includes a description of the information collection requirements currently approved by OMB under numbers 0579-0088 (Domestic Quarantine Regulations) and 0579-0238 (Mexican Fruit Fly; Interstate Movement of Regulated Articles). After OMB approves and combines the burden for both collections under one collection (number 0579-0088), the Department will retire number 0579-0238.
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 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 collection of information 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.
Done in Washington, DC, this 31st day of January 2008.
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 pork and poultry products from Mexico transiting the United States.
We will consider all comments that we receive on or before April 7, 2008.
You may submit comments by either of the following methods:
•
•
For information on pork and poultry products from Mexico transiting the United States, contact Dr. Masoud Malik, Senior Staff Veterinarian, Technical Trade Services-Products, National Center for Import and Export, VS, APHIS, 4700 River Road Unit 40, Riverdale, MD 20737; (301) 734-8096. For copies of more detailed information on the information collection, contact Mrs. Celeste Sickles, APHIS* Information Collection Coordinator, at (301) 734-7477.
The regulations in 9 CFR 94.15 allow fresh (chilled or frozen) pork and pork products and poultry carcasses, parts, and products (except eggs and egg products) that are not eligible to enter into the United States to transit the United States from specified States in Mexico, via land ports, for export to another country.
The regulations set out conditions for the transit movements that protect against the introduction of classical swine fever or exotic Newcastle disease into the United States.
These conditions involve the use of several information collection activities, including the completion of an import permit application, the placement of
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.
Animal and Plant Health Inspection Service, USDA.
Notice.
We are advising the public that we have prepared a pest risk analysis that evaluates the risks associated with the importation into the continental United States of blueberries from Guatemala. Based on that analysis, we believe that the application of one or more designated phytosanitary measures will be sufficient to mitigate the risks of introducing or disseminating plant pests or noxious weeds via the importation of blueberries from Guatemala. We are making the pest risk analysis available to the public for review and comment.
We will consider all comments that we receive on or before April 7, 2008.
You may submit comments by either of the following methods:
• Federal eRulemaking Portal: Go to
•
Mr. Tony Román, Import Specialist, Commodity Import Analysis and Operation Staff, PPQ, APHIS, 4700 River Road Unit 133, Riverdale, MD 20737-1231; (301) 734-8758.
Under the regulations in “Subpart—Fruits and Vegetables” (7 CFR 319.56 through 319.56-47, referred to below as the regulations), the Animal and Plant Health Inspection Service (APHIS) of the U.S. Department of Agriculture prohibits or restricts the importation of fruits and vegetables into the United States from certain parts of the world to prevent plant pests from being introduced into and spread within the United States.
Section 319.56-4 contains a performance-based process for approving the importation of commodities that, based on the findings of a pest risk analysis, can be safely imported subject to one or more of the designated phytosanitary measures listed in paragraph (b) of that section. These measures are:
• The fruits or vegetables are subject to inspection upon arrival in the United States and comply with all applicable provisions of § 319.56-3;
• The fruits or vegetables are imported from a pest-free area in the country of origin that meets the requirements of § 319.56-5 for freedom from that pest and are accompanied by a phytosanitary certificate stating that the fruits or vegetables originated in a pest-free area in the country of origin;
• The fruits or vegetables are treated in accordance with 7 CFR part 305;
• The fruits or vegetables are inspected in the country of origin by an inspector or an official of the national plant protection organization of the exporting country, and have been found free of one or more specific quarantine pests identified by the risk analysis as likely to follow the import pathway; and/or
• The fruits or vegetables are a commercial consignment.
APHIS received a request from the Government of Guatemala to allow the importation of blueberries from Guatemala into the continental United States. We have completed a pest risk assessment to identify pests of quarantine significance that could follow the pathway of importation into the United States and, based on that pest risk assessment, have prepared a risk management analysis to identify phytosanitary measures that could be applied to the commodity to mitigate the pest risk. We have concluded that
After reviewing the comments we receive, we will announce our decision regarding the import status of blueberries from Guatemala in a subsequent notice. If the overall conclusions of the analysis and the Administrator's determination of risk remain unchanged following our consideration of the comments, then we will begin issuing permits for importation of blueberries from Guatemala into the continental United States subject to the requirements specified in the risk management analysis.
7 U.S.C. 450, 7701-7772, and 7781-7786; 21 U.S.C. 136 and 136a; 7 CFR 2.22, 2.80, and 371.3.
Farm Service Agency, USDA.
Notice; 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 organizations on an extension of a currently approved information collection associated with the Standards for Approval of Volunteer Programs.
We will consider comment received by April 7, 2008.
We invite you to submit comments on this notice. In your comment, include volume, date and page number of this issue of the
Comments also should be sent to the Desk Officer for Agriculture, Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503.
Ms. C. Mondina Jolley, Student Employment Program Manager, phone: (202) 401-0515.
The type of respondents are mainly students; individuals; and sponsored volunteer program service Agreements. The supporting documents with the forms in this information collection are required to allow the Agency to document the use (as required by the Office of Personnel Management letter dated April 18, 1996, i.e., to inform volunteers of the nature of their appointment with respect to service credit for leave or other employees benefits and record time and attendance) of individuals providing voluntary service but are not Federal employees except for the purpose of Chapter 81 of Title 5, U.S.C. (relating to Worker Compensation Program), and Sections 2671 through 2680 of Title 28 U.S.C. relating to tort claims. The forms are furnished to selected volunteers to secure and record information regarding the agreement and permit the volunteer to submit time and attendance information.
Comments are invited on:
(1) 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) The accuracy of the Agency's estimate of burden 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 on those who are to respond, including those who respond through the use of appropriate automated, electronic, or mechanical, collection techniques, or other forms of information technology.
All responses to this notice, including names and addresses when provided, will be a matter of public records. Comments will be summarized and included in the submission for Office of Management and Budget approval.
Forest Service, USDA.
Notice of meeting.
The Land Between The Lakes Advisory Board will hold a meeting on Thursday, February 28, 2008. Notice of this meeting is given under the Federal Advisory Committee Act, 5 U.S.C. App.2.
The meeting agenda includes the following:
The meeting is open to the public. Written comments are invited and may be mailed to: William P. Lisowsky, Area Supervisor, Land Between The Lakes, 100 Van Morgan Drive, Golden Pond, Kentucky 42211. Written comments must be received at Land Between The Lakes by February 21, 2008, in order for copies to be provided to the members at the meeting. Board members will review written comments received, and at their request, oral clarification may be requested at a future meeting.
The meeting will be held on Thursday, February 28, 2008, 9 a.m. to 3 p.m., CST.
The meeting will be held at Kentucky Dam Village State Resort Park, Gilbertsville, Kentucky, and will be open to the public.
Sharon Byers, Advisory Board Liaison, Land Between The Lakes, 100 Van Morgan Drive, Golden Pond, Kentucky 42211, 270-924-2002.
None.
An application has been submitted to the Foreign-Trade Zones Board (the Board) by the South Carolina State Ports Authority, grantee of FTZ 38, pursuant to Section 400.32(b)(1) of the Board's regulations (15 CFR Part 400), requesting authority on behalf of Kittel Supplier USA, Inc. (KSU), to assemble automotive roof/luggage racks under FTZ procedures within FTZ 38. It was formally filed on January 28, 2008.
The KSU facility (25 employees) is located at 201 Commerce Court within the Highway 290 Commerce Park (Site 3) in Duncan, South Carolina. Under FTZ procedures, KSU would assemble up to 2.5 million automotive roof/luggage racks (HTSUS 8708.29) annually for the U.S. market and export. Foreign components that would be used in the assembly activity (up to 100% of total purchases) include: aluminum rails and support legs, plastic support legs, brackets, fasteners and rubber seals (duty rates: free—5.7%).
FTZ procedures would exempt KSU from customs duty payments on the foreign components used in production for export. On domestic shipments transferred in-bond to U.S. automobile assembly plants with subzone status, no duties would be paid on the foreign components within the roof/luggage racks until the finished vehicles are subsequently entered for consumption, at which time the finished automobile duty rate (2.5%) could be applied to the foreign components. For the finished roof/luggage racks withdrawn directly by KSU for customs entry, the finished automotive part rate (2.5%) could be applied to the foreign inputs noted above. The application indicates that the company would also realize duty deferral and certain logistical/supply chain savings.
Public comment is invited from interested parties. Submissions (original and 3 copies) shall be addressed to the Board's Executive Secretary at the following address: Office of the Executive Secretary, Room 2111, U.S. Department of Commerce, 1401 Constitution Avenue, NW., Washington, DC 20230-0002. The closing period for receipt of comments is April 7, 2008. Rebuttal comments in response to material submitted during the foregoing period may be submitted during the subsequent 15-day period to April 22, 2008.
A copy of the application will be available for public inspection at the Office of the Foreign-Trade Zones Board's Executive Secretary at the address listed above. For further information, contact Pierre Duy, examiner, at:
Pursuant to Section 6(c) of the Educational, Scientific and Cultural Materials Importation Act of 1966 (Pub. L. 89-651, as amended by Pub. L. 106-36; 80 Stat. 897; 15 CFR part 301), we invite comments on the question of whether instruments of equivalent scientific value, for the purposes for which the instruments shown below are intended to be used, are being manufactured in the United States.
Comments must comply with 15 CFR 301.5(a)(3) and (4) of the regulations and be postmarked on or before February 27, 2008. Address written comments to Statutory Import Programs Staff, Room 2104, U.S. Department of Commerce, Washington, DC 20230. Applications may be examined between 8:30 a.m. and 5 p.m. at the U.S. Department of Commerce in Room 2104.
Docket Number: 07-072. Applicant: University of Washington, 1959 Pacific St., Room J405, Seattle, WA 98105. Instrument: Electron Microscope, Model Tecnai G2 F20 Twin. Manufacturer: FEI Company, Netherlands. Intended Use: The instrument is intended to be used in several different modes for single particle reconstruction and electron crystallography. The instrument will also be used as a teaching instrument to introduce graduate students, postdoctoral fellows and medical school faculty to the elements of protein structure determination by electron microscopy. Application accepted by Commissioner of Customs: January 18, 2008.
Docket Number: 08-002. Applicant: University of Texas at Austin, 204 E. Dean Keeton, Austin, TX 78721. Instrument: Electron Microscope, Model Quanta 600 FEG. Manufacturer: FEI Company, Czech Republic. Intended Use: The instrument is intended to be used to study polymer matrix composites, biological systems, and novel carbon materials. The instrument will also be used in determining microscale structure, including under environmental conditions. Application accepted by Commissioner of Customs: January 18, 2008.
Import Administration, International Trade Administration, Department of Commerce.
On August 6, 2007, the U.S. Department of Commerce (“the Department”) published in the
February 7, 2008.
Andrew McAllister or Brandon Farlander, AD/CVD Operations, Office 1, Import Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue, NW., Washington, DC 20230; telephone: (202) 482-1174 and (202) 482-0182, respectively.
Since the publication of the
We invited interested parties to comment on the preliminary results. Case briefs were received from De Matteis and petitioners on September 19, 2007. A rebuttal brief was received from De Matteis on September 24, 2007. The Department did not conduct a hearing in this review because none was requested.
The period of review (“POR”) for which we are measuring subsidies is January 1, 2005, through December 31, 2005.
Imports covered by the order are shipments of certain non-egg dry pasta in packages of five pounds four ounces or less, whether or not enriched or fortified or containing milk or other optional ingredients such as chopped vegetables, vegetable purees, milk, gluten, diastasis, vitamins, coloring and flavorings, and up to two percent egg white. The pasta covered by this scope is typically sold in the retail market, in fiberboard or cardboard cartons, or polyethylene or polypropylene bags of varying dimensions.
Excluded from the scope of the order are refrigerated, frozen, or canned pastas, as well as all forms of egg pasta, with the exception of non-egg dry pasta containing up to two percent egg white. Also excluded are imports of organic pasta from Italy that are accompanied by the appropriate certificate issued by the Instituto Mediterraneo Di Certificazione, Bioagricoop S.r.l., QC&I International Services, Ecocert Italia, Consorzio per il Controllo dei Prodotti Biologici, Associazione Italiana per l'Agricoltura Biologica, or Codex S.r.l. In addition, based on publicly available information, the Department has determined that, as of August 4, 2004, imports of organic pasta from Italy that are accompanied by the appropriate certificate issued by Bioagricert S.r.l. are also excluded from this order.
The merchandise subject to review is currently classifiable under items 1901.90.90.95 and 1902.19.20 of the
(1) On August 25, 1997, the Department issued a scope ruling that multicolored pasta, imported in kitchen display bottles of decorative glass that are sealed with cork or paraffin and bound with raffia, is excluded from the scope of the antidumping and countervailing duty orders.
(2) On July 30, 1998, the Department issued a scope ruling finding that multipacks consisting of six one-pound packages of pasta that are shrink-wrapped into a single package are within the scope of the antidumping and countervailing duty orders.
(3) On October 26, 1998, the Department self-initiated a scope inquiry to determine whether a package weighing over five pounds as a result of allowable industry tolerances is within the scope of the antidumping and countervailing duty orders. On May 24, 1999, we issued a final scope ruling finding that, effective October 26, 1998, pasta in packages weighing or labeled up to (and including) five pounds four ounces is within the scope of the antidumping and countervailing duty orders.
(4) On April 27, 2000, the Department self-initiated an anti-circumvention inquiry to determine whether Pastificio Fratelli Pagani S.p.A.'s importation of pasta in bulk and subsequent repackaging in the United States into packages of five pounds or less constitutes circumvention with respect to the antidumping and countervailing duty orders on pasta from Italy pursuant to section 781(a) of the Tariff Act of 1930, as amended (“the Act”), and 19 CFR 351.225(b).
There has been one change since the
In addition, a complete version of the Decision Memo can be accessed directly on the Web at
In accordance with 19 CFR 351.221(b)(4)(i), we calculated an individual subsidy rate for Pallante and De Matteis.
The calculations will be disclosed to the interested parties in accordance with 19 CFR 351.224(b).
Because the countervailing duty rate for Atar is zero, we will instruct U.S. Customs and Border Protection (“CBP”) to liquidate entries for Atar during the period January 1, 2005, through December 31, 2005, without regard to countervailing duties in accordance with 19 CFR 351.106(c). For Pallante and De Matteis, the Department will instruct CBP to assess countervailing duties at these net subsidy rates. The Department will issue appropriate instructions directly to CBP 15 days after publication of these final results of this review.
For all other companies that were not reviewed (except Barilla G. e R. F.lli S.p.A. and Gruppo Agricoltura Sana S.r.l., which are excluded from the order, and Pasta Lensi S.r.l. which was revoked from the order), the Department has directed CBP to assess countervailing duties on all entries between January 1, 2005, and December 31, 2005, at the rates in effect at the time of entry. Agritalia has been reviewed previously and has its own exporter-specific rate of 2.92 percent.
The Department also intends to instruct CBP to collect cash deposits of estimated countervailing duties. Since the countervailable subsidy rate for Atar is zero, the Department will instruct CBP to continue to suspend liquidation of entries, but to collect no cash deposits of estimated countervailing duties for Atar on all shipments of the subject merchandise that are entered, or withdrawn from warehouse, for consumption on or after the date of publication of the final results of this administrative review.
For all non-reviewed firms (except Barilla G. e R. F.lli S.p.A. and Gruppo Agricoltura Sana S.r.l., which are excluded from the order, and Pasta Lensi S.r.l. which was revoked from the order), we will instruct CBP to collect cash deposits of estimated countervailing duties at the most recent company-specific or all-others rate applicable to the company. These rates shall apply to all non-reviewed companies until a review of a company assigned these rates is requested.
This notice serves as a reminder to parties subject to administrative protective order (“APO”) of their responsibility concerning the disposition of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of return or destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and the terms of an APO is a sanctionable violation.
We are issuing and publishing these results in accordance with sections 751(a)(1) and 777(i)(1) of the Act.
Comment 1: De Matteis Received Additional Subsidies Under Law 662/96 and Law 488/92.
Comment 2: The Department Should Countervail Subsidies Received by Agritalia's Cross-Owned Companies.
Comment 3: The Benefits Under Law 488/92 Received by De Matteis Should be Allocated Over Total Sales.
Import Administration, International Trade Administration, Department of Commerce.
On August 7, 2007, the Department of Commerce (Department) published in the
The review covers one respondent, MTZ Polyfilms, Ltd. (MTZ).
Based on our analysis of comments received on the
February 7, 2007.
Jun Jack Zhao or Martha Douthit, AD/CVD Operations, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th and Constitution Avenue, NW., Washington, DC 20230; telephone: (202) 482-1396 or (202) 482-5050, respectively.
On August 7, 2007, the Department published the preliminary results of the administrative review of the antidumping duty order on PET film from India. In accordance with 19 CFR. 351.309(c)(ii), we invited parties to comment on our
The period of review (POR) is July 1, 2005 through June 30, 2006.
For purposes of this administrative review, the products covered are all gauges of raw, pretreated or primed PET Film, whether extruded or coextruded. Excluded are metallized films and other finished films that have had at least one of their surfaces modified by the application of a performance-enhancing resinous or inorganic layer of more than 0.00001 inches thick. Since the order was published, there has been one scope determination, dated August 25, 2003. In this determination, requested by International Packaging Films, Inc., the Department determined that tracing and drafting film is outside of the scope of the order. Imports of PET Film are classifiable under the Harmonized Tariff Schedule of the United States (HTSUS) under item number 3920.62.00. HTSUS subheadings are provided for convenience and customs purposes. The written scope of this proceeding is dispositive.
All issues raised by interested parties in the case briefs are listed in the Appendix to this notice, and addressed in the Memorandum from Stephen J. Claeys, Deputy Assistant Secretary for Import Administration, to David M. Spooner, Assistant Secretary for Import Administration, Issues and Decision Memorandum for the Administrative Review of the Antidumping Duty Order on PET Film from India (Decision Memorandum), which is hereby adopted by this notice. Parties can find a complete discussion of all issues raised in this administrative review in this public memorandum, which is on file in the Central Records Unit, Room B-099 of the main Department building. In addition, a complete version of the
Based on our analysis of comments received from MTZ, we have made changes to the margin calculation used in the
We determine that the following percentage margin exists for the period July 1, 2005 through June 30, 2006:
The Department shall determine, and U.S. Customs and Border Protection shall assess, antidumping duties on all appropriate entries. The Department will issue appraisement instructions directly to U.S. Customs and Border Protection. For duty-assessment purposes, we calculated importer-specific assessment rates by dividing the dumping margins calculated for each importer by the total entered value of sales for each importer during the period of review.
The Department intends to issue assessment instructions to CBP 15 days after the date of publication of these final results of review.
The following deposit requirements will be effective upon publication of this notice of final results of administrative review for all shipments of PET Film from India entered, or withdrawn from warehouse, for consumption on or after the date of publication, as provided by section 751(a)(1) of the Act: (1) The cash deposit rate for MTZ will be the rate shown above; (2) for previously reviewed or investigated companies not covered in this review, the cash deposit rate will continue to be the company-specific rate published for the most recent period; (3) if the exporter is not a firm covered in this review, a prior review, or the less-than-fair-value (LTFV) investigation, but the manufacturer is a firm covered in this review, the cash deposit rate will be the rate established for the most recent period for the manufacturer of the subject merchandise; and (4) if neither the exporter nor the manufacturer is a firm covered in this or any previous proceeding conducted by the Department, the cash deposit rate will continue to be 5.71 percent, which is the all others rate established in the less than fair value investigation (24.14 percent), adjusted for the export subsidy rate found in the companion countervailing duty investigation. These cash deposit requirements, when imposed, shall remain in effect until further notice.
This notice also serves as a final reminder to importers of their responsibility under 19 CFR 351.402(f)(2) to file a certificate regarding the reimbursement of antidumping duties or countervailing duties prior to liquidation of the relevant entries during this review period. Failure to comply with this requirement could result in the Secretary's presumption that reimbursement of the antidumping duties or countervailing duties occurred and the subsequent assessment of double antidumping duties or countervailing duties.
This notice also serves as a reminder to parties subject to administrative protective orders (APOs) of their responsibility concerning the return or destruction of proprietary information disclosed under APO in accordance with 19 CFR 351.305, which continues to govern business proprietary information in this segment of the
We are issuing and publishing this determination and notice in accordance with sections 751(a)(1) of the Act.
1. Adjustment of Export Price (EP) by the countervailing duties imposed on PET Film.
Import Administration, International Trade Administration, Department of Commerce.
February 7, 2008.
On January 23, 2008, the Department of Commerce (the “Department”) published the preliminary determination of sales at less than fair value (“LTFV”) in the antidumping investigation of certain steel nails from the People's Republic of China (“PRC”).
Nicole Bankhead, 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) 482-9068.
On January 23, 2008, the Department published in the
On January 22, 2008, Paslode and Petitioners
The period of investigation (“POI”) is October 1, 2006, through March 31, 2007. This period corresponds to the two most recent fiscal quarters prior to the month of the filing of the petition, May 2007.
The merchandise covered by this investigation includes certain steel nails having a shaft length up to 12 inches. Certain steel nails include, but are not limited to, nails made of round wire and nails that are cut. Certain steel nails may be of one piece construction or constructed of two or more pieces. Certain steel nails may be produced from any type of steel, and have a variety of finishes, heads, shanks, point types, shaft lengths and shaft diameters. Finishes include, but are not limited to, coating in vinyl, zinc (galvanized, whether by electroplating or hot-dipping one or more times), phosphate cement, and paint. Head styles include, but are not limited to, flat, projection, cupped, oval, brad, headless, double, countersunk, and sinker. Shank styles include, but are not limited to, smooth, barbed, screw threaded, ring shank and fluted shank styles. Screw-threaded nails subject to this proceeding are driven using direct force and not by turning the fastener using a tool that engages with the head. Point styles include, but are not limited to, diamond, blunt, needle, chisel and no point. Finished nails may be sold in bulk, or they may be collated into strips or coils using materials such as plastic, paper, or wire. Certain steel nails subject to this proceeding are currently classified under the Harmonized Tariff Schedule of the United States (“HTSUS”) subheadings 7317.00.55, 7317.00.65 and 7317.00.75.
Excluded from the scope of this proceeding are roofing nails of all lengths and diameter, whether collated or in bulk, and whether or not galvanized. Steel roofing nails are specifically enumerated and identified in ASTM Standard F 1667 (2005 revision) as Type I, Style 20 nails. Also excluded from the scope of this proceeding are corrugated nails. A corrugated nail is made of a small strip of corrugated steel with sharp points on one side. Also excluded from the scope of this proceeding are fasteners suitable for use in powder-actuated hand tools, not threaded and threaded, which are currently classified under HTSUS 7317.00.20 and 7317.00.30. Also excluded from the scope of this proceeding are thumb tacks, which are currently classified under HTSUS 7317.00.10.00. Also excluded from the scope of this proceeding are certain brads and finish nails that are equal to or less than 0.0720 inches in shank diameter, round or rectangular in cross section, between 0.375 inches and 2.5 inches in length, and that are collated with adhesive or polyester film tape backed with a heat seal adhesive.
While the HTSUS subheadings are provided for convenience and customs purposes, the written description of the scope of these investigations is dispositive.
Ministerial errors are defined in section 735(e) of the Act as “errors in addition, subtraction, or other arithmetic function, clerical errors resulting from inaccurate copying, duplication, or the like, and any other type of unintentional error which the administering authority considers ministerial.” Section 351.224(e) of the Department's regulations provides that the Department “will analyze any comments received and, if appropriate, correct any significant ministerial error by amending the preliminary determination* * *.” A significant ministerial error is defined as an error, the correction of which, singly or in combination with other errors, would result in (1) a change of at least five absolute percentage points in, but not less than 25 percent of, the weighted-
Paslode argues that the Department incorrectly applied the rail freight surrogate value in calculating the antidumping duty margin. Paslode notes in calculating the margin, the Department set the surrogate value for rails to 6.07 rupees per kilogram.
We agree that the Department incorrectly calculated the rail surrogate value. This error qualifies as a ministerial error in accordance with section 735(e) of the Act. Moreover, when considered in combination with the other corrections discussed below, this error constitutes a significant ministerial error in accordance with section 351.224(g) of the Department's regulations.
Petitioners state that the Department inadvertently did not account for Paslode's reported billing adjustments. Petitioners argue that the Department should adjust the gross unit price to account for these billing adjustments in the targeted dumping analysis program. In addition, Petitioners argue that this same change needs to be made to Paslode's margin calculation programs.
We agree that the Department did not account for certain billing adjustments in the targeted dumping and margin calculation programs. Paslode reported that it incurred billing adjustments in its January 3, 2008, supplemental Section C questionnaire response and we indicated that we were adjusting for these billing adjustments.
Petitioners argue that the Department used the incorrect surrogate value for profit in the CEP profit calculation in Paslode's targeted dumping analysis program.
We agree that the Department inadvertently mis-entered the profit surrogate value in the CEP profit calculation in Paslode's targeted dumping analysis program. This error qualifies as a ministerial error in accordance with section 735(e) of the Act. Moreover, when considered in combination with the other corrections discussed in this notice, this error constitutes a significant ministerial error in accordance with section 351.224(g) of the Department's regulations.
Petitioners argue that the Department inadvertently entered the incomplete surrogate brokerage and handling charge in the calculation of Paslode's movement expenses.
We agree that the Department inadvertently only entered the surrogate brokerage and handling charge out to two decimal points instead of five in the calculation of Paslode's movement expenses. This error qualifies as a ministerial error in accordance with section 735(e) of the Act. Moreover, when considered together with the other corrections discussed in this notice, this error constitutes a significant ministerial error in accordance with section 351.224(g) of the Department's regulations.
We determine that these allegations qualify as ministerial errors as defined in section 351.224(g) of the Department's regulations because they result in a change of more than five absolute percentage points to Paslode's dumping margin. Accordingly, we have corrected the errors alleged by Paslode and Petitioners.
As a result of correcting the above errors made to Paslode's margin, the margin for the companies granted separate rate status must also be revised because the margin for those companies was partially derived from Paslode's margin.
As a result of corrections of ministerial errors, the weighted-average dumping margins are as follows:
The collection of bonds or cash deposits and suspension of liquidation will be revised accordingly and parties will be notified of this determination, in accordance with section 733(d) and (f) of the Act.
In accordance with section 733(f) of the Act, we have notified the International Trade Commission (“ITC”) of our amended preliminary determination. If our final determination is affirmative, the ITC will make its final determination as to whether the domestic industry in the United States is materially injured, or threatened with material injury, by reason of imports of certain lined paper products, or sales (or the likelihood of sales) for importation, of the subject merchandise within 45 days of our final determination.
This determination is issued and published in accordance with sections 733(f) and 777(i)(1) of the Act and 19 CFR 351.224(e).
Import Administration, International Trade Administration, Department of Commerce.
February 7, 2008.
Kristin Case or Catherine Cartsos, AD/CVD Operations, Office 5, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue, NW., Washington, DC 20230; telephone: (202) 482-3174 and (202) 482-1757, respectively.
On October 11, 2007, the Department of Commerce (the Department) initiated the antidumping duty investigation of raw flexible magnets from Taiwan. See
On January 16, 2008, the petitioner, Magnum Magnetics Corporation, made a timely request pursuant to 19 CFR 351.205(e) for a postponement of the preliminary determination with respect to Taiwan. The petitioner requested postponement of the preliminary determination in order to allow the Department additional time to address several complex issues such as the appropriate model-matching characteristics.
For the reason identified by the petitioner and because there are no compelling reasons to deny the request, the Department is postponing the deadline for the preliminary determination with respect to Taiwan under section 733(c)(1)(A) of the Act by 50 days to April 18, 2008. The deadline for the final determination will continue to be 75 days after the date of the preliminary determination, unless extended.
This notice is issued and published pursuant to section 733(c)(2) of the Act and 19 CFR 351.205(f)(1).
Import Administration, International Trade Administration, Department of Commerce.
On February 1, 2007, the Department of Commerce (“the Department”) initiated sunset reviews of the antidumping duty (“AD”) orders on stainless steel bar (“SSB”) from France, Germany, Italy, South Korea, and the United Kingdom; and the countervailing duty (“CVD”) order on SSB from Italy.
March 7, 2007 (AD Orders) and March 8, 2007 (CVD Order).
Devta Ohri or Brandon Farlander, AD/CVD Operations, Import Administration, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue, NW., Washington, DC 20230; telephone: (202) 482-3853 and (202) 482-0182, respectively.
The merchandise subject to these AD and CVD orders is “stainless steel bar,” which includes articles of stainless steel in straight lengths that have been either hot-rolled, forged, turned, cold-drawn, cold-rolled or otherwise cold-finished, or ground, having a uniform solid cross section along their whole length in the shape of circles, segments of circles, ovals, rectangles (including squares), triangles, hexagons, octagons, or other convex polygons. Stainless steel bar includes cold-finished stainless steel bars that are turned or ground in straight lengths, whether produced from hot-rolled bar or from straightened and cut rod or wire, and reinforcing bars that have indentations, ribs, grooves, or other deformations produced during the rolling process.
Except as specified above, the term does not include stainless steel semi-finished products, cut length flat-rolled products (
The stainless steel bar subject to this review is currently classifiable under subheadings 7222.11.00.05, 7222.11.00.50, 7222.19.00.05, 7222.19.00.50, 7222.20.00.05, 7222.20.00.45, 7222.20.00.75, and 7222.30.00.00 of the
On March 7, 2002, the Department issued the AD orders on SSB from France, Germany, Italy, South Korea, and the United Kingdom.
On February 1, 2007, the Department initiated, and the ITC instituted, sunset reviews of the AD orders on SSB from France, Germany, Italy, South Korea, and the United Kingdom, and the CVD order on SSB from Italy.
As a result of its sunset reviews of these orders, the Department found that revocation of the AD orders would be likely to lead to the continuation or recurrence of dumping and that revocation of the CVD order would be likely to lead to continuation or recurrence of a countervailable subsidy.
On January 31, 2008, the ITC determined, pursuant to section 751(c) of the Act, that revocation of these orders would not be likely to lead to continuation or recurrence of material injury to an industry in the United States within a reasonably foreseeable time.
As a result of the determination by the ITC that revocation of these orders is not likely to lead to the continuation or recurrence of material injury to an industry in the United States, the Department, pursuant to section 751(d) of the Act, is revoking the AD orders on SSB from France, Germany, Italy, South Korea, and the United Kingdom, and the CVD order on SSB from Italy. Pursuant to section 751(d) of the Act and 19 CFR 351.222(i)(2)(i), the effective date of revocation is March 7, 2007 (AD Orders) and March 8, 2007 (CVD Order). The Department will notify U.S. Customs and Border Protection to terminate suspension of liquidation and collection of cash deposits on entries of the subject merchandise entered or withdrawn from warehouse on or after March 7, 2007 (AD Orders) and March 8, 2007 (CVD Order). Entries of subject merchandise prior to the effective date of revocation will continue to be subject to suspension of liquidation and antidumping and countervailing duty deposit requirements. The Department will complete any pending administrative reviews of these orders and will conduct administrative reviews of subject merchandise entered prior to the effective date of revocation in response to appropriately filed requests for review.
These five-year sunset reviews and notice are in accordance with section 751(d)(2) of the Act and published pursuant to section 777(i)(1) of the Act.
National Institute of Standards and Technology, Commerce.
Notice of public meeting.
The National Institute of Standards and Technology (NIST)
The workshop will be held on February 19, 2008, from 9 a.m. till 5 p.m.
The workshop will be held at National Institute of Standards and Technology, 100 Bureau Drive, Gaithersburg, MD 20899, Building 101, Lecture Room B.
Stephen Nightingale, 301 975 4171,
In June 2005 the Office of Management and Budget initiated a policy to expedite adoption and deployment of IPv6 within the Federal Government (
The USG IPv6 Testing Program will require that products document claims of compliance to the profile through a Supplier's Declaration of Conformity (SDOC) in accordance with ISO/IEC 17050. Such declarations will be traceable to specific test results from laboratories accredited to the specific requirements of the IPv6 Test Program, including full compliance with ISO/IEC 17025—
The scope of laboratory accreditation includes test methods for computer network protocol conformance and interoperability testing based on open public test suites. The detailed set of test methods and validation procedures are still under development. One purpose of this meeting is to discuss the general plans for the development and execution of the test program and to identify parties interested in collaborating in the further development of its details.
1. The USG IPv6 profile, its components and timing constraints.
2. Accreditor qualification.
3. Test method validation.
4. Suppliers Declaration of Conformity.
5. Discussion.
All intending participants must register in advance, to gain access to the campus. Due to space limitations, there is a limit of 60 participants in this workshop. Precedence will be given to the first two representatives of each accreditation body and IPv6 testing laboratory. Please register early and designate your primary representative, in case there is a further need, due to a high response rate, to limit participation to one representative per organization to ensure that all interested parties can participate. Access to the NIST campus and the room cannot be guaranteed for unregistered participants.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration, Commerce.
Notice; availability of report.
The National Marine Fisheries Service (NMFS) announces the availability of a joint report on the Forest Service and Bureau of Land Management's use of the counterpart regulations for projects that support the National Fire Plan.
The report and related documents are available for review upon written request or on-line from the NMFS website:
Ann Garrett, Endangered Species Division at (301)713-1401.
In accordance with the Alternative Consultation Agreements NMFS and the Fish and Wildlife Service (FWS) have with the Bureau of Land Management (BLM) and the Forest Service (FS), conducted a review of the determinations that BLM and FS made under the joint counterpart regulations for Endangered Species Act (ESA) section 7 consultation. The counterpart regulations, codified in 50 CFR part 402 subpart C, provide an optional alternative to the standard section 7 consultation process described in subparts A and B, and were developed specifically for agency projects that authorize, fund, or carry out actions that support the National Fire Plan. The National Fire Plan, part of the President's 2002 Healthy Forests Initiative, is an interagency strategy for reducing the risk of catastrophic wildland fires and resorting fire-adapted ecosystems. The intent of the counterpart regulations is to eliminate the need to conduct informal consultation and obtain written concurrence from the FWS and NMFS for those National Fire Plan actions that the FS or BLM determines are “not likely to adversely affect (NLAA)” any listed species or designated critical habitat.
According to the counterpart regulations for National Fire Plan activities, the FS or BLM may make NLAA determinations for fire plan projects after entering into an Alternative Consultation Agreement with FWS and NMFS, and upon implementing the provisions of the ACA. Each ACA outlines the procedures and roles of the agencies and specific requirements for reporting, training and execution of self-certification, and conducting periodic program monitoring of the use of the counterpart regulations. With the publication of this Notice of Availability, NMFS and FWS are announcing the completion of the first review of the FS's and BLM's use of the counterpart regulations and the availability of the report describing the results of the program review and recommendations for improving their decisions made pursuant to this authority. The results of the first review
16 U.S.C. 1531
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; receipt of application for modification
Notice is hereby given that Mr. Michael M. Hastings, University of Maine, 5717 Corbett Hall, Orono, Maine 04469, has requested a modification to scientific research Permit No. 1595-01.
Written, telefaxed, or e-mail comments must be received on or before March 10, 2008.
The modification request and related documents are available for review upon written request or by appointment in the following offices:
Permits, Conservation and Education Division, Office of Protected Resources, NMFS, 1315 East-West Highway, Room 13705, Silver Spring, MD 20910; phone (301)713-2289; fax (301)427-2521; and
Northeast Region, NMFS, One Blackburn Drive, Gloucester, MA 01930-2298; phone (978)281-9300; fax (978)281-9394.
Written comments or requests for a public hearing on this request should be submitted to the Chief, Permits, Conservation and Education Division, F/PR1, Office of Protected Resources, NMFS, 1315 East-West Highway, Room 13705, Silver Spring, MD 20910. Those individuals requesting a hearing should set forth the specific reasons why a hearing on this particular modification request would be appropriate.
Comments may also be submitted by facsimile at (301)427-2521, provided the facsimile is confirmed by hard copy submitted by mail and postmarked no later than the closing date of the comment period.
Comments may also be submitted by e-mail. The mailbox address for providing e-mail comments is
Brandy Belmas or Malcolm Mohead, (301)713-2289.
The subject modification to Permit No. 1595-01, issued on May 1, 2007 (72 FR 19469) is requested under the authority of the Endangered Species Act of 1973, as amended (16 U.S.C. 1531
Permit No. 1595-01 authorizes the permit holder to: capture, anesthetize, measure, weigh, sex (borescope), Carlin and PIT tag, recover and release up to 70 sub-adult and adult shortnose sturgeon annually. Up to 30 sub-adult and adult shortnose sturgeon, annually, would be fitted (or implanted) with an external (or internal) transmitter, in addition to the previously mentioned procedures. This permit also authorizes the annual lethal take of up to 50 shortnose sturgeon eggs, up to 30 of which may be transported to the lab for genetic sampling. Up to 2 incidental mortalities of shortnose sturgeon each year is also currently authorized.
The permit holder is now requesting authorization to: (1) increase the total annual take of shortnose sturgeon from 100 fish to 200 fish; (2) expand netting efforts to include currently restricted areas (i.e., within 0.5 miles of the confluence of the Penobscot River with Cove Brook, and the Kenduskeag River); (3) add D-net sampling as a method of sturgeon egg collection; (4) add non-lethal blood sampling as a procedure (which would be conducted on up to 30 fish of which the capture and handling is already authorized); and (5) add and remove personnel authorized to conduct research activities. The purpose of the proposed modification is to better assess the distribution, movements, abundance and spawning of shortnose sturgeon in the Penobscot River, Maine. This modification would be valid through the expiration date of the original permit, March 31, 2012.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of issuance of a letter of authorization.
In accordance with the Marine Mammal Protection Act (MMPA), as amended, notification is hereby given that a letter of authorization (LOA) to take three species of marine mammals incidental to missile launch operations from San Nicolas Island, CA (SNI) has been issued to the Naval Air Warfare Center Weapons Division (NAWC-WD), Point Mugu, CA.
This authorization is effective from February 3, 2008, through October 2, 2008.
The application, LOA, and Navy monitoring report are available for review in the Office of Protected Resources, NMFS, 1315 East-West Highway, Silver Spring, MD 20910 or by contacting one of the individuals mentioned below (See
Howard Goldstein or Ken Hollingshead, NMFS, (301) 713-2289 ext. 172.
Section 101(a)(5)(A) of the MMPA (16 U.S.C. 1361
Authorization may be granted for periods up to five years if NMFS finds, after notification and opportunity for public comment, that the taking will have a negligible impact on the species or stock(s) of marine mammals and will not have an unmitigable adverse impact on the availability of the species or stock(s) for certain subsistence uses. In addition, NMFS must prescribe regulations that include permissible methods of taking and other means of
Pursuant to these regulations, NMFS has issued an LOA to the NAWC-WD. Issuance of the LOA is based on a finding made in the preamble to the final rule that the total takings by this project (with the mitigation) will have no more than a negligible impact on the affected species or stocks of marine mammals and will not have an unmitigable adverse impact on the availability of such species or stock for taking for relevant subsistence uses. NMFS also finds that the applicant will meet the requirements contained in the implementing regulations and LOA, including monitoring and reporting requirements.
According to the draft technical report, the NAWC-WD performed a total of three missile launches between February and November 2007. A dual launch of Rolling Airframe Missiles(RAM) occurred on 26 April, 2007; and single GQM-163A Supersonic Sea-Skimming Target (SSST) were launched on June 12 and 13, 2007. California sea lions were observed during all three launches on all three launch dates. Northern elephant seals were observed during all three launches on the three dates. Pacific harbor seals were not observed during launches on any launch dates. Based on monitoring efforts between February and November 2007, the NAWC-WD estimates that approximately 567 sea lions, 40 harbor seals, and no elephant seals were affected by launch sounds. There was no evidence of injury or mortality during or immediately succeeding the launches for any pinniped species. NMFS finds that the level of taking under the 2008 LOA will be consistent with the findings made in the final rule for this action.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; issuance of permit.
Notice is hereby given that Mystic Aquarium, 55 Coogan Boulevard, Mystic, CT 06355 (Dr. Lisa Mazzaro, Principal Investigator) has been issued a permit to conduct research and enhancement on Steller sea lions (
The permit and related documents are available for review upon written request or by appointment in the following office(s):
Permits, Conservation and Education Division, Office of Protected Resources, NMFS, 1315 East-West Highway, Room 13705, Silver Spring, MD 20910; phone (301)713-2289; fax (301)427-2521; and
Northeast Region, NMFS, One Blackburn Drive, Gloucester, MA 01930-2298; phone (978)281-9300; fax (978)281-9394.
Jennifer Skidmore or Amy Sloan, (301)713-2289.
On June 8, 2007, notice was published in the
Mystic Aquarium has been issued a permit to continue activities authorized under Permit No. 42-1642-03 for the following two projects: Project 1: Research and display of captive Steller sea lions including authorization (1) to import or receive a second intact adult male Steller sea lion and subsequently return this animal to its facility of origin, if necessary; and (2) to import up to nine female Steller sea lions from the Vancouver Aquarium, and to receive a “non-releasable” one year old male Steller sea lion from The Marine Mammal Center in Sausalito, California. At any one time the maximum number of adult male SSL maintained at Mystic Aquarium will be two and the number of females and pups will not exceed nine.
Project 2: Receipt, import and export of tissues from a maximum of 10,000 animals, up to 30 samples per animal per year (i.e., 5000 pinniped and 5000 cetaceans) under NMFS jurisdiction in the U.S. and abroad (i.e. worldwide). Samples will be analyzed for purposes of research on marine mammal health (e.g., nutrition, disease, immune function, environmental stressors).
In compliance with the National Environmental Policy Act of 1969 (42 U.S.C. 4321
Issuance of this permit, as required by the ESA, was based on a finding that such permit: (1) was applied for in good faith; (2) will not operate to the disadvantage of such endangered species; and (3) is consistent with the purposes and policies set forth in section 2 of the ESA.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of public meeting.
This notice advises the public that the Western Pacific Fishery Management Council (Council) will hold a public meeting in Pago Pago, American Samoa to discuss potential
The public meeting will be held on Saturday February 23, 2008 at the American Samoa Department of Marine and Wildlife Resources Conference Room. Written comments will be accepted until March 7, 2008. For specific times, and the agenda, see
The public meeting will be held on Saturday February 23, 2008 from 9 a.m. to 1 p.m. at the American Samoa Department of Marine and Wildlife Resources Conference Room, Pago Pago, American Samoa. Send written comments to Kitty M. Simonds, Western Pacific Regional Fishery Management Council, 1164 Bishop Street, Suite 1400, Honolulu, HI 96813.
Kitty M. Simonds, Executive Director; telephone: (808)522-8220.
The agenda for the meeting is as follows. Council is seeking public input on agenda items 2 and 3.
At its 138th meeting held in June 2007, the Council discussed the potential for increases in purse seine fishing within the U.S. Exclusive Economic Zone surrounding American Samoa and directed staff to develop a paper examining potential options to expand the existing 50 miles large pelagic vessel exclusion zone specifically for purse seine vessels to avoid potential gear conflicts between these vessels and the American Samoa longline and domestic troll vessels. At its 139th meeting held in October 2007, the Council recommended an amendment be developed which included a range of preliminary alternatives as follows:
Under the no-action alternative waters within 3-50 nm around American Samoa would continue to be closed to pelagic fishing by vessels greater than 50ft in length including purse seine vessels
Under Alternative 2, a closed area would be established to exclude purse seine vessels from operating within all EEZ waters around American Samoa
Under Alternative 3, a closed area would be established to exclude purse seine vessels from operating within 75 nm around American Samoa
At its 139th Council meeting, the Council directed staff to draft a regulatory amendment that would provide a framework to adjust the American Samoa longline limited entry program, including establishing a process to reopen the limited entry permit application process, amending the large (>50ft) pelagic vessel 50 nm closed areas, and eliminating the minimum landing requirements for all vessel size classes in the American Samoa longline limited entry program.
These issues were brought before the Council by fishery participants who were concerned that rapid changes in the American Samoa pelagic longline fishery over the past several years has resulted in lower than anticipated participation in the fishery, and that the current measures including the large vessel area closure, minimum landing requirements and initial permit qualification criteria be reviewed in order to ensure that the management program continues to ensure sustained participation in the domestic longline fishery and to maintain opportunities for substantial participation by indigenous American Samoans in this fishery while minimizing adverse impacts on American Samoa communities.
Regarding potential modification to the American Samoa pelagic longline limited entry permit and landing requirements, the preliminary alternatives to be discussed include:
Under Alternative 1, the Council would not re-open the permit application process and would not remove the minimum landing requirement.
Under Alternative 2, the Council would not re-open the permit application process but would remove the minimum landing requirement.
Under Alternative 3 the Council would re-open the permit application process but would not remove the minimum landing requirement.
Under Alternative 4 the Council would re-open the permit application process and would also remove the minimum landing requirement.
Regarding the American Samoa large pelagic vessel area closure, the preliminary alternatives to be discussed include:
Alternative 1: No Action, Maintain Current 50 nm closure to vessels greater than 50 ft.
Under Alternative 1, the Council would maintain the current 50 nautical mile area closure for pelagic fishing vessels greater than 50 ft. around the islands of the American Samoa Archipelago
Alternative 2: Modify the area closure to 25 nautical miles
Under Alternative 2, the Council would temporarily reduce the area closure from 50 nautical miles to 25 nautical miles. The Council would also review the status of the fishery every two years to determine whether the closure should be maintained at 25 miles or return back to 50 nautical miles.
Alternative 3: Modify the area closure to 12 nautical miles
Under Alternative 3, the Council would temporarily reduce the area closure from 50 nautical miles to 12 nautical miles. The Council would also review the status of the fishery every two years to determine whether the closure should be maintained at 12 miles or return back to 50 nautical miles.
Alternative 4: Suspend the 50 mile area closure indefinitely
Under Alternative 4, the Council would suspend the 50 mile area closure indefinitely. The Council would also review the status of the fishery every two years to determine whether the closure should be returned back to 50 nautical miles.
The order in which agenda items addressed may change. Public comment periods will be provided throughout the agenda and written comments will be accepted until March 7, 2008.
These meetings are physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aids should be directed to Kitty M. Simonds, (808)522-8220 (voice) or (808)522-8226 (fax), at least 5 days prior to the meeting date.
16 U.S.C. 1801
Corporation for National and Community Service.
Notice.
The Corporation for National and Community Service (hereinafter the “Corporation”), has submitted a public information collection request (ICR) entitled the Financial Management Survey (FMS) form 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). Copies of this ICR, with applicable supporting documentation, may be obtained by calling the Corporation for National and Community Service, Mrs. Stacy Bishop at (202) 606-6962. Individuals who use a telecommunications device for the deaf (TTY-TDD) may call (202) 565-2799 between 8:30 a.m. and 5 p.m. eastern time, Monday through Friday.
Comments may be submitted, identified by the title of the information collection activity, to the Office of Information and Regulatory Affairs, Attn: Ms. Katherine Astrich, OMB Desk Officer for the Corporation for National and Community Service, by any of the following two methods within 30 days from the date of publication in this
(1) By fax to: (202) 395-6974, Attention: Ms. Katherine Astrich, OMB Desk Officer for the Corporation for National and Community Service; and
(2) Electronically by e-mail to:
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 Corporation, 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;
• Propose ways to enhance the quality, utility, and clarity of the information to be collected; and
• Propose ways to 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, e.g., permitting electronic submissions of responses.
A 60-day public comment Notice was published in the
The Financial Management Survey (FMS) form must be completed as a pre-award assessment tool by potential grantees to address questions about its organization type, financial systems, funds management, and internal controls to administer federal funds properly. The FMS is used to ensure uniform consideration of the capacity of prospective grantees to manage federal funds and becomes the basis for determining the areas of the organization's financial and management systems that may warrant technical assistance.
Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Notice of request for an extension to an existing OMB clearance.
Under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), the Federal Acquisition Regulation (FAR) Secretariat has submitted to the Office of Management and Budget (OMB) a request to review and approve an extension of a currently approved information collection requirement concerning Buy American Act, Trade Agreements Act Certificate. A request for public comments was published in the
Public comments are particularly invited on: Whether this collection of information is necessary for the proper performance of functions of the FAR, and whether it will have practical utility; whether our estimate of the public burden of this collection of information is accurate, and based on valid assumptions and methodology; ways to enhance the quality, utility, and clarity of the information to be collected; and ways in which we can minimize the burden of the collection of information on those who are to respond, through the use of appropriate technological collection techniques or other forms of information technology.
Submit comments on or before March 10, 2008.
Submit comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden to: FAR Desk Officer, OMB, Room 10102, NEOB, Washington, DC 20503, and a copy to the General Services Administration, FAR Secretariat (VPR), 1800 F Street, NW., Room 4035, Washington, DC 20405.
Meredith Murphy, Contract Policy Division, GSA (202) 208-6925.
Under the Trade Agreements Act of 1979, unless specifically exempted by statute or regulation, agencies are required to evaluate offers over a certain dollar limitation not to supply an eligible product without regard to the restrictions of the Buy American program. Offerors identify excluded end products on this certificate.
The contracting officer uses the information to identify the offered items which are domestic end products. Items having components of unknown origin are considered to have been mined, produced, or manufactured outside the United States, a designated country, Caribbean Basin country or Free Trade Agreement Country.
Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Notice of request for an extension to an existing OMB clearance.
Under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), the Federal Acquisition Regulation (FAR) Secretariat has submitted to the Office of Management and Budget (OMB) a request to review and approve an extension of a currently approved information collection requirement concerning duty-free entry. A request for public comments was published in the
Public comments are particularly invited on: Whether this collection of information is necessary for the proper performance of functions of the FAR, and whether it will have practical utility; whether our estimate of the public burden of this collection of information is accurate, and based on valid assumptions and methodology; ways to enhance the quality, utility, and clarity of the information to be collected; and ways in which we can minimize the burden of the collection of information on those who are to respond, through the use of appropriate technological collection techniques or other forms of information technology.
Submit comments on or before March 10, 2008.
Submit comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden to: FAR Desk Officer, OMB, Room 10102, NEOB, Washington, DC 20503, and a copy to the General Services Administration, FAR Secretariat (VPR), 1800 F Street, NW., Room 4035, Washington, DC 20405.
Meredith Murphy, Contract Policy Division, GSA (202) 208-6925.
United States laws impose duties on foreign supplies imported into the customs territory of the United States. Certain exemptions from these duties are available to Government agencies. These exemptions are used whenever the anticipated savings outweigh the administrative costs associated with processing required documentation. When a Government contractor purchases foreign supplies, it must notify the contracting officer to determine whether the supplies should be duty-free. In addition, all shipping documents and containers must specify certain information to assure the duty-free entry of the supplies.
The contracting officer analyzes the information submitted by the contractor to determine whether or not supplies should enter the country duty-free. The information, the contracting officer's determination, and the U.S. Customs forms are placed in the contract file.
Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Notice of request for an extension to an existing OMB clearance.
Under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), the Federal Acquisition Regulation (FAR) Secretariat has submitted to the Office of Management and Budget (OMB) a request to review and approve an extension of a currently approved information collection requirement concerning Submission for OMB Review; Statement and Acknowledgment (Standard Form 1413). A request for public comments was published in the
Public comments are particularly invited on: Whether this collection of information is necessary for the proper performance of functions of the FAR, and whether it will have practical utility; whether our estimate of the public burden of this collection of information is accurate, and based on valid assumptions and methodology; ways to enhance the quality, utility, and clarity of the information to be collected; and ways in which we can minimize the burden of the collection of information on those who are to respond, through the use of appropriate technological collection techniques or other forms of information technology.
Submit comments on or before March 10, 2008.
Submit comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden to: FAR Desk Officer, OMB, Room 10102, NEOB, Washington, DC 20503, and a copy to the General Services Administration, FAR Secretariat (VPR), 1800 F Street, NW., Room 4035, Washington, DC 20405.
Mr. Ernest Woodson, Contract Policy Division, GSA (202) 501-3775.
Standard Form 1413, Statement and Acknowledgment, is used by all executive agencies, including the Department of Defense, to obtain a statement from contractors that the proper clauses have been included in subcontracts. The form includes a signed contractor acknowledgment of the inclusion of those clauses in the subcontract.
Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Notice of request for an extension to an existing OMB clearance.
Under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), the Federal Acquisition Regulation (FAR) Secretariat has submitted to the Office of Management and Budget (OMB) a request to review and approve an extension of a currently approved information collection requirement concerning Standard Form 28, Affidavit of Individual Surety. A request for public comments was published in the
Public comments are particularly invited on: Whether this collection of information is necessary for the proper performance of functions of the FAR, and whether it will have practical utility; whether our estimate of the public burden of this collection of information is accurate, and based on valid assumptions and methodology; ways to enhance the quality, utility, and clarity of the information to be collected; and ways in which we can minimize the burden of the collection of information on those who are to respond, through the use of appropriate technological collection techniques or other forms of information technology.
Submit comments on or before March 10, 2008.
Submit comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden to: FAR Desk Officer, OMB, Room 10102, NEOB, Washington, DC 20503, and a copy to the General Services Administration, FAR Secretariat (VPR), 1800 F Street, NW., Room 4035, Washington, DC 20405.
Mr. Edward Chambers, Contract Policy Division, GSA (202) 501-3221.
The Affidavit of Individual Surety (Standard Form (SF) 28) is used by all executive agencies, including the Department of Defense, to obtain information from individuals wishing to serve as sureties to Government bonds. To qualify as a surety on a Government bond, the individual must show a net worth not less than the penal amount of the bond on the SF 28. It is an elective decision on the part of the maker to use individual sureties instead of other available sources of surety or sureties for Government bonds. We are not aware if other formats exist for the collection of this information.
The information on SF 28 is used to assist the contracting officer in determining the acceptability of individuals proposed as sureties.
Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Notice of request for an extension to an existing OMB clearance.
Under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), the Federal Acquisition Regulation (FAR) Secretariat has submitted to the Office of Management and Budget (OMB) a request to review and approve an extension of a currently approved information collection requirement concerning certification of independent price determination and parent company and identifying data. A request for public comments was published in the
Public comments are particularly invited on: Whether this collection of information is necessary for the proper performance of functions of the FAR, and whether it will have practical utility; whether our estimate of the public burden of this collection of information is accurate, and based on valid assumptions and methodology; ways to enhance the quality, utility, and clarity of the information to be collected; and ways in which we can minimize the burden of the collection of information on those who are to respond, through the use of appropriate technological collection techniques or other forms of information technology.
Submit comments on or before March 10, 2008.
Submit comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden to: FAR Desk Officer, OMB, Room 10102, NEOB, Washington, DC 20503, and a copy to the General Services Administration, FAR Secretariat (VPR), 1800 F Street, NW., Room 4035, Washington, DC 20405.
Mr. Ernest Woodson, Contract Policy Division, GSA (202) 501-3775.
Agencies are required to report under 41 U.S.C. 252(d) and 10 U.S.C. 2305(d) suspected violations of the antitrust laws (
As a first step in assuring that Government contracts are not awarded to firms violating such laws, offerors on Government contracts must complete the certificate of independent price determination. An offer will not be considered for award where the certificate has been deleted or modified. Deletions or modifications of the certificate and suspected false certificates are reported to the Attorney General.
Department of Defense (DOD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Notice of request for an extension to an existing OMB clearance.
Under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), the Federal Acquisition Regulation (FAR) Secretariat has submitted to the Office of Management and Budget (OMB) a request to review and approve an extension of a currently approved information collection requirement concerning the Buy American Act Certificate. A request for public comments was published in the
Public comments are particularly invited on: Whether this collection of information is necessary for the proper performance of functions of the FAR, and whether it will have practical utility; whether our estimate of the public burden of this collection of information is accurate, and based on valid assumptions and methodology; ways to enhance the quality, utility, and clarity of the information to be collected; and ways in which we can minimize the burden of the collection of information on those who are to respond, through the use of appropriate technological collection techniques or other forms of information technology.
Submit comments on or before March 10, 2008.
Submit comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden to: FAR Desk Officer, OMB, Room 10102, NEOB, Washington, DC 20503, and a copy to the General Services Administration, FAR Secretariat (VPR), 1800 F Street, NW., Room 4035, Washington, DC 20405.
Meredith Murphy, Contract Policy Division, GSA (202) 208-6925.
The Buy American Act requires that only domestic end products be acquired for public use unless specifically authorized by statute or regulation, provided that the cost of the domestic products is reasonable.
The Buy American Act Certificate provides the contracting office with the information necessary to identify which products offered are domestic end products and which are of foreign origin. Components of unknown origin are considered to have been supplied from outside the United States.
Notice of Meeting of Air University Board of Visitors.
Under the provisions of the Federal Advisory Committee Act of 1972 (5 U.S.C., Appendix, as amended), the Government in the Sunshine Act of 1976 (5 U.S.C. 552b, as amended), and 41 CFR 102-3.150, the Department of Defense announces that the Air University Board of Visitors' meeting will take place on Monday, April 13th, 2008, from 8 a.m.-5 p.m., and Tuesday, April 14th, 2008, from 8 a.m.-5 p.m. in the Air University Commander's Conference Room, Headquarters Air University and again on Tuesday, 6 p.m.-8 p.m., at the Officers' Club, Maxwell Air Force Base, AL 36112.
The purpose of this meeting is to provide independent advice and recommendations on matters pertaining to the educational, doctrinal, and research policies and activities of Air University. The agenda will include topics relating to the policies, programs, and initiatives of Air University educational programs.
Pursuant to 5 U.S.C. 552b, as amended, and 41 CFR 102-3.155, all sessions of the Air University Board of Visitors' meeting will be open to the public. Any member of the public wishing to provide input to the Air University Board of Visitors should submit a written statement in accordance with 41 CFR 102-3.140(c) and section 10(a)(3) of the Federal Advisory Committee Act and the procedures described in this paragraph. Written statements can be submitted to the Designated Federal Officer at the address detailed below at any time. Statements being submitted in response to the agenda mentioned in this notice must be received by the Designated Federal Officer at the address listed below at least five calendar days prior to the meeting which is the subject of this notice. Written statements received after this date may not be provided to or considered by the Air University Board of Visitors until its next meeting. The Designated Federal Officer will review all timely submissions with the Air University Board of Visitors' Board Chairperson and ensure they are provided to members of the Board before the meeting that is the subject of this notice.
Dr. Dorothy Reed, Federal Designated Officer, Air University Headquarters, 55 LeMay Plaza South, Maxwell Air Force Base, Alabama 36112-6335, telephone (334) 953-5159 or Mrs. Diana Bunch, Alternate Federal Designated Officer, same address, telephone (334) 953-4547.
Department of Education.
The IC Clearance Official, Regulatory Information Management Services, Office of Management invites comments on the submission for OMB review as required by the Paperwork Reduction Act of 1995.
Interested persons are invited to submit comments on or before March 10, 2008.
Written comments should be addressed to the Office of Information and Regulatory Affairs, Attention: Education Desk Officer, Office of Management and Budget, 725 17th Street, NW., Room 10222, Washington, DC 20503. Commenters are encouraged to submit responses electronically by e-mail to
Section 3506 of the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 35) requires that the Office of Management and Budget (OMB) provide interested Federal agencies and the public an early opportunity to comment on information collection requests. OMB may amend or waive the requirement for public consultation to the extent that public participation in the approval process would defeat the purpose of the information collection, violate State or Federal law, or substantially interfere with any agency's ability to perform its statutory obligations. The IC Clearance Official, Regulatory Information Management Services, Office of Management, publishes that notice containing proposed information collection requests prior to submission of these requests to OMB. Each proposed information collection, grouped by office, contains the following: (1) Type of review requested, e.g., new, revision, extension, existing or reinstatement; (2) Title; (3) Summary of the collection; (4) Description of the need for, and proposed use of, the information; (5) Respondents and frequency of collection; and (6) Reporting and/or Recordkeeping burden. OMB invites public comment.
Requests for copies of the information collection submission for OMB review may be accessed from
Comments regarding burden and/or the collection activity requirements should be electronically mailed to
Department of Education.
The IC Clearance Official, Regulatory Information Management Services, Office of Management, invites comments on the proposed information collection requests as required by the Paperwork Reduction Act of 1995.
Interested persons are invited to submit comments on or before April 7, 2008.
Section 3506 of the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35) requires that the Office of Management and Budget (OMB) provide interested Federal agencies and the public an early opportunity to comment on information collection requests. OMB may amend or waive the requirement for public consultation to the extent that public participation in the approval process would defeat the purpose of the information collection, violate State or Federal law, or substantially interfere with any agency's ability to perform its statutory obligations. The IC Clearance Official, Regulatory Information Management Services, Office of Management, publishes that notice containing proposed information collection requests prior to submission of these requests to OMB. Each proposed information collection, grouped by office, contains the following: (1) Type of review requested, e.g., new, revision, extension, existing or reinstatement; (2) Title; (3) Summary of the collection; (4) Description of the need for, and proposed use of, the information; (5) Respondents and frequency of collection; and (6) Reporting and/or Recordkeeping burden. OMB invites public comment.
The Department of Education is especially interested in public comment addressing the following issues: (1) Is this collection necessary to the proper functions of the Department; (2) will this information be processed and used in a timely manner; (3) is the estimate of burden accurate; (4) how might the Department enhance the quality, utility, and clarity of the information to be collected; and (5) how might the Department minimize the burden of this collection on the respondents, including through the use of information technology.
Requests for copies of the proposed information collection request may be accessed from
Comments regarding burden and/or the collection activity requirements should be electronically mailed to
Department of Education.
The IC Clearance Official, Regulatory Information Management Services, Office of Management, invites comments on the proposed information collection requests as required by the Paperwork Reduction Act of 1995.
Interested persons are invited to submit comments on or before April 7, 2008.
Section 3506 of the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 35) requires that the Office of Management and Budget (OMB) provide interested Federal agencies and the public an early opportunity to comment on information collection requests. OMB may amend or waive the requirement for public consultation to the extent that public participation in the approval process would defeat the purpose of the information collection, violate State or Federal law, or substantially interfere with any agency's ability to perform its statutory obligations. The IC Clearance Official, Regulatory Information Management Services, Office of Management, publishes that notice containing proposed information collection requests prior to submission of these requests to OMB. Each proposed information collection, grouped by office, contains the following: (1) Type of review requested, e.g. new, revision, extension, existing or
The Department of Education is especially interested in public comment addressing the following issues: (1) Is this collection necessary to the proper functions of the Department; (2) will this information be processed and used in a timely manner; (3) is the estimate of burden accurate; (4) how might the Department enhance the quality, utility, and clarity of the information to be collected; and (5) how might the Department minimize the burden of this collection on the respondents, including through the use of information technology.
Requests for copies of the proposed information collection request may be accessed from
Comments regarding burden and/or the collection activity requirements should be electronically mailed to
United States Election Assistance Commission (EAC).
Notice of Public Meeting Roundtable Discussion.
Friday, February 29, 2008, 9 a.m.-2 p.m. (EST).
United State Election Assistance Commission, 1225 New York Ave., NW., Suite 150, Washington, DC 20005.
The Commission will host a voting systems manufacturer roundtable discussion regarding the Technical Guidelines Development Committee's (TGDC) recommended voluntary voting system guidelines (VVSG). The discussion will be focused upon the following topics: (1) The dominant business model for voting system manufacturers and their role as innovators; (2) How to evaluate innovative systems, for which there are no standards for purposes of certification; (3) The value and risks associated with Open Ended Vulnerability Testing; (4) The processes associated with testing to the VVSG and possible modifications; (5) Whether the recommend TGDC standards create appropriate functional standards that promote innovation; (6) The cost implications of the proposed VVSG; (7) Development of systems to the proposed VVSG and possible time frames.
This meeting will be open to the public.
Matthew Masterson, Telephone: (202) 566-3100.
Bonneville Power Administration (BPA), DOE.
Notice; request for comments (BPA File No.: ASCM-08).
Bonneville Power Administration (BPA) proposes a revised methodology for determining the average system cost (ASC) of resources for regional electric utilities that participate in the Residential Exchange Program (REP) authorized by section 5(c) of the Pacific Northwest Electric Power Planning and Conservation Act (Northwest Power Act). The ASC methodology is used in the determination of monetary benefits paid by BPA to utilities participating in the REP. The Northwest Power Act authorizes the BPA Administrator to determine utilities' ASCs based on a methodology developed by BPA in consultation with the Northwest Power and Conservation Council, BPA customers and state regulatory agencies in the Pacific Northwest. The existing methodology was adopted by BPA and approved by the Federal Energy Regulatory Commission (FERC or Commission) in 1984 (1984 ASC Methodology). On August 1, 2007, the Administrator initiated a series of public meetings in which informal comment was taken on 17 specific issues pertaining to the 1984 ASC Methodology. Based in part on public comment, the methodology proposed by BPA in this notice redefines the types of capital and expense items includable in ASC, establishes new data sources from which ASCs are to be derived, and changes the nature and timing of BPA's procedures for review of ASC filings by utilities participating in the REP. This notice also contains detailed procedures for public participation in the consultation proceeding.
This consultation proceeding is intended to facilitate the compilation of a full record upon which the Administrator will base his decision for a final ASC Methodology. Although preliminary informal comments have already been made by some groups and members of the public, this notice formally solicits public comment. With
In order to participate in the REP during FY 2009, a Pacific Northwest utility must notify BPA of its intent to participate by February 22, 2008. A utility also must submit an ASC filing (an Appendix 1) to BPA by March 3, 2008, or BPA will use the corresponding Appendix 1 from its WP-07 Supplemental Power Rate Adjustment Proceeding as the base filing to determine the utility's ASCs for FY 2009. During the comment period on the proposed ASC Methodology, interested parties will have the opportunity to participate in an expedited process for determining exchanging utilities' ASCs for FY 2009 based on the proposed methodology. In addition to the comments submitted, BPA expects to learn through this expedited process where improvements or changes to the proposed methodology can be made. Workshops will be held during the comment period to help facilitate feedback and explore different ideas. BPA strives to develop, in concert with the region, an ASC Methodology that will be legally sustainable, efficient, and durable over time.
Interested members of the public may make written comments between February 8, 2008, and May 2, 2008. Comments must be received by 5 p.m., Pacific Prevailing Time, on the specified date in order to be considered in the Record of Decision for the ASC Methodology, which will be submitted to FERC for interim and final approval. BPA will also post written comments online. Written comments may be made as follows: online at BPA's Web site:
Ms. Michelle Manary, Manager, Residential Exchange Program—FE-2, P.O. Box 3621, Portland, OR 97208. Ms. Leslie M. Dimitman, Paralegal Specialist, Office of General Counsel, LP-7, P.O. Box 3621, Portland, OR 97208. Interested persons may also call Ms. Dimitman at 503-230-5515, or the general BPA toll-free numbers 800-282-3713 (answered Monday through Friday 6:30 a.m. to 5 p.m.) or 866-879-2303 (answered by voice-mail).
Section 5(c)(1) of the Northwest Power Act, 16 U.S.C. 839c(c)(1), provides that BPA shall acquire certain amounts of power offered for sale to BPA by a Pacific Northwest electric utility at the average system cost of the utility's resources in each year. In exchange, BPA shall offer to sell “an equivalent amount of electric power to such utility for resale to that utility's residential users within the region.”
In contrast, the amount paid by BPA to the participating utility is not a conventional wholesale power rate. Section 5(c)(1) of the Northwest Power Act states that BPA is to pay “the average system cost of that [exchanging] utility's resources.” 16 U.S.C. 839c(c)(1). Section 5(c)(7) of the Northwest Power Act gives BPA's Administrator the discretionary authority to determine ASC on the basis of a methodology to be established in consultation proceedings. 16 U.S.C. 839c(c)(7). The only express statutory limits on the Administrator's authority are found in sections 5(c)(7)(A), (B) and (C) of the Act. 16 U.S.C. 839c(c)(7)(A), (B) and (C).
Generally, the BPA PF rate has been lower than participating utilities' ASCs under the 1984 ASC Methodology. The resulting monetary benefits BPA paid to participating utilities, or “net cost of the exchange,” is the second attribute of the REP. As noted above, the REP is not a conventional power transaction. System schedulers do not dispatch the exchange; line losses are not incurred. The power purchase and sale concept was created by Congress for BPA ratemaking purposes.
Furthermore, Northwest Power Act section 5(c)(4), 16 U.S.C. 839c(c)(4), recognizes that BPA's PF rate, insofar as it applies to the REP, may carry one or more “supplemental rate charges” after July 1, 1985, due to implementation of section 7(b)(3) of the Northwest Power Act. 16 U.S.C. 39e(b)(3). Were this to occur and cause the PF Exchange rate to exceed a participating utility's ASC, that utility has the statutory right to terminate its participation in the REP. 16 U.S.C. 839c(c)(4).
The monetary benefits of the REP must be passed through directly to the participating utilities' residential and small farm consumers in accordance with section 5(c)(3) of the Northwest Power Act, 16 U.S.C. 839c(c)(3), guarding against the possibility that the
The ASC methodology must also be designed so that BPA does not become the “deep pocket” to which participating utilities may shift excessive or improper resource costs. The ASC methodology should give participating utilities an incentive to minimize their costs. Otherwise, BPA may not be able to satisfy the requirement of section 7(a) of the Northwest Power Act that its rates recover its total revenue requirement. BPA is a self-financing government agency, which must recover its costs through rates for sales of electric power and energy.
The first ASC Methodology was developed in consultation with the region in 1981.
Prior to BPA's WP-02 power rate proceeding, BPA sought to resolve REP disputes by offering REP Settlement Agreements (Settlement Agreements) to regional investor-owned utilities. Under these Agreements, BPA would provide the participating utilities 1,000 aMW of actual power and 900 aMW of financial benefits for the FY 2002-2006 period, and 2,200 aMW of benefits for FY 2007-2011. Power sales were made at the Residential Load (RL) Firm Power Rate. Financial benefits were calculated based on the difference between BPA's RL rate and a forecast of market prices.
The Settlement Agreements were challenged in the U.S. Court of Appeals for the Ninth Circuit. On May 3, 2007, the Court held that the Settlement Agreements executed by BPA and the investor-owned utilities were inconsistent with the Northwest Power Act.
Under the 1984 ASC Methodology, utilities file with BPA “Appendix 1” forms containing cost information based on rate orders from state utility commissions or consumer-owned utility governing bodies. BPA reviews each Appendix 1 for conformance with criteria specified in the Methodology.
If BPA grants a request for oral argument, it is presented up to 180 days after a Utility files a new Appendix 1. BPA must issue a final determination on the revised Appendix 1 no later than 210 days after a Utility files a new Appendix 1.
Discovery is another component of the 1984 ASC Methodology. BPA can request data from a Utility any time during the 210-day review period. The Utility is required to respond within 30 days of receiving the data request. In addition, parties to the ASC review can submit data requests up to 40 days after the Utility files its revised Appendix 1. The Utility must respond within 65 days after the Utility files its revised Appendix 1.
Consumer-owned utilities may execute RPSAs for participation in the REP. Because consumer-owned utilities are not regulated by the state commissions in the Pacific Northwest, and because they are not required to make FERC Form 1 filings, preparation and review of ASC filings is more burdensome for all parties concerned. The difficulty in the preparation and review of ASC filings has been a major cause of disputes between BPA and participating consumer-owned utilities and became one of the issues leading BPA and the consumer-owned utilities to settle out their REP participation in the late 1980s.
The reliance on state regulatory agencies to determine the level of costs included in the ASC of a participating Utility under the 1984 ASC Methodology, known as the “jurisdictional costing approach,” has resulted in a long, burdensome, expensive and often contentious review process that many BPA customers said could be improved and streamlined. The 210-day review period for each ASC filing under the current methodology means that BPA and its customers are almost always reviewing an ASC filing. Given the tremendous advancement in information and communication technology (ICT) since the early 1990s, the review process and implementation costs can be reduced substantially through use of electronic filings, e-mail and other aspects of ICT without changing the existing ASC Methodology. However, BPA believes that further efficiencies in the ASC filing and review process could be obtained if BPA were to adopt a new
One issue related to the “jurisdictional costing approach” that has not changed since REP disputes were addressed through settlements is the volume of utility rate orders. Because any commission-ordered change in retail rates triggers a new ASC filing under the 1984 ASC Methodology, BPA and its customers could be faced with requirements to review several ASC filings a year for each investor-owned utility participating in the REP because of adjustment clauses and tracker filings in each state where the Utility provides retail electric service to customers.
BPA is mindful of the difficulty in preparing ASC filings for consumer-owned utilities that may want to participate in the REP and hopes that the proposed methodology will ease the burden of preparing and reviewing Appendix 1 filings.
This consultation proceeding is intended to facilitate the compilation of a full record upon which the Administrator will base the decision to establish the ASC Methodology. Preliminary informal comments have already been submitted by groups, including investor-owned utilities, state regulatory agencies and consumer-owned utility customers. This notice solicits a new round of formal comments from interested members of the public.
Interested members of the public may make written comments between February 8, 2008 and May 2, 2008. Comments must be received by 5 p.m., Pacific Prevailing Time, on the specified date in order to be considered in the Record of Decision for the ASC Methodology. BPA will also post written comments online. Written comments may be made as follows: Online at BPA's Web site:
After the written comment stage, an opportunity will be provided for oral presentations before the Administrator, which will be transcribed for inclusion in the record. The date, time, and location of oral presentations will be specified in a future communication. Only those persons who participate in the written comment stage of the consultation will have the option of making an oral presentation before the Administrator. During any stage of the proceeding, negotiated resolutions of issues raised by BPA or by commenters may be incorporated into the record by means of written stipulations.
After completion of the foregoing proceedings, the Administrator will issue a Record of Decision on the revised ASC Methodology. The revised ASC Methodology will then be submitted to the Federal Energy Regulatory Commission for review and approval.
The revised methodology proposed by BPA in this notice is intended to implement the Northwest Power Act, help alleviate the administrative burden and expense associated with the jurisdictional approach to ASC determinations, and to reflect changes in the organization and operation of the electric utility industry since the 1984 ASC Methodology was approved. In preparing this proposal, BPA took into account the issues and concerns raised by parties during workshops held in August through November of 2007. Although BPA is proposing a number of broad changes to the 1984 ASC Methodology, the proposal is not a complete reconstruction of the previous 1984 ASC Methodology. Several portions of the proposal reflect features from the 1984 ASC Methodology that remain viable in today's environment.
BPA anticipates that there will be a wide variety of comments on the proposed ASC Methodology, and also expects that comments will raise issues that may not have been apparent to BPA. BPA stresses the importance of written comments that precisely state each commenter's position on issues of concern, whether the comments be positive or negative, so that a complete record can be compiled. Numerical analyses and examples will be of particular assistance to BPA in developing a revised ASC Methodology. BPA also welcomes negotiations and possible settlements of issues.
Both the 1981 and 1984 ASC Methodologies used the jurisdictional costing approach for ASC determinations. As noted above, using the jurisdictional cost approach as the data source for the ASC calculations has proven to be inefficient, cumbersome, and extremely contentious. BPA therefore is proposing to not use a jurisdictional costing approach for the revised ASC Methodology. In its place, BPA is proposing to use a data source that is uniform and that facilitates ease of administration for all parties. Such data can be found for investor-owned utilities in the FERC Form No. 1 (Form 1), a compilation of financial and operating information prepared annually in accordance with the Commission's Uniform System of Accounts for Public Utilities and Licensees.
Under the proposed ASC Methodology, the Utility may include in its ASC only actual costs documented in its Form 1 or equivalent, with limited exceptions. These exceptions include the following: First, equity return for investor-owned utilities will be determined in accordance with procedures described later in this notice; second, Federal income taxes will be included at the marginal Federal income tax rate; third, the Form 1 does not always contain enough information or level of detail to allow BPA to determine whether costs are includable in ASC, thus requiring supplemental information; and fourth, BPA will require utilities that do not file a Form 1 with FERC to submit audited financial data in a format comparable to the Form 1 and a detailed cost of service analysis prepared by an independent accounting or consulting firm, approved by the Utility's Regulatory Body
BPA is proposing an approach for determining a utility's ASC that is aimed at simplicity, transparency and minimal administrative burden for all parties. BPA recognizes this may make it difficult to reflect unique circumstances of individual utilities, which may have an impact on their ASCs. BPA is open to different types of approaches and welcomes such suggestions during the comment period.
BPA proposes to review each Utility's filed ASC in a simplified administrative process. This process will commence during the period prior to BPA filing an initial proposal for a change in wholesale power rates, referred to as the Review Period. An investor-owned utility would submit a “base period ASC” to BPA using data from the prior year's Form 1 on or before May 1 of each year. For Utilities not required to submit a Form 1 to FERC, the base period ASC would be determined from a filing similar in format to a Form 1. The Utility's base period ASC will be projected by BPA to determine the ASC for the BPA rate period.
Proposed changes to established ASCs would only be allowed under two specific conditions. First, the ASC may be adjusted in the event a Utility acquires a new service territory or relinquishes all or a portion of its service territory. A second adjustment may be made to account for major new resource additions, purchases, retirements or sales. In the event that a Utility has a resource that is projected to come on-line or be purchased and used to meet that Utility's retail regional load during the BPA rate period, the Utility will submit two ASC filings: (1) One conforming to the Form 1 described above, and (2) a second filing that incorporates the costs associated with the new resource based on the expected commercial operation date of the new resource or, for resource purchases, the date the sale is completed and the costs associated with the purchased resource used to meet that utility's regional retail load. In addition to including the estimated capital and operating costs of the new resource, the Utility must also estimate the changes in purchased power expense, sales for resale credit and other costs based on the additional generation provided by the new resource. Because the commercial on-line dates of power plants often change during the construction process, BPA will not adjust the Utility's ASC until the new generating resource begins commercial operation.
For a major resource used to meet the Utility's regional retail load that is projected to be unable to serve load, retired or sold during the BPA rate period, BPA proposes that the Utility make two ASC filings: (1) One conforming to the Form 1 described above, and (2) a second filing that excludes the costs associated with the retired or sold resource based on the expected retirement or closing date of the resource. In addition to including the reduction in estimated capital and operating costs of the retired or sold resource, the Utility must also estimate the changes in purchased power expense, sales for resale credit and other costs based on the generation formerly provided by the retired or sold resource. BPA proposes not to adjust the Utility's ASC until the official retirement or transfer date of the generating resource.
BPA proposes that all Utilities be required to submit ASC filings using BPA's electronic template (Appendix 1)
BPA envisions that this approach will reduce the time, administrative burden and cost to BPA, the Utility, other BPA customers and other interested parties without significantly affecting the accuracy of the ASC determination when compared to the more cumbersome process required under the 1984 ASC Methodology. BPA proposes that ASC determinations prior to BPA's rate cases will replace the multiple determinations in each year required under the 1984 ASC Methodology for each jurisdiction in which a Utility provides retail residential service upon each change in retail rates.
The revised ASC Methodology has characteristics similar to ratemaking based on an historical test year incorporating end-of-year data. Each Utility would be permitted to include the same types of costs in ASC based on actual data from the same calendar-year period. It is uniform in contrast to the 1984 ASC Methodology, which relied on data from retail rate proceedings throughout the Northwest, each using different ratemaking methodologies and test years.
Although the numbers included in Form 1 accounts by Utilities will help expedite ASC reviews, Utilities' ASC filings will continue to be scrutinized by BPA, its customers and other participants in the ASC review process. BPA has a statutory responsibility to ensure that all improper costs are excluded from ASCs. Each ASC filing must contain a statement, signed by a senior officer of the Utility, stating that all data submitted by the Utility were compiled in strict compliance with the Commission's Uniform System of Accounts, the ASC Methodology, and Generally Accepted Accounting Principles, and are consistent with applicable orders and policies of their Regulatory Body. For Utilities not required to submit a Form 1, the attestation will state that the data were compiled in strict compliance with the Utility's financial statements, the ASC Methodology, and policies and orders from the Utility's Regulatory Body. BPA proposes that any filing that does not contain this attestation will not be accepted by BPA for determination of an ASC.
BPA invites and welcomes comments on alternative sources of verifiable data for use in determining ASC. Such comments should contain detailed explanations of the verification safeguards inherent in any proposed alternative as well as procedural alternatives.
BPA hopes to begin the implementation of the REP for eligible utilities on October 1, 2008. To do so, BPA must negotiate and execute new RPSAs with Utilities, establish a revised ASC Methodology, and establish ASCs under the revised Methodology. As noted below, BPA also intends to implement the proposed ASC Methodology in an expedited ASC review during the spring of 2008 in order to identify any problems that might arise in implementing the Methodology. The results of the expedited ASC review will be used as a starting point for the determination of final ASCs for FY 2009. The expedited
After publication of the proposed ASC Methodology, a Utility intending to participate in the REP beginning October 1, 2008, must notify BPA of its intent by February 22, 2008. If a Utility fails to notify BPA of its intent to participate in the REP in FY 2009 by February 29, 2008, the Utility will be ineligible to receive any REP benefits during the FY 2009 rate period. A Utility must file its Appendix 1 based on the proposed ASC Methodology with BPA by March 3, 2008. If it fails to do so, BPA will rely on the Appendix 1 for the Utility included by BPA in its WP-07 Supplemental Rate Proposal to determine ASCs for FY 2009. BPA will provide electronic access to the Appendix 1 filings on March 4, 2008, to all Regional Power Sales Customers and other interested parties. BPA will review all Appendix 1 filings concurrently in an expedited public process. Interested parties will have the opportunity to intervene in BPA's review. Petitions to intervene must be filed with BPA by March 11, 2008. Data requests must be submitted by March 14, 2008. BPA will commence discovery workshops on all Appendix 1 filings on March 26, 2008. BPA and parties will address and resolve all discovery issues in the workshops. BPA and parties may electronically file an issue list identifying and providing full arguments regarding the contested elements of a Utility's Appendix 1 filing by April 10, 2008. The Utility will electronically file, and other parties may file, a response to the issue lists on April 24, 2008. A second workshop will be held on April 29, 2008, to discuss and resolve, to the extent possible, the identified issues. BPA will then review the parties' arguments, rule on such issues, and publish and electronically serve all parties with a Draft ASC Reports on May 9, 2008. The Utility and parties may file comments on the Draft ASC Reports by May 23, 2008. After reviewing the comments, the BPA Administrator will issue Final ASC Reports on June 6, 2008.
After BPA develops the final proposed ASC Methodology, BPA will file the Methodology with FERC for confirmation and approval. BPA hopes to receive interim approval of the Methodology on or around September 1, 2008. After FERC approval, BPA proposes to review the ASC determinations resulting from the expedited ASC review. BPA will compare the proposed ASC Methodology provisions with the FERC-approved Methodology. If there are no differences between the data included in the Utilities' initial Appendix 1s (or the Appendix 1 filings developed by BPA for the WP-07 Supplemental Rate Proposal) and the Appendix 1s to be filed under the final Methodology, the Utilities' initial Appendix 1s (or the default WP-07 Supplemental Appendix 1s) can be used for the Utilities' final ASC determinations. If the Appendix 1s are the same but the substantive criteria of the Methodology have changed from the initial proposed Methodology, BPA will recalculate each Utility's ASC by reviewing the initial Appendix 1 and applying the final Methodology criteria. Because the Utility's initial Appendix 1 will have been reviewed in the expedited review, BPA will conduct an abbreviated review with all interested parties to ensure that the Utilities' ASCs comply with the FERC-approved Methodology. If BPA determines that the ASCs comply, BPA will establish the ASCs as the Utilities' final ASCs for FY 2009.
BPA also must plan for the establishment of each Utility's ASC for FY 2010-2011. Under the proposed ASC Methodology, except for the initial one-year Exchange Period under the revised Methodology, and the second Exchange Period for FY 2010-2011, a Utility must file an Appendix 1 by May 1 of each year. If a Utility wishes to participate in the REP in the second Exchange Period for FY 2010-2011, it must file an Appendix 1 using 2007 data by July 1, 2008. If a Utility fails to file an Appendix 1 by July 1, 2008, the Utility will receive no REP benefits for the FY 2010-2011 period. After receiving all exchanging Utilities' Appendix 1s by July 1, 2008, BPA will promptly publish a schedule for review of the filings. Although BPA hopes to complete this review using the ASC review schedule contained in the ASC Methodology, BPA may issue a schedule different from the prescribed schedule in order to ensure that ASCs for FY 2010-2011 are established in time to be incorporated in BPA's FY 2010-2011 wholesale power rate initial proposal. After completing its ASC review process, BPA will establish ASCs for FY 2010-2011. If FERC approval of the ASC Methodology is subsequent to this ASC review, BPA will compare the Methodology used to calculate the ASCs with the FERC-approved Methodology. BPA will conduct an abbreviated ASC review will all interested parties to ensure that Utilities' ASCs comply with the final Methodology. If BPA determines that the ASCs comply, BPA will establish the ASCs as the Utilities' final ASCs for FY 2010-2011.
Although not a part of the ASC Methodology, BPA proposes to continue the contractual requirement that Utilities invoice BPA monthly based on actual eligible residential and small farm loads. A Utility's monthly REP payment is determined by subtracting the Utility's BPA PF Exchange Rate
Transmission investments and expenses were included in ASCs under BPA's 1981 ASC Methodology. The 1981 ASC Methodology was established pursuant to a negotiated settlement, agreed to by all parties. The Administrator's 1981 ASC Methodology Decision, at 1-2, explains the process by which most issues, including the propriety of adding transmission costs to ASC, were resolved through a negotiated settlement in the first consultation proceeding. The Commission granted final approval to the 1981 ASC Methodology on October 17, 1983.
In the 1984 ASC Methodology, BPA included “all existing transmission, as defined in the Commission Uniform System of Accounts, in service as of July 1, 1984 * * *” and “[f]or transmission plant commencing service after July 1, 1984, transmission plant costs that can be exchanged are limited to transmission facilities that are directly required to integrate resources to the transmission grid.”
Even though the 1984 ASC Methodology allowed all transmission prior to 1984 but only a portion of it after 1984, upon further consideration BPA believes transmission should be included in the calculation of utilities' ASCs. One of the main reasons for this conclusion is that the exclusion of the transmission component of electricity production and delivery may introduce an inequity between Utilities that develop resources close to their service territory and those that develop geographically distant resources. Therefore, BPA proposes that the cost of resources should include all costs associated with the delivery of power to the Utility's load centers.
Furthermore, since implementation of the 1984 ASC Methodology and its approval by the Commission, the electric utility industry has undergone significant changes in structure, specifically, the development of wholesale power markets, creation of regional transmission organizations (RTOs) and the separation of generation and transmission functions of vertically integrated electric utilities mandated by Commission Order 888, which was issued in 1996. In 1999, BPA administratively separated its power and transmission functions to voluntarily comply with the Commission's order for investor-owned utilities to separate generation and transmission. Consequently, BPA now develops separate rates for power and transmission.
As a result of this change in industry structure, electric utilities have a variety of ways to acquire generation to serve their retail load. For example, utilities can: (1) Rely on wholesale power markets; (2) build centralized generation units close to the fuel source; or (3) build the generation close to the load center and transport the fuel source (e.g. coal by rail). In addition, many large power plants are owned by more than one utility. This diversity in the method of acquiring electric generating capacity to serve retail load means that excluding transmission costs from the ASC calculation would have adverse effects on Utilities. Exclusion of the transmission component of electricity production and delivery would introduce an inequity between Utilities that develop resources close to their service territory and those that develop geographically distant resources. In summary, BPA proposes that the cost of resources should include the cost of transmission used to deliver resources to retail load.
In the 1984 ASC Methodology, the Administrator determined which conservation costs could be included in ASCs. The determinations “were case specific, based on the information provided by exchanging utilities.”
BPA proposes to continue with the 1984 ASC Methodology's exclusion of advertising and promotion costs, except that the revised Methodology will allow Utilities to include the cost of energy audits. BPA proposes to allow energy audits because the only way to determine if a conservation program or measure will be cost effective is through an analysis or “audit” of the facility where the conservation measure will be installed. Some items such as energy efficient light bulbs are cost effective in almost any location. Others, like insulation, energy efficient windows or HVAC upgrade/replacements must be analyzed in advance to see if the measure is cost effective. In many ways, the audit is a form of or extension to the Utility's least-cost plan. If the audit is not done before the measure is installed, the funds could be used on a measure that is not cost effective. For this reason, BPA believes it is reasonable to allow the costs of audits in the ASC calculation.
Oregon's Public Purpose Charge (OPPC) was established in 1999 with passage of Oregon's electricity restructuring law, Senate Bill 1149.
The OPPC was implemented on March 1, 2002, for PGE and PacifiCorp-Oregon, and in 2006 for Idaho Power-Oregon. Distribution of the OPPC funds are made monthly by the utilities to the following organizations in the following percentages:
PGE, PacifiCorp and Idaho Power do not show the OPPC on their financial statements or Form 1s. The utilities treat the revenue and expense as a direct pass-through. Accounting records are available from the utilities showing the revenue received and the payments made to the three recipient organizations. SB 1149 states that the OPPC funds be allocated in the following manner:
The 1981 and the 1984 ASC Methodologies did not address the cost treatment of charges like the OPPC. A key attribute of the OPPC has been that it effectively replaces the Utility's conservation program, which is typically included as part of a Utility's base rates. Because of this unique feature, BPA proposes that the OPPC is an alternative form of acquiring conservation and renewable resources, and therefore should be considered in determining ASC. In the same way that some utilities build thermal resources and others purchase power from the market, BPA proposes that the OPPC is a similar method of acquiring conservation and renewable resources. Another way of looking at the OPPC is as an outsourcing arrangement. While some utilities have their own conservation departments and programs, Oregon investor-owned utilities are effectively required to “outsource” their conservation activities to the ETO, OHCS and ESDs. BPA needs to have the right to review and audit the costs and programs of the organizations that receive OPPC funds in order to
In the
The 1984 ASC Methodology did not allow ROE in ASCs, but instead permitted the inclusion of the Utility's long-term cost of debt. BPA now proposes that ROE should be allowable in ASC. The cost of debt is a cost of resources and, in the case of investor-owned utilities, the cost of debt is lowered by the contribution of equity by the company. Without the spreading of risk to shareholders there would be a significant increase in the cost of debt. State commissions and rating agencies require investor-owned utilities to maintain specific capital structures that affect the company's debt ratings. Therefore, debt alone is not an adequate reflection of the capital cost of a Utility's resources. Without an equity component in the cost of capital, a higher cost of debt is needed to reflect the true cost of financing resources.
BPA finds that enough changes have occurred in the PNW regulatory environment to reasonably ensure that terminated plant costs will not be included with allowable costs under the ASC Methodology. First, the costs of the Pebble Springs nuclear plant that were the basis of the terminated plant controversy in the mid-1980s have been completely written off by the utilities involved. Second, Oregon's establishment of a three-person appointed public utility commission greatly reduces the chance of improper communications between the Oregon PUC and utilities. Third, since 1984, Oregon has had a Citizens' Utility Board (CUB), which monitors the retail rate development of utilities conducting business in Oregon. CUB reviews retail rates in order to ensure, among other things, that terminated plant costs are excluded from such rates. Additionally, increased disclosure and filing requirements at the commission level make identifying inappropriate costs much easier. All four state commissions now have requirements that utilities under their review prepare Integrated Resource Plans. From these filings, BPA and its customers can likely determine if a Utility included the costs of terminated plant in its equity calculation. Thus, the risk that Regulatory Bodies will include inappropriate costs in the ROE has diminished significantly since 1984.
Because of these changes, and based on BPA's experience in implementing the ASC, BPA now proposes that Utilities should be allowed to exchange ROE. In the revised ASC Methodology, BPA is proposing to allow return on equity as determined by the Regulatory Bodies at a Utility's most recent commission-approved level. For purposes of determining return on rate base, the Utility will include the weighted cost of capital from its most recent rate order. For Utilities with service territories in more than one state, the Utility shall submit a weighted cost of capital based on the most recent Regulatory Body rate orders weighted by rate base in states within the PNW region.
In the 1984 ASC Methodology, BPA did not allow the inclusion of Federal income taxes in ASC. BPA's rationale stated that “nothing in the [Northwest Power] Act or its legislative history requires the inclusion or exclusion of income taxes in computing the average system cost of a Utility's resources.”
Under the revised ASC Methodology, BPA is proposing to allow Utilities to exchange the costs of certain taxes through their ASCs. BPA is proposing this change because it is necessary to have symmetry between its treatment of ROE and taxes. As noted above, BPA is proposing to allow the costs associated with equity return as a resource cost in calculation of ASC. If the cost of Federal income taxes at the marginal tax rate is not also included, then an investor-owned utility's cost of resources would be understated. When calculating the revenue requirement for an investor-owned utility, Regulatory Bodies typically gross up the cost of equity by the marginal Federal income tax rate to arrive at the “after tax” return. In the same manner, because BPA is proposing to include ROE as a resource cost in the ASC Methodology, BPA is also proposing to gross up the equity component by the Federal income tax rate when determining an investor-owned utility's weighted cost of capital in ASC.
Regulatory assets and liabilities are expenses, revenues, gains or losses that would normally be recognized in net income in one period, but for an order of a Regulatory Body specifying a different recovery period in retail rates. Regulatory Assets and Liabilities, Accounts 182.3 and 254 in the Commission Uniform System of Accounts, were established in March 1993 in Commission Order No. 552,
For investor-owned utilities located in the Pacific Northwest, regulatory assets and liabilities are a significant portion of the balance sheet. Examples of costs and revenues that can be deferred and included as a regulatory asset or liability with Regulatory Body approval include: fuel costs subject to a power cost adjustment, storm damage, gains on reacquired debt, deferred compensation plans, stranded costs, phase-in plans, deferred income taxes, asset retirement obligations, asset impairment or disposal under Financial Accounting Standards Board 144, rate case expenses and intervenor funding, buyout costs for non-utility generation, deferred purchase capacity costs, deferred demand-side management costs, U.S. Department of Energy (USDOE) nuclear fuel enrichment clean-up fees, deferred revenue related to income taxes associated with allowance for funds used during construction (AFUDC), unamortized loss on reacquired debt, and deferred return on sales of emission allowances. The above list is only representative of the deferred costs and revenues that would be found in a typical Form No.1 or a Regulatory Body rate or accounting order.
There are three major issues for the revised ASC Methodology relating to treatment of regulatory assets and liabilities. First, how should regulatory assets and regulatory liabilities be functionalized between production, transmission, and distribution? Second, for the production-related assets and liabilities, what rate of return, if any, should the Utility earn on these items for purposes of determining a Utility's ASC? And finally, how should the amortization of regulatory assets and liabilities be handled in the ASC review process?
Functionalization of regulatory assets and liabilities raises several problems because of the lack of information contained in the Form 1 concerning the nature of these items. Descriptions of regulatory assets and liabilities are cryptic at best. Some of the deferred costs are of a short-term nature, such as power costs, which may be carried as a deferral for a matter of months. Other costs may be deferred and amortized 5 years or more, such as costs associated with storm damage and conservation. The Form 1 provides little or no detail on the length of the deferral period for each item. Nor does it provide information on whether the deferred assets and liabilities are included in rate base by the Utility's Regulatory Body. A brief review of several regional Regulatory Body rate orders revealed few references to regulatory assets in the list of items included in rate base. Finally, the Commission's Uniform System of Accounts does not provide specific rules for amortization of regulatory assets. Review of the Utilities' Form 1 filings reveal that some utilities amortize regulatory assets and liabilities to Accounts 407.3, Regulatory Debits and 407.4, Regulatory Credits, while others amortize regulatory assets and liabilities to specific income or expense accounts. For these reasons, BPA proposes that Utilities must perform a direct analysis and functionalize all regulatory assets and liabilities to Production, Transmission, or Distribution/Other. The Utility must provide documentation supporting its rationale for functionalization of the regulatory asset or liability. This documentation must consist of general ledger entries, a description of the item in sufficient detail to permit BPA to determine the functional nature of the cost, and all communications on the asset or liability between the Utility, its Regulatory Body and its external auditor. The documentation must also show that the asset or liability is included in the Utility's calculation of rate base approved by its Regulatory Body and the allowed return or carrying cost. In no case will the amount of regulatory assets and liabilities allowed in ASC exceed the amount included in retail rates for the same period by the regional Regulatory Bodies.
Cash Working Capital (CWC) is a component in almost all Regulatory Body determinations of rate base. Inclusion of CWC as an element of rate base is consistent with the principle that investors receive a fair return on investment that is used, useful and devoted to public service. One definition of CWC as used in regulatory proceedings is:
The average amount of capital provided by investors, over and above the investment in plant and other specifically measured rate base items, to bridge the gap between the time expenditures are required to provide services and the time collections are received for such services.
Because the 1981 and 1984 Methodologies relied on the jurisdictional approach, CWC was a part of the Utilities' rate base calculation in Regulatory Body rate orders. The 1981 and 1984 Methodologies simply set an upper limit on the amount of CWC included in rate base for the ASC calculation.
Because the revised ASC Methodology proposes to use the Form 1 (which does not include a CWC value) as the basis for data for ASC filings, BPA believes it is important to include a separate determined value for CWC in the Utility's rate base calculation for ASC purposes. While determination of the proper amount of CWC in rate base is often very controversial, a standard and widely accepted measure is one-eighth of total O&M costs, less fuel and purchase power costs.
BPA is proposing to use this formula—one-eighth of total exchangeable O&M costs, less fuel and purchase power costs—for the CWC value included in the Appendix 1 filing. The details are shown in Schedule 1A of the revised ASC Methodology template.
Under the 1981 and 1984 ASC Methodologies, BPA used a jurisdictional approach to determining a Utility's ASC. For Avista, Idaho and PacifiCorp, Utilities that serve retail customers in more than one state, reliance on Regulatory Body rate orders for ASC determinations resulted in separate ASC filings for each state. Developing ASCs by state for multi-jurisdictional Utilities presents problems for those utilities because Form 1 filings are prepared on a total utility basis, and trying to separate and allocate the costs from the total system to individual states would be burdensome and expensive for both the Utility and BPA. For this proposal, BPA proposes to develop a single ASC for each Utility. Because PacifiCorp has service territories that are outside the Pacific Northwest region, it will be required to submit an ASC filing based on an allocation of its in-region resources and costs, based on the individual state results of operations
Purchased power and sales for resale are subject to significant variability for a number of reasons including:
Regulatory Bodies use a process called normalization to adjust quantity and price for purchased power and sales for resale in regulatory proceedings. Normalization of purchased power and sales for resale credits is a process used by utilities and Regulatory Bodies to adjust actual data to reflect what would likely occur under conditions (water, weather, market prices) that are closer to long-term averages. For this reason, BPA proposes to generally use a rolling 5-year average of short-term (less than 1 year) energy sales and energy purchases in the Appendix 1. For pricing, BPA proposes to use the same models and methodologies used to develop market price forecasts in BPA's wholesale power rate filings.
BPA understands this area is not simple, and its treatment can have a big impact on hydro-intensive utilities. BPA welcomes different approaches and ideas on how to account for the significant variability in this area.
BPA and its customers are currently discussing the design of a Tiered Rates Methodology (TRM) for BPA's future wholesale power rates. BPA expects to conduct a hearing under section 7(i) of the Northwest Power Act in 2008 in order to establish a TRM, which would be implemented in the rate period beginning FY 2012. The establishment of the TRM may affect the implementation of the REP for consumer-owned utilities. For example, BPA may propose as part of the TRM that a consumer-owned utility that elects to receive an individual Contract High Water Mark will have an ASC that excludes costs of any resources added by the utility after September 30, 2006. Other REP-related proposals and issues will undoubtedly be raised in connection with the TRM. Consequently, BPA has included placeholder language in the Proposed Revised Average System Cost Methodology that the Methodology will be revised if necessary or appropriate to accommodate establishment and implementation of tiered rates.
The Proposed Revised Average System Cost Methodology, Functionalization for Average System Cost Methodology, Endnotes and the Proposed Average System Cost template are incorporated herein by reference and are available at the following link:
In consideration of the foregoing discussion, BPA proposes to revise the Average System Cost Methodology as set forth below.
Bonneville Power Administration (BPA), Department of Energy (DOE).
Notice of Wind Integration—Within-Hour Balancing Service Rate (Notice), BPA Docket No. WI-09.
The purpose of the hearing is to adopt a rate for Wind Integration—Within-Hour Balancing Service. As increasing amounts of wind generation have integrated into BPA's Balancing Authority, the variability and uncertainty of wind generation have led to increased costs through the need for additional reserve capacity, the shift of energy generation from heavy load hours to light load hours, and reduced system efficiency. The Wind Integration—Within-Hour Balancing Service rate will ensure that these costs are borne by the parties causing the costs.
Persons wishing to intervene and become parties in the rate case must file a petition to intervene by 5 p.m., Pacific Standard Time, on February 13, 2008. The petition must state the name and address of the intervenor and the intervenor's interest in the outcome of the proceeding. Written comments by non-party participants must be received by BPA no later than April 15, 2008, to be considered in the Record of Decision (“ROD”). The Administrator will issue a Final Record of Decision in these proceedings by July 28, 2008.
Petitions to intervene should be directed to Brandon Hignite, Hearing Clerk—2009 Wind Integration Rate Case, L-7, Bonneville Power Administration, 905 NE 11th Avenue, Portland, OR 97232 or by e-mail to:
Mr. Elliot E. Mainzer, Transmission Policy and Strategy Manager, at (360) 619-6252.
Section 7 of the Northwest Power Act, 16 U.S.C. 839e, sets forth a number of general directives that the BPA Administrator must consider in establishing rates for the sale of electric energy and capacity and transmission services. In particular, section 7(a)(1), 16 U.S.C. 839e(a)(1), provides in part that “[s]uch rates shall be established and, as appropriate, revised to recover, in accordance with sound business principles, the costs associated with the acquisition, conservation, and transmission of electric power, including the amortization of the Federal investment in the Federal Columbia River Power System (FCRPS) (including irrigation costs required to be repaid out of power revenues) over a reasonable period of years and the other costs and expenses incurred by the
Rates established by BPA are effective on an interim or final basis as approved by FERC. 16 U.S.C. 839e(a)(2). In addition to the Northwest Power Act, BPA ratemaking is governed by the Bonneville Project Act, 16 U.S.C. 832,
Section 7(i) of the Northwest Power Act, 16 U.S.C., 839e(i), requires that BPA's rates be set according to certain procedures, including issuance of a
The hearing will be conducted under the rule for general rate proceedings, section 1010.9 of the Procedures Governing Bonneville Power Administration Rate Hearings. The following proposed schedule is provided for informational purposes. A final schedule will be established by the Hearing Officer at the prehearing conference.
Section 1010.7 of the BPA Hearing Procedures prohibits
The purpose of the hearing is to adopt a rate for Wind Integration—Within-Hour Balancing Service. As increasing amounts of wind generation have integrated into BPA's transmission system, the variability and uncertainty of wind generation have led to increased costs through the need for additional reserve capacity, the shift of energy generation from heavy load hours to light load hours, and reduced system efficiency. The Wind Integration—Within-Hour Balancing Service Rate is intended to ensure that these costs are borne by the parties causing the costs.
Pursuant to Rule 1010.3(f) of BPA's Procedures, the Administrator limits the scope of this hearing to issues concerning the rate for Wind Integration—Within-Hour Balancing Service described in Part IV hereof. In particular, the following issues are not part of the scope of the case, and the Hearing Officer is directed to strike all testimony contesting these issues: how BPA operates the FCRPS to provide control area services and ancillary services; how or from which entities BPA's transmission business obtains capacity to provide any such services; program levels and program level forecasts for any BPA program; and rates previously established or to be established in any other rate case, including BPA's WP-07 Supplemental Wholesale Power Rate Case.
BPA is in the process of assessing the potential environmental effects of the Wind Integration Within-Hour Balancing Service rate, consistent with the National Environmental Policy Act (“NEPA”). The NEPA process is conducted separately from BPA's formal rate proceedings. Therefore, the Administrator directs the Hearing Officer to exclude from the record all evidence and argument that seek in any way to address the potential environmental impacts of the rates being developed in the 2009 Wind Integration—Within-Hour Balancing Service Rate Case.
BPA's Business Plan Environmental Impact Statement (“Business Plan EIS”), completed in June 1995, evaluated the environmental impacts of a range of business plan alternatives that could be varied by applying various policy modules, including one for rates. Any combination of alternative policy modules should allow BPA to balance its costs and revenues. The Business Plan EIS also addressed response strategies, including adjusting rates that BPA could pursue if BPA's costs exceeded its revenues.
In August 1995, the BPA Administrator issued a Record of Decision (“Business Plan ROD”) that adopted the Market-Driven Alternative from the Business Plan EIS. This alternative was selected because, among other reasons, it allows BPA to: (1) Recover costs through rates; (2) competitively market BPA's products and services; (3) develop rates that meet customer needs for clarity and simplicity; (4) continue to meet BPA's legal mandates; and (5) avoid adverse
In April 2007, BPA completed and issued a Supplement Analysis to the Business Plan EIS. The Supplement Analysis found that the Business Plan EIS's relationship-based and policy-level analysis of potential environmental impacts from BPA's business practices remains valid, and that BPA's current business practices remain consistent with BPA's Market-Driven approach. The Business Plan EIS and ROD thus continue to provide a sound basis for making determinations under NEPA concerning BPA's policy-level decisions, including rates.
Because the Wind Integration rate proposal likely would assist BPA in accomplishing the goals identified in the Business Plan ROD, the proposal appears consistent with these aspects of the Market-Driven Alternative. In addition, this rate proposal is similar to the type of rate designs and resulting rate levels evaluated in the Business Plan EIS; thus implementation of this rate proposal would not be expected to result in significantly different environmental impacts from those examined in the Business Plan EIS. Therefore, BPA expects that this rate proposal will fall within the scope of the Market-Driven Alternative that was evaluated in the Business Plan EIS and adopted in the Business Plan ROD.
As part of the Administrator's Record of Decision that will be prepared regarding the Wind Integration—Within-Hour Balancing Service rate, BPA may tier its decision under NEPA to the Business Plan ROD. However, depending upon the ongoing environmental review, BPA may, instead, issue another appropriate NEPA document. Persons may submit comments regarding the potential environmental effects of the proposal to Katherine Pierce, NEPA Compliance Officer, KEC-4, Bonneville Power Administration, 905 NE. 11th Avenue, Portland, OR 97232. Any such comments received by the comment deadline in Part III.A above will be considered by BPA's NEPA compliance staff in the NEPA process that will be conducted for this proposal.
BPA distinguishes between participants in and parties to the hearings. Apart from the formal hearing process, BPA will accept comments, views, opinions, and information from participants, who are defined in the BPA Procedures as persons who may submit comments without being subject to the duties of, or having the privileges of, parties. Participants are not entitled to participate in the prehearing conference; may not cross examine parties' witnesses, seek discovery, or serve or be served with documents; and are not subject to the same procedural requirements as parties.
Participants' written and oral comments will be made part of the official record and considered by the Administrator, if they are submitted on or before April 15, 2008. Participants' written views, supporting information, questions, and arguments should be submitted to the address noted in the
The second category of interest is that of a party as defined in Rules 1010.2 and 1010.4 of the BPA Procedures. 51 Fed. Reg. 7611 (1986). Parties may participate in any aspect of the hearing process.
Persons wishing to become parties to BPA's rate proceeding must notify BPA in writing of their interest by submitting a petition to intervene. Petitions to intervene are due to the Hearing Officer by February 13, 2008, and should be directed to Brandon Hignite, Hearing Clerk, L-7, Bonneville Power Administration, 905 NE. 11th Avenue, Portland, OR 97232 or by e-mail to:
Petitions shall state the name and address of the person requesting party status and the person's interest in the hearing. Petitioners must explain their interests in sufficient detail to permit the Hearing Officer to determine whether they have a relevant interest in the hearing. Pursuant to Rule 1010.1(d) of BPA's Procedures, BPA waives the requirement in Rule 1010.4(d) that an opposition to an intervention petition be filed and served 24 hours before the prehearing conference. Any opposition to an intervention petition may instead be made at the prehearing conference. Any party, including BPA, may oppose a petition for intervention. All timely applications will be ruled on by the Hearing Officer. Late interventions are strongly disfavored. Opposition to an untimely petition to intervene shall be filed and received by BPA within two days after service of the petition.
The record will include, among other things, the testimony and evidence submitted by the parties, the transcripts of any hearings and cross-examination, written material submitted by the participants, and evidence accepted into the record by the Hearing Officer. The Hearing Officer will review the record and certify the record to the Administrator for decision. Parties will have the opportunity to file initial briefs at the close of cross-examination. After the close of the hearings, and following submission of initial briefs, BPA will issue a draft ROD that states the Administrator's preliminary decision(s). Parties may file briefs on exceptions, after that the Administrator will issue the final ROD establishing the rate.
The Administrator will develop the final rate for Wind Integration—Within-Hour Balancing Service based on the entire record. The Administrator will serve copies of the final Record of Decision on all parties and will file the final proposed rate, together with the record, with FERC for confirmation and approval.
In 2006 BPA and the Northwest Power and Conservation Council convened a regional forum to discuss the operational and economic issues raised by the expected integration of significant amounts of wind generation into the Pacific Northwest power system. In March 2007 the group, which included investor-owned utilities, public power organizations, environmental groups, and others, produced the Northwest Wind Integration Action Plan. The Action Plan recognized that the emergence of wind energy as a significant resource on the Northwest transmission grid—which has 17 separate Balancing Authorities—raised new cost recovery and cost allocation issues.
Historically, most of the variability and uncertainty in a Balancing Authority's operations has been caused by loads. As a result, most Northwest transmission providers do not have rate schedules that charge generators for the variability they add to the system. However, the output of wind generators is significantly more variable and uncertain than the output of traditional generation sources. The variability and uncertainty associated with wind generation increases the demand for reserves required to maintain Balancing Authority reliability.
Under current rate schedules, BPA power customers pay most of the costs of these additional reserves. For BPA, wind integration cost recovery is a particularly important issue because the majority of the 1,425 MW of wind generation in the BPA Balancing Authority is exported to other Balancing Authorities to serve the loads of other regional utilities. Therefore, BPA power customers are paying the costs of providing balancing services for wind generation used to serve other loads. This pattern of large-scale exports of wind generation is expected to continue through the end of 2009, at which point BPA expects that 2,880 MW of wind will be interconnected to the BPA system.
To better align cost causation and cost allocation, BPA is proposing a Wind Integration—Within-Hour Balancing Service rate under which wind generators will be charged for the costs of the additional reserve capacity that is needed to support their operations, as well as other incremental costs caused by the variability of wind generation. Additional costs are caused by the need to shift energy generation from heavy load hours to light load hours to preserve the ability to change generation levels to compensate as wind output changes and by reduced efficiency because demands on the system become less predictable as wind generation increases. The new rate is intended to ensure that BPA recovers the costs that wind generation places on the system, and that the costs are allocated to the parties that cause the costs.
BPA currently estimates that, during FY 2009, it will need an average of 203 MW of capacity to provide these balancing services for wind generation. Therefore, BPA is proposing a wind integration rate to recover the embedded costs of 203 MW of Federal system resources plus the other costs, noted above, that wind generation places on the system.
BPA projects the cost of providing this service is $22.9 million. To recover this cost, BPA is proposing a rate not to exceed $0.81 per installed kW of wind capacity per month.
The proposed rate schedule is attached at the end of this Notice.
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Control Area Service rates available under this rate schedule are:
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5. Wind Integration—-Within-Hour Balancing Service
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E. WIND INTEGRATION—WITHIN-HOUR BALANCING SERVICE
The rate below applies to all wind plants in the BPA Control Area. Within-Hour Balancing Service provides the generation capability to follow within-hour variations of wind resources in the BPA Control Area and to maintain the power system frequency at 60 Hz in conformance with NERC and WECC reliability standards.
1. RATE
The rate shall not exceed $0.81 per kilowatt per month.
2. BILLING FACTOR
The Billing Factor is as follows:
i. For each wind plant, or phase of a wind plant, that has completed installation of all units no later than the 15th day of the month prior to the billing month, the billing factor will be the nameplate of the plant in kW. A unit has completed installation when it has generated and delivered power to the BPA system.
ii. For each wind plant, or phase of a wind plant, for which some but not all units have been installed by the 15th day of the month prior to the billing month, the billing factor will be the maximum measured hourly output of the plant through the 15th day of the prior month in kW.
Take notice that the following hydroelectric application has been filed with the Commission and is available for public inspection:
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All documents (original and eight copies) should be filed with: Secretary, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426.
The Commission's Rules of Practice and Procedure require all interveners filing documents with the Commission to serve a copy of that document on each person whose name appears on 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 document on that resource agency. A copy of any motion to intervene must also be served upon each representative of the Applicant specified in the particular application.
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m. Individuals desiring to be included on the Commission's mailing list should so indicate by writing to the Secretary of the Commission.
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o. Any filings must bear in all capital letters the title “COMMENTS”, “PROTEST”, or “MOTION TO INTERVENE”, as applicable, and the Project Number of the particular application to which the filing refers.
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q. 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 at
Take notice that the Commission received the following electric rate filings:
Take notice that the Commission received the following electric securities 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 docket(s). For assistance with any FERC Online service, please e-mail
On January 23, 2008, a technical conference was held in this proceeding on the issue of master limited partnership growth rates.
Take notice that on January 23, 2008, Trunkline Gas Company, LLC (Trunkline), P. O. Box 4967, Houston, Texas 77210-4967, filed in Docket No. CP08-61-000, a prior notice request pursuant to sections 157.205, 157.210, and 157.216 of the Federal Energy Regulatory Commission's regulations under the Natural Gas Act for authorization to relocate an existing interconnect with Enbridge Pipeline (East Texas) L.P. (Enbridge), located in Hardin County, Texas, and increase the certificated capacity of Trunkline's North Texas transmission system by 40 MMcf/d, all as more fully set forth in the application, which is on file with the Commission and open to public inspection. The filing may also be viewed on the Web at
Specifically, Trunkline proposes to relocate the Enbridge Pipeline (East Texas) L.P. Meter Station from its current location at Trunkline's existing Kountze Compressor Station, located in Kountze, Hardin County, Texas, to a new location near Silsbee, Hardin County, Texas. Trunkline states that the relocation will increase the certificated capacity of Trunkline's North Texas transmission system expansion facilities by 40 MMcf/d. Trunkline asserts that the increase in capacity will benefit Trunkline's shippers. Trunkline declares that it will be able to receive, and, at the same time, Enbridge will be able to increase the volumes of natural gas being delivered to Trunkline for further transportation to natural gas markets. Trunkline proposes to relocate the Enbridge facilities located at the Kountze Compressor Station approximately 15 miles east and install and own two 12-inch hot tap assemblies on existing 24-inch Lines 100-1 and 100-2, and install a 16-inch above-grade valve that will function as the overpressure protection device and RTU. Trunkline estimates the cost to relocate the meter station to be $983,040.
Any questions regarding the application should be directed to Stephen T. Veatch, Regulatory Affairs, Trunkline Gas Company, LLC, 5444 Westheimer Road, Houston Texas 77056, call (713) 989-2024, fax (713) 989-1158, or by e-mail
Any person or the Commission's Staff may, within 60 days after the issuance of the instant notice by the Commission, file pursuant to Rule 214 of the Commission's Procedural Rules (18 CFR 385.214) a motion to intervene or notice of intervention and, pursuant to section 157.205 of the Commission's Regulations under the Natural Gas Act (NGA) (18 CFR 157.205) a protest to the request. If no protest is filed within the time allowed therefore, the proposed activity shall be deemed to be authorized effective the day after the time allowed for protest. If a protest is filed and not withdrawn within 30 days after the time allowed for filing a protest, the instant request shall be treated as an application for authorization pursuant to section 7 of the NGA.
The Commission strongly encourages electronic filings of comments, protests, and interventions via the Internet in lieu of paper. See 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's Web site (
Environmental Protection Agency (EPA).
Notice of Proposed Settlement Agreement; Request for Public Comment.
In accordance with section 113(g) of the Clean Air Act, as amended (“Act”), 42 U.S.C. 7413(g), notice is hereby given of a proposed settlement agreement, to address a lawsuit filed by the Battery Council International (“BCI”) in the United States Court of Appeals for the District of Columbia Circuit:
Written comments on the proposed settlement agreement must be received by March 10, 2008.
Submit your comments, identified by Docket ID number EPA-HQ-OGC-2008-0076, online at
Paul Versace, Air and Radiation Law Office (2344A), Office of General Counsel, U.S. Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone: (202) 564-0219; fax number (202) 564-5603; e-mail address:
Battery Council International (BCI) filed a petition for review of the rules applicable to Lead Acid Battery Manufacturing on September 13, 2007. BCI raised issues regarding the scope of the performance test requirement in Subpart PPPPPP, 40 CFR 63.11423(c)(1) of the Battery NESHAP.
The settlement agreement provides that within three days after the agreement is executed BCI and EPA will jointly notify the Court of this settlement agreement and request that the case continue to be held in abeyance. The settlement agreement states that EPA shall sign a notice of proposed rulemaking and/or direct final rulemaking that contains a technical amendment to the Battery NESHAP that is substantially the same in substance as set forth in Attachment A. If EPA signs and thereafter publishes in the
For a period of thirty (30) days following the date of publication of this notice, the Agency will receive written comments relating to the proposed settlement agreement. EPA or the Department of Justice may withdraw or withhold consent to the proposed settlement agreement if the comments disclose facts or considerations that indicate that such consent is inappropriate, improper, inadequate, or inconsistent with the requirements of the Act. Unless EPA or the Department of Justice determines, based on any comment which may be submitted, that consent to the settlement agreement should be withdrawn, the terms of the agreement will be affirmed.
Direct your comments to the official public docket for this action under Docket ID No. EPA-HQ-OGC-2008-0076, which contains a copy of the settlement agreement. The official public docket is available for public viewing at the Office of Environmental Information (OEI) Docket in the EPA Docket Center, EPA West, Room 3334, 1301 Constitution Ave., NW., Washington, DC. The EPA Docket Center Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the OEI Docket is (202) 566-1752.
An electronic version of the public docket is available through
It is important to note that EPA's policy is that public comments, whether submitted electronically or in paper, will be made available for public viewing online at
You may submit comments as provided in the
If you submit an electronic comment, EPA recommends that you include your name, mailing address, and an e-mail address or other contact information in the body of your comment and with any disk or CD ROM you submit. This ensures that you can be identified as the submitter of the comment and allows EPA to contact you in case EPA cannot read your comment due to technical difficulties or needs further information on the substance of your comment. Any identifying or contact information provided in the body of a comment will be included as part of the comment that is placed in the official public docket, and made available in EPA's electronic public docket. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment.
Use of the
The Federal Communications Commission, as part of its continuing effort to reduce paperwork burdens, invites the general public and other Federal agencies to take this opportunity to comment on (PRA) of 1995 (PRA), Public Law No. 104-13. An agency may not conduct or sponsor a collection of information unless it displays a currently valid control number. Subject to the PRA, no person shall be subject to any penalty for failing to comply with a collection of information that does not display a valid control number. Comments are requested concerning (a) whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; (b) the accuracy of the Commission's burden estimate; (c) ways to enhance the quality, utility, and clarity of the information collected; and (d) ways to minimize the burden of the collection of information on the respondents, including the use of automated collection techniques or other forms of information technology.
Written PRA comments should be submitted on or before April 7, 2008. If you anticipate that you will be submitting comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the contact listed below as soon as possible.
You may submit all PRA comments by e-mail or U.S. post mail. To submit your comments by e-mail, send them to
For additional information about the information collection(s), contact Cathy Williams at (202) 418-2918 or send an e-mail to
Specifically, the Report and Order requires the following:
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The Commission hereby gives notice of the filing of the following agreements under the Shipping Act of 1984. Interested parties may submit comments on agreements to the Secretary, Federal Maritime Commission, Washington, DC 20573, within ten days of the date this notice appears in the
By Order of the Federal Maritime Commission.
Notice is hereby given that the following applicants have filed with the Federal Maritime Commission an application for license as a Non-Vessel Operating Common Carrier and Ocean Freight Forwarder—Ocean Transportation Intermediary pursuant to section 19 of the Shipping Act of 1984 as amended (46 U.S.C. Chapter 409 and 46 CFR part 515).
Persons knowing of any reason why the following applicants should not receive a license are requested to contact the Office of Transportation Intermediaries, Federal Maritime Commission, Washington, DC 20573.
Office of Governmentwide Policy, General Services Administration (GSA).
Notice.
The General Services Administration (GSA) is announcing the 2008 Travel and Relocation Innovation Award. This award will recognize masters of travel and/or relocation management.
Go to GSA's 2008 Travel and Relocation Innovation Award at
The Federal Travel Regulation is contained in Title, 41 Code of Federal Regulations (14 CFR Chapters 300 through 304), and implements statutory requirements and executive branch policies for travel and relocation by Federal civilian employees and others authorized to travel and relocate at Government expense.
GSA announces an award to recognize and honor excellence in Federal travel and relocation. This award, available to all Federal employees, will honor individuals and/or teams. In addition to cash awards, one or more entries may receive honorable mention. Entries must be received no later than March 31, 2008.
Announcement and presentation of winners will be at the National Travel Forum 2008 (June 3-6, 2008; Atlanta, GA;
Office of Governmentwide Policy, General Services Administration (GSA).
Notice of a bulletin.
This notice announces GSA Federal Management Regulation (FMR) Bulletin B-17 which provides guidance to Federal agencies to maximize the use and benefits of property throughout the asset management lifecycle and to explain how those benefits are extended to the public. GSA Bulletin FMR B-17 may be found at
The bulletin announced in this notice is effective January 29, 2008.
For clarification of content, contact General Services Administration, Office of Governmentwide Policy, Office of Travel, Transportation and Asset Management, at (202) 501-1777. Please cite Bulletin FMR B-17.
Section 521 of Title 40 of the United States Code ( 40 U.S.C. 521) and General Services Administration (GSA) policies require the maximum use of excess property by executive agencies, and provide for the transfer of excess property to other Federal agencies and eligible recipients. In addition, section 524 of Title 40 United States Code (40 U.S.C. 524) and Federal Management Regulation (FMR) section 102-36.45 (41 CFR 102-36.45) require that the agencies perform care and handling of excess property. Maintaining the utility of property protects the Government's investment in that property and saves Federal agencies and taxpayers valuable resources by avoiding the need to acquire new property.
This notice announces GSA Bulletin FMR B-17 which provides guidance to Federal agencies to maximize the use and benefits of property throughout the asset management lifecycle and to explain how those benefits are extended to the public.
Bulletins regarding asset management are located on the Internet at
The Centers for Disease Control and Prevention (CDC) publishes a list of information collection requests under review by the Office of Management and Budget (OMB) in compliance with the Paperwork Reduction Act (44 U.S.C. Chapter 35). To request a copy of these requests, call the CDC Reports Clearance Officer at (404) 639-5960 or send an e-mail to
Preventive Medicine Residency and Fellowship Program Evaluation—New—Office of Workforce and Career Development (OWCD), Centers for Disease Control and Prevention (CDC).
Preventive medicine is a specialized field of medical practice that works with large populations to promote good health; to prevent disease, injury and disability; and to facilitate early diagnosis and treatment of illness. It is unique because its central focus is population health. Despite the nation's growing need for preventive-medicine skills, numerous studies have demonstrated an increasing shortage of preventive medicine-trained professionals, and that shortage is projected to continue (American College of Preventive Medicine; Council on Graduate Medical Education). The specialty will benefit from attracting new residents, rewarding programs that fill positions with highly qualified candidates, and expanding the specialty into new medical leadership roles (Ducatman, et al., 2005).
The mission of CDC's Preventive Medicine Residency and Fellowship (PMR/F) is to (1) train public health and preventive medicine leaders, and (2) maintain leadership in the field of preventive medicine training. CDC's PMR/F has been training physicians in the residency since 1972 and veterinarians in the fellowship since 1983. PMR/F consists of a competency-based curriculum, a one-year practicum, and sponsorship for a Master of Public Health degree for qualified applicants before the practicum year. PMR/F provides its residents and fellows with training and experience in leadership, management, program development and evaluation, and the translation of epidemiology to public health practice.
During the past 15 years, the CDC PMR/F has adapted its educational plan and design in response to changing public health needs, feedback from trainees and stakeholders, internal reviews of the residency, changes in Accreditation Council for Graduate Medical Education (ACGME) requirements, and a formal national survey of Preventive Medicine Residency graduates conducted by CDC in 1991. The last formal evaluation of the program occurred as part of the 1991 survey.
CDC proposes a new project to evaluate the PMR/F. The goals of the evaluation are to determine: (1) How well PMR/F is fulfilling its mission to train competent public health practitioners and leaders, (2) the effectiveness of the PMR/F educational program, and (3) PMR/F's contribution to its residents and fellows, the CDC, and the larger public health community.
As part of this project, PMR/F practicum alumni and a matched group of physicians and veterinarians who were eligible to apply to PMR/F will be asked to complete a questionnaire to provide information that addresses the evaluation's goals. Below is a description of the questionnaire's response burden.
There is no cost to the respondents other than their time. The estimated annualized burden hours are 16.
The Centers for Disease Control and Prevention (CDC) publishes a list of information collection requests under review by the Office of Management and Budget (OMB) in compliance with the Paperwork Reduction Act (44 U.S.C. Chapter 35). To request a copy of these requests, call the CDC Reports Clearance Officer at (404) 639-5960 or send an email to
Report of Verified Case of Tuberculosis (RVCT), (OMB No. 0920-0026)—Revision—National Center for HIV/AIDS, Viral Hepatitis, STD, and TB Prevention (NCHHSTP), Centers for Disease Control and Prevention (CDC).
In the United States, an estimated 10 to 15 million people are infected with
Data are collected by 60 reporting areas (the 50 states, the District of Columbia, New York City, Puerto Rico, and 7 jurisdictions in the Pacific and Caribbean). CDC's Division of Tuberculosis Elimination (DTBE) has revised the Report of Verified Case of Tuberculosis (RVCT) data collection instrument, which has been in use since 1993. The increase in burden hours is due to the addition of information on new clinical diagnostic tests and factors to identify high-risk patients. The revision captures changes in the diagnosis and treatment of TB, and improves the monitoring of trends in TB epidemiology and outbreaks and support CDC in developing strategies to meet the national goal of TB elimination.
In 2001, DTBE initiated a comprehensive review of the RVCT with stakeholders and partner organizations. This review resulted in the revision of the data collection form in 2007.
The reporting areas use and analyze their RVCT data to monitor local TB trends, evaluate program success, and focus resources to eliminate TB. CDC uses the RVCT data to monitor national trends by demographics, risk, and region. These summaries are published annually in CDC-sponsored publications, journals, and are submitted as Agency reports to the Congress.
CDC is requesting approval for approximately 8050 burden hours, an estimated increase of 490 hours. There is no cost to respondents other than their time. The total estimated annualized burden hours are 8050.
DSEHS is a longitudinal study of a representative sample of programs and children in three age cohorts, which will collect information about programs, families, and services. When completed, data will be collected on a sample of approximately 2,100 children and families from 60 EHS programs. Data will be collected in four waves: Fall 2008, Fall 2009, Fall 2010, and Fall 2011. Children and families will be followed until children are three years old and exit EHS programs.
Data collected under DSEHS will complement information gathered under the Survey of Early Head Start Programs (SEHSP), OMB Control No. 0992-0008. SEHSP gathered information on the management systems, services, and characteristics of children and families served by EHS programs. To complement this information, DSEHS will gather information on the needs and characteristics of children and families enrolled in EHS programs, including an assessment of children's and families' needs, how programs meet the needs of children and families in EHS programs, and how children and families in EHS programs progress over time.
The activity proposed under this notice includes only the data collected during the selection and recruitment of programs to participate in DSEHS and a pilot study on the feasibility of proposed measures.
To select and recruit programs, ACF intends to send letters to program directors of selected EHS programs. Directors will receive a summary of the study goals that will include an overview of the design and data collection, a brochure describing the study, and examples of the consent materials for enrolling study participants. Programs will not be asked to enroll participants during the initial selection and recruitment phase.
Selected programs may also receive a follow-up phone call to answer questions from EHS directors or staff. Program directors will be asked to provide information on the numbers of families enrolled with children who will be within two months of the target ages at the time of each of the four fall data collections.
ACF intends to conduct a feasibility pilot study at two EHS programs in June 2008. In the pilot study, ACF will test the feasibility of administering various direct child assessment measures and parent interviews.
Estimated Total Annual Burden Hours: 125.
Copies of the proposed collection may be obtained by writing to the Administration for Children and Families, Office of Administration, Office of Information Services, 370 L'Enfant Promenade, SW., Washington, DC 20447, Attn: ACF Reports Clearance Officer. All requests should be identified by the title of the information collection. E-mail address:
OMB is required to make a decision concerning the collection of information between 30 and 60 days after publication of this document in the
In compliance with the requirements of Section 506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Administration for Children and Families is soliciting public comment on the specific aspects of the infromation collection described above. Copies of the proposed collection of infromation can be obtained and comments may be forwared by writing to the Administration for Children and Families, Office of Administration, Office of Information Services, 370 L'Enfant Promenade, SW., Washington, DC 20447, Attn: ACF Reports Clearance Officer. E-mail address:
The Department specifically requests comments on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the proposed collection of information; (c) the quality, utility, and clarity of the information to be collected; and (d) ways to minimze the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology. Consideration will be given to comments and suggestions submitted within 60 days of this publication.
CWIG is a service of the Children's Bureau, a component within the Administration for Children and Families, and CWIG is dedicated to the mission of connecting professionals and concerned citizens to information on programs, research, legislation, and statistics regarding the safety, permanency, and well-being of children and families. CWIG's main functions are identifying information needs, locating and acquiring information, creating information, organizing and storing information, disseminating information, and facilitating information exchange among professionals and concerned citizens. A number of vehicles are employed to accomplish these activities, including, but not limited to, Web site hosting, discussions with customers, and dissemination of publications (both print and electronic).
The Customer Satisfaction Evaluation was initiated in response to Executive Order 12862 issued on September 11, 1993. The order calls for putting customers first and striving for a customer-driven government that matches or exceeds the best service available in the private sector.
To that end, CWIG's evaluation is designed to better understand the kind and quality of services customers want, as well as customers' level of satisfaction with existing services. The proposed data collection activities for the evaluation include customer satisfaction surveys, customer comment cards, selected publication surveys, and focus groups.
Estimated Total Annual Burden Hours: 174.1.
Copies of the proposed collection may be obtained by writing to the Administration for Children and Families, Office of Administration, Office of Information Services, 370 L'Enfant Promenade, SW., Washington, DC 20447, Attn: ACF Reports Clearance Officer. All requests should be identified by the title of the information collection. E-mail address:
OMB is required to make a decision concerning the collection of information between 30 and 60 days after publication of this document in the
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing the availability of the draft Compliance Policy Guide (CPG) Sec. 555.320
Although you can comment on any guidance at any time (see 21 CFR 10.115(g)(5)), to ensure that the agency considers your comment on this draft guidance before it begins work on the final version of the guidance, submit written or electronic comments on the draft guidance by April 7, 2008.
Submit written comments on the draft CPG to the Division of Dockets Management (HFA-305), Food and Drug Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852. Submit electronic comments to
Submit written requests for single copies of the draft CPG to the Division of Compliance Policy (HFC-230), Office of Enforcement, Food and Drug Administration, 5600 Fishers Lane, Rockville, MD 20857. Send two self-addressed adhesive labels to assist that office in processing your request, or fax your request to 240-632-6861. See the
Mary Losikoff, Center for Food Safety and Applied Nutrition (HFS-325), Food and Drug Administration, 5100 Paint Branch Pkwy., College Park, MD 20740, 301-436-1412.
The draft CPG is intended to provide clear policy and regulatory guidance for FDA staff regarding
For RTE foods that support the growth of
Further discussion of FDA's current thinking on
The draft CPG is being issued as a Level 1 draft guidance consistent with FDA's good guidance practices regulation (21 CFR 10.115). The draft CPG, when final, will represent the agency's current thinking on
Interested persons may submit to the Division of Dockets Management (see
Please note that on January 15, 2008, the FDA Web site transitioned to the Federal Dockets Management System (FDMS). FDMS is a Government-wide, electronic docket management system. Electronic submissions will be accepted by FDA through the FDMS only.
Persons with access to the Internet may obtain the draft CPG from the Office of Regulatory Affairs home page. It may be accessed at
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing the availability of the draft guidance entitled “Guidance for Industry: Control of
Although you can comment on any guidance at any time (see 21 CFR 10.115(g)(5)), to ensure that the agency considers your comment on this draft
Submit written requests for single copies of the draft guidance entitled “Guidance for Industry: Control of
Submit written comments on the draft guidance and the proposed collection of information provisions to the Division of Dockets Management (HFA-305), Food and Drug Administration, 5630 Fishers Lane, rm. 1061, Rockville, MD 20852. Submit electronic comments to
With this notice, FDA is announcing the availability of the draft
This draft guidance contains information collection provisions that are subject to review by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995 (the PRA) (44 U.S.C 3501-3520). Under the PRA, Federal agencies must obtain approval from the OMB for each collection of information they conduct or sponsor. “Collection of information” is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c) and includes agency requests or requirements that members of the public submit reports, keep records, or provide information to a third party. Section 3506(c)(2)(A) of the PRA (44 U.S.C. 3506(c)(2)(A)) requires Federal agencies to provide a 60-day notice in the
FDA invites comments on these topics: (1) Whether the proposed collection of information is necessary for the proper performance of FDA's functions, including whether the information will have practical utility; (2) the accuracy of FDA'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 on respondents, including through the use of automated collection techniques, when appropriate, and other forms of information technology.
FDA's draft
In order to minimize
• List of ingredients reasonably likely to be contaminated with
• Listeristatic or listericidal control measures
• Ingredient control records, i.e. certificate of conformance (COC), certificate of analysis (COA)
• Ingredient testing records
• Written sanitation standard operating procedures (SSOP)
• Sanitation monitoring records
• Written plan for monitoring
• Procedures to detect and enumerate
• Results of tests to detect or enumerate
• Results of tests to detect or enumerate
• Corrective actions taken
FDA estimates the burden of this collection of information as follows:
The estimated recurring annual burden for this information collection is 863,974 hours. Thus, the first year estimated burden for this information collection is 939,242 hours (863,974 hours + 75,268 first-year-only hours). A detailed breakdown of the estimated burden is shown in table 1 of this document.
Data for the number of establishments potentially affected by this guidance were obtained from U.S. Census Bureau's 2003 “County Business Patterns.” Including grocery stores, delicatessens, and retail establishments that might perform some sort of RF-RTE food processing would bring the number of affected establishments to over 100,000. However, FDA anticipates this guidance would be used mainly by firms that are primarily RF-RTE food processors and manufacturers. Overall, there are 4,270 RF-RTE food processors and manufacturers that might be affected by this guidance. Liquid milk producers account for 515 of the establishments, and are already regulated by each state individually through the adoption of the Pasteurized Milk Ordinance (PMO). FDA assumes that milk producers would refer to the PMO for guidance in production and therefore would only be collecting or maintaining new information for general sanitation and on environmental monitoring and product sampling. There are currently 34 butter manufacturers, 408 ice cream manufacturers, 514 cheese manufacturers, and 501 ice manufacturers in the United States. There are 643 producers of perishable foods (including sandwiches, salads, and fresh-cut vegetables).
The draft guidance recommends that establishments keep a list of ingredients likely to be contaminated with
Plants employing either a listericidal or listeristatic step would be recommended to maintain documentation of scientific studies that demonstrate that the control measure consistently destroys viable cells or is effective in preventing the growth of
Based on these assumptions, there will be roughly 2,629 establishments (0.70 x 3,755) that would be recommended to keep a new record showing the efficacy of their listericidal step. Although the time taken to commit the verification to record will vary, FDA estimates that, on average, it will take about 1 hour for the documentation.
Under the draft guidance, listeristatic control measures fall into two categories: Those that are generally recognized as effective in preventing the growth of
As stated, the draft guidance recommends that processors of RF-RTE foods select one or more identified measures to control ingredients. The recommended measures to control ingredients that may be adopted by firms expected to collect new records include: Eliminating
For firms that choose to eliminate
Under the recommendations in the draft guidance, firms may instead choose to test ingredients for
Firms may choose to add a listeristatic step in addition to the COC, COA, or ingredient testing. FDA recommends in the draft guidance that records of listeristatic control measures be kept on a daily basis per lot, either per ingredient lot or per final product lot. FDA assumes that, similar to listericidal control records, listeristatic control records can be treated as a daily collection for each product, taking approximately 6 minutes. FDA does not have information to predict how many establishments would employ a listeristatic step. For this analysis, FDA estimates that about 10 percent of the affected establishments (376 establishments) would collect the information for an average of 3 products. These records would produce a total annual burden of about 33,840 hours ((376 plants) x (3 products) x (300 days of production) x (0.1 hours)).
In the draft guidance, FDA is recommending that firms have written SSOPs. FDA assumes this is a new collection for 4,270 establishments. Developing written SSOPs would be a one-time cost and we assume that this would take approximately 8 hours. This results in a first year burden of 34,160 hours (4,270 plants x 8 hours). The guidance also recommends that firms have written sanitation monitoring records. As stated previously, establishments subject to FDA's HACCP regulations are already required to have sanitation monitoring records, in order in order to comply with those regulations. However, because these records may not be specific to
FDA assumes that although some firms may have an environmental monitoring program for critical surfaces in place (including surfaces that contact
In the draft guidance, FDA is recommending that firms that detect
If a firm does not use one of the methods described in FDA's BAM or by ISO, FDA is recommending that the firm have a written record of its method to enumerate or detect
FDA estimates that record maintenance would require roughly 1 hour per week for each firm, for a total of about 222,040 annual hours ((4,270 plants) x (52 weeks maintenance) x (1 hour per week)).
FDA estimates that each of the 4,270 establishments expected to keep new records would purchase a storage unit for the records. A standard file cabinet large enough for such records as described in the guidance costs about $150. Therefore, there would be total first year capital costs of about $640,500 (4,270 plants x $150).
Interested persons may submit to the Division of Dockets Management (see
Please note that on January 15, 2008, the FDA Web site transitioned to the Federal Dockets Management System (FDMS). FDMS is a Government-wide, electronic docket management system. Electronic submissions will be accepted by FDA through the FDMS only.
Persons with access to the Internet may obtain the draft guidance from the Center for Food Safety and Applied Nutrition home page at
Food and Drug Administration, HHS.
Notice of meeting.
The Food and Drug Administration (FDA) is announcing a public meeting to discuss a Draft Compliance Policy Guide Sec. 555.320
The meeting will be held on March 28, 2008, from 9 a.m. to 4:30 p.m. The closing date for requests to make an oral presentation is March 7, 2008. The closing date for advance registration, for notifying the contact person about a need for special accommodations due to a disability, and for providing a brief description of an oral presentation and
The meeting will be held at the Harvey W. Wiley Federal Bldg., Food and Drug Administration, Center for Food Safety and Applied Nutrition, 5100 Paint Branch Pkwy., College Park, MD, 20740-3835 (Metro stop: College Park on the Green Line). Submit electronic registration and requests to make an oral presentation to
Due to limited space and time, we encourage all persons who wish to attend the meeting or to request an opportunity to make an oral presentation to register in advance. We encourage you to register and request an opportunity to make an oral presentation electronically, if possible. You may also register orally or in writing by providing registration information (including name, title, firm name, address, telephone number, fax number, and e-mail address), requests to make an oral presentation, and written material for the presentation to the contact person for registration (see
FDA has been working with its Federal, State, local, and international food safety counterparts in an effort to reduce the incidence of foodborne illness in the United States, including illness caused by
FDA is holding this public meeting to discuss and share information about the enforcement policy in this draft CPG. Stakeholders will have an opportunity to ask questions about the draft CPG and provide oral comments on the draft CPG. Stakeholders may send questions in advance to the contact person identified above (see
A transcript of the meeting will be available for review at the Division of Dockets Management (see
This document presents the background and rationale for the establishment of an enforcement policy for
We are issuing for public comment a draft CPG that, when finalized, would provide guidance for FDA staff as follows:
• For RTE foods that support the growth of
• For RTE foods that do not support the growth of
Some foods (such as ice cream and pickled fish) are characterized by intrinsic or extrinsic factors
• The pH of the food is less than or equal to 4.4;
• The water activity of the food is less than or equal to 0.92; or
• The food is frozen.
Foods may naturally have a pH or water activity that prevents growth of
Examples of RTE foods that generally are considered to not support the growth of
• Fish that are preserved by techniques such as drying, pickling, and marinating;
• Ice cream and other frozen dairy products;
• Processed cheese (e.g., cheese foods, spreads, slices);
• Cultured milk products (e.g., yogurt, sour cream, buttermilk);
• Hard cheeses (less than 39 percent moisture) (e.g., cheddar, colby, and parmesan);
• Some deli-type salads, particularly those processed to a pH less than 4.4 and those containing antimicrobial substances such as sorbic acid/sorbates or benzoic acid/benzoates under conditions of use documented to be effective in preventing the growth of
• Some vegetables (such as carrots); and
• Crackers, dry breakfast cereals, and other dry foods that have water activity less than 0.92 (Ref. 10).
In contrast, other foods (such as milk and crabmeat) do not have factors that prevent the growth of
• Milk;
• High fat and other dairy products (e.g., butter and cream);
• Soft unripened cheeses (greater than 50 percent moisture) (e.g., cottage cheese and ricotta cheese);
• Cooked crustaceans (e.g., shrimp and crab);
• Smoked seafood (e.g., smoked finfish and mollusks);
• Raw seafood that will be consumed as sushi or sashimi;
• Many vegetables (such as broccoli, cabbage and salad greens);
• Non-acidic fruit (such as melon, watermelon, and papaya) (Ref. 17; and
• Some deli-type salads and sandwiches (particularly those containing seafood and those prepared at retail establishments without the addition of antimicrobial substances).
Appendix 8 of Reference 1 lists some of the available information on the growth of
Beginning in 1980, a number of reports linked listeriosis outbreaks with various RTE foods, including coleslaw (Ref. 18), pasteurized milk (Ref. 19), and Mexican-style soft, white cheese (Ref. 20). In 1986, FDA revised Compliance Policy Guide (CPG) Sec. 527.300 Pathogens in Dairy Products (7106.08) to address
A 1996 paper authored by FDA staff and entitled “U.S. position on
FDA uses an analytical method that can detect 1.0 cfu of
Some international entities are approaching the contamination of foods with
As another example, the Commission of the European Community has established a directive that establishes a series of food safety criteria for
In 2001, FDA and USDA/FSIS, in consultation with the Centers for Disease Control and Prevention of the United States Department of Health and Human Services, requested comment on a draft quantitative assessment (the 2001 Draft LmRA) (Ref. 28) of relative risk associated with consumption of 20 categories of RTE foods that had a history of contamination with
In 2004, the Food and Agriculture Organization (FAO) and the World Health Organization (WHO) of the United Nations (FAO/WHO) issued a Risk Assessment of
Both the FDA/FSIS LmRA and the FAO/WHO LmRA are quantitative risk assessments that use mathematical modeling to estimate risk and assume that individuals in a population may have varying susceptibility to infection. The dose-response models developed in these risk assessments are nonthreshold models that assume that a single cell has the potential to infect and provoke a response in an individual (Ref. 30). As a result, under these models the risk presented by foodborne
The FDA/FSIS LmRA and the FAO/WHO LmRA differ in aspects such as focus (i.e., the questions that the risk assessments addressed), modeling assumptions, source of data regarding exposure, and estimation of serving size. For example, the FAO/WHO LmRA relies on the exposure data in the 2001 Draft LmRA, whereas the FDA/FSIS LmRA relies on revised exposure data that reflect modified food categories, contamination data, growth data, and data on how long foods are stored before consumption. As another example, the FDA/FSIS LmRA used empirical distributions derived from consumer surveys to describe the serving sizes in the food categories. These distributions were expressed as a series of population percentiles of the amount of food eaten per serving, weighted to reflect the consumption survey demographics. In contrast, the FAO/WHO LmRA assumed a uniform serving size of 31.6 g because this serving size both approximated a typical serving size and simplified the calculations in that dose levels were estimated in 0.5 log
The FDA/FSIS LmRA and the FAO/WHO LmRA also differ in reported output. For example, the FDA/FSIS LmRA provides information grouping its results as a two-dimensional matrix with five overall risk designations (very high, high, moderate, low, and very low) (see Figure VII-1 in Section VII of the FDA/FSIS LmRA, p. 230), whereas the FAO/WHO LmRA provides tables that report the annual incidence of listeriosis estimated to be associated with specific ingested doses of
FAO/WHO characterize their dose-response model as a conservative model that assumes maximum virulence of
Applying the exposure assessment and the dose response model in the FDA/FSIS LmRA, we estimate that there would be no annual cases of listeriosis in the total population if all servings of RTE foods were at or below 10
These estimates are in line with the estimates reported by FAO/WHO using their least conservative assumption regarding the maximum dose to which
The FDA/FSIS LmRA and other scientific information cited in that document support a conclusion that RTE foods that support the growth of
In contrast, the FDA/FSIS LmRA and other scientific information cited in that document support a conclusion that RTE foods that do not support the growth of
Because the difference in risk of listeriosis is linked to the ability of a RTE food to support the growth of
Since RTE foods that do not support the growth can be expected to have the same level of
In contrast, a RTE food that supports the growth of
The FDA/FSIS LmRA estimates that it would be rare to find
FDA anticipates that the public health benefits of this enforcement policy include clarifying for FDA staff which foods support growth of
We have placed the following references on display in the Division of Dockets Management (see
1. U.S. Food and Drug Administration and U.S. Food Safety and Inspection Service, “Quantitative Assessment of the Relative Risk to Public Health from Foodborne
2. National Advisory Committee on Microbiological Criteria for Foods (NACMCF), “
3. Fenlon, D. R., J. Wilson, and W. Donachie, “The Incidence and Level of
4. Fenlon, D. R., “
5. Tompkin, R. B., “Control of
6. Moretro, T. and S. Lansgrund, “
7. Gall, K., V. N. Scott, R. Collette, et al., “Implementing Targeted Good Manufacturing Practices and Sanitation Procedures to Minimize
8. Doyle, M. E., A. S. Mazzotta, T. Wang, et al., “Heat Resistance of
9. Lou, Y. and A. E. Yousef, “Characteristics of
10. Institute of Food Technologists, IFT/FDA Contract No. 223-98-2333, “Evaluation and Definition of Potentially Hazardous Foods,” 2001. Available at
11. Russell, N. J. and G. W. Gould, “Major Preservation Technologies,”
12. Sorrells, K. M., D. C. Enigl, and J. R. Hatfield, “Effect of pH, Acidulant, Time, and Temperature on the Growth and Survival of
13. Petran, R. L. and E. A. Zottola, “A Study of Factors Affecting Growth and Recovery of
14. Tienungoon, S., D. A. Ratkowsky, T. A. McMeekin, et al., “Growth Limits of
15. Leistner, L., “Principles and Applications of Hurdle Technology,”
16. Scott, V. N., K. M. J. Swanson, T. A. Freier, et al., “Guidelines for Conducting
17. Penteado, A. L. and M. F. F. Leitao, “Growth of
18. Schlech, W. F., III, P. M. Lavigne, R. A. Bortolussi, et al., “Epidemic Listeriosis: Evidence for Transmission by Food,”
19. Fleming, D. W., S. L. Cochi, K. L. MacDonald, et al., “Pasteurized Milk as a Vehicle of Infection in an Outbreak of Listeriosis,”
20. Linnan, M. J., L. Mascola, X. D. Lou, et al., “Epidemic Listeriosis Associated with Mexican-Style Cheese,”
21. Compliance Policy Guide Sec. 527.300 Pathogens in Dairy Products (CPG 7106.08). Accessed and printed on April 8, 2007. FDA makes the most recent edition of the CPG available at
22. Letter from J. H. Rahto of FDA, Minneapolis District Office to Bradley V. Beckman, Custom Cuts Co., March 5, 1999. Available at
23. Shank, F. R., E. L. Elliot, K. Wachsmuth, et al., “U.S. Position on
24. U.S. Food and Drug Administration, Bacteriological Analytical Manual Online, Chapter 10—“
25. Health Canada, “Policy on Ready-to-Eat Foods Contaminated with
26. Health Canada, “Health Products and Food Branch (HPFB) Standards and Guidelines for Microbiological Safety of Food—An Interpretive Summary,” 2006. Available at
27. Commission of the European Communities, “Commission Regulation (EC) No 2073/2005 of 15 November 2005 on Microbiological Criteria for Foodstuffs,”
28. U.S. Food and Drug Administration and U.S. Food Safety and Inspection Service, “Draft Assessment of the Relative Risk to Public Health from Foodborne
29. Food and Agriculture Organization and World Health Organization, “Risk Assessment of
30. Haas, C. N., “Estimation of Risk Due to Low Doses of Microorganisms: A Comparison of Alternative Methodologies,”
Table IV-12 of the FDA/FSIS LmRA (Section IV, p. 110) reports the relationship between the dose of
We took the output data of the model used in the FDA/FSIS LmRA and re-tabulated the data to show our estimates of the annual number of cases of listeriosis in the elderly population, the intermediate-age population, and the neonatal population, as well as in the total population, as a function of the ingested dose (in colony forming units, i.e., cfu) per serving. Tables 1 through 4 report that output data.
Table 1 reports the estimated ascending cumulative percentage of contaminated food servings consumed annually by the elderly population at a series of doses (in cfu/serving) and the estimated ascending cumulative percentage of illnesses in the elderly population. The data are reported at the 5th, 50th (median), and 95th percentiles. Tables 2 through 4 report these data for the intermediate-age, neonatal, and total populations, respectively.
Table IV-11 of the FDA/FSIS LmRA (Section IV, p. 105) reports the estimated total number of illnesses for each population on an annual basis as follows:
• Elderly population: 1159
• Intermediate-age population: 702
• Neonatal population: 216
• Total population: 2078
For each population, we calculated the incremental increase in the estimated percentage of contaminated servings and the incremental increase in the estimated percentage of illnesses. We then multiplied the estimated incremental percentage of illnesses by the estimated total number of illnesses for that population to obtain an estimate of the number of listeriosis cases per year for each dose. Table 5 reports the 50th percentile (i.e., median) calculated estimates of the annual number of cases of listeriosis in the elderly population, the intermediate-age population, and the neonatal population, as well as in the total population, as a function of the ingested dose per serving (i.e., cfu/serving). Table 5 also shows the calculated level (in cfu/g) corresponding to a 100 g serving size.
Table III-16 in the FDA/FSIS LmRA (see Section III, p. 73) reports the modeled distribution of
Food and Drug Administration, HHS.
Notice.
This notice announces a forthcoming meeting of a public advisory committee of the Food and Drug Administration (FDA). At least one portion of the meeting will be closed to the public.
FDA intends to make background material available to the public no later than 2 business days before the meeting. If FDA is unable to post the background material on its Web site prior to the meeting, the background material will be made publicly available at the location of the advisory committee meeting, and the background material will be posted on FDA's Web site after the meeting. Background material is available at
Persons attending FDA's advisory committee meetings are advised that the agency is not responsible for providing access to electrical outlets.
FDA welcomes the attendance of the public at its advisory committee meetings and will make every effort to accommodate persons with physical disabilities or special needs. If you require special accommodations due to a disability, please contact Shirley Meeks, Conference Management Staff, at 240-276-8931, at least 7 days in advance of the meeting.
FDA is committed to the orderly conduct of its advisory committee meetings. Please visit our Web site at
Notice of this meeting is given under the Federal Advisory Committee Act (5 U.S.C. app. 2).
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 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 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.
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 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 person 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.
Coast Guard, DHS.
Notice of meeting.
The Lower Mississippi River Waterway Safety Advisory Committee will meet in New Orleans to discuss various issues relating to navigational safety on the Lower Mississippi River and related waterways. This meeting will be open to the public.
The Committee will meet on Thursday, March 20, 2008 from 9 a.m. to 12 p.m. This meeting may close early if all business is finished. Written material and requests to make oral presentations should reach the Coast Guard on or before March 6, 2008. Requests to have a copy of your material distributed to each member of the committee or subcommittee should reach the Coast Guard on or before March 6, 2008.
The Committee will meet at the New Orleans Yacht Club, 403 North Roadway, West End, New Orleans, LA
LT Tonya Harrington, Assistant to Executive Director of Lower Mississippi River Waterway Safety Advisory Committee; at 504-565-5108.
Notice of this meeting is given under the Federal Advisory Committee Act, 5 U.S.C. App. (Pub. L. 92-463).
The agenda for the March 20, 2008 Committee meeting is as follows:
(1) Introduction of committee members.
(2) Opening Remarks.
(3) Approval of the December 11, 2007 minutes.
(4) Old Business.
(a) Captain of the Port status report.
(b) VTS update report.
(c) Subcommittee/Working Groups update reports.
(5) New Business.
(6) Adjournment.
This meeting is open to the public. Please note that the meeting may close early if all business is finished. At the Chair's discretion, members of the public may make oral presentations during the meeting. If you would like to make an oral presentation at a meeting, please notify the Executive Director no later than March 6, 2008. Written material for distribution at a meeting should reach the Coast Guard no later than March 6, 2008. If you would like a copy of your material distributed to each member of the committee or subcommittee in advance of a meeting, please submit 25 copies to the Executive Director no later than March 6, 2008.
For information on facilities or services for individuals with disabilities or to request special assistance at the meeting, contact the Executive Director as soon as possible.
Customs and Border Protection, Department of Homeland Security.
Proposed interpretation; extension of comment period.
This document provides an additional 30 days for interested parties to submit comments on Customs and Border Protection's proposed interpretation of the phrase “sold for exportation to the United States” for purposes of applying the transaction value method of valuation in a series of sales importation scenario. The proposed interpretation was published in the
Comments on the proposed rule must be received on or before April 23, 2008.
You may submit comments, identified by docket number, by one of the following methods:
•
•
Lorrie Rodbart, Valuation and Special Programs Branch, Regulations and Rulings, Office of International Trade, (202) 572-8740.
Interested persons are invited to submit written data, views, or arguments on all aspects of the proposed interpretation. If appropriate to a specific comment, the commenter should reference the specific portion of the proposed interpretation, explain the reason for any recommended change, and include data, information, or authority that support such recommended change.
On January 24, 2008, a notice was published in the
The notice of proposed interpretation invited public comment on the
In response to the proposed interpretation, CBP has received correspondence requesting an extension of the comment period. A decision has been made to grant an extension of 30 days. Comments are now due on or before April 23, 2008.
Office of the Assistant Secretary for Housing—Federal Housing Commissioner, HUD.
Notice.
In accordance with section 206A of the National Housing Act, HUD has adjusted the basic statutory mortgage limits for multifamily housing programs for calendar year 2008.
January 1, 2008.
Joseph A. Sealey, Director, Technical Support Division, Office of Multifamily Development, Department of Housing and Urban Development, 451 Seventh Street, SW., Washington, DC 20410-8000, telephone (202) 402-2559 (this is not a toll-free number). Hearing- or speech-impaired individuals may access this number through TTY by calling the toll-free Federal Information Relay Service at (800) 877-8339.
The FHA Downpayment Simplification Act of 2002 (Pub. L. 107-326, approved December 4, 2002) amended the National Housing Act by adding a new section 206A (12 U.S.C. 1712a). Under section 206A, the following are affected:
(1) Section 207(c)(3)(A) (12 U.S.C. 1713(c)(3)(A));
(2) Section 213(b)(2)(A) (12 U.S.C. 1715e(b)(2)(A));
(3) Section 220(d)(3)(B)(iii)(I) (12 U.S.C. 1715k(d)(3)(B)(iii)(I));
(4) Section 221(d)(3)(ii)(I) (12 U.S.C. 1715l(d)(3)(ii)(I));
(5) Section 221(d)(4)(ii)(I) (12 U.S.C. 1715l(d)(4)(ii)(I));
(6) Section 231(c)(2)(A) (12 U.S.C. 1715v(c)(2)(A)); and
(7) Section 234(e)(3)(A) (12 U.S.C. 1715y(e)(3)(A)).
The dollar amounts in these sections, which are collectively referred to as the “Dollar Amounts,” shall be adjusted annually (commencing in 2004) on the effective date of the Federal Reserve Board's adjustment of the $400 figure in the Home Ownership and Equity Protection Act of 1994 (HOEPA) (Pub. L. 103-325, approved September 23, 1994). The adjustment of the Dollar Amounts shall be calculated using the percentage change in the Consumer Price Index for All Urban Consumers (CPI-U) as applied by the Federal Reserve Board for purposes of the above-described HOEPA adjustment.
HUD has been notified of the percentage change in the CPI-U used for the HOEPA adjustment and the effective date of the HOEPA adjustment. The percentage change in the CPI-U is 2.56 percent and the effective date of the HOEPA adjustment is January 1, 2008. The Dollar Amounts have been adjusted correspondingly and have an effective date of January 1, 2008.
The adjusted Dollar Amounts for calendar year 2008 are shown below:
Bureau of Land Management, Interior.
Temporary Road Closure of BLM-Administered Road; Rio Blanco County, Colorado.
Notice is hereby given that a certain access road in Rio Blanco County, Colorado, is closed to all entry or use by all members of the public. The closure is made under the authority of 43 CFR 8364.1. The public road affected by this closure is specifically identified as follows:
BLM Road 1005, Piceance Creek Crossing at Sprague Gulch.
The following persons, operating within the scope of their official duties, are exempt from the provisions of this closure order: Dan and Cheryl Johnson/ Piceance Creek Ranch, Bureau of Land
Any person who fails to comply with the provisions of this closure order may be subject to the penalties provided in 43 CFR 8360.0-7, which include a fine not to exceed $1,000 and/or imprisonment not to exceed 12 months, as well as the penalties provided under Colorado State law.
The road closed to public use under this order will be posted with signs at points of public access.
The purpose of this closure is to protect persons and public resources from a low water stream crossing made unsafe by unstable streambed and banks, and an excessive buildup of ice.
This closure is effective as of 12 noon, January 22, 2008 and will remain in effect until June 1, unless otherwise directed by the authorizing officer.
Copies of the closure order and maps showing the location of the road are available from the White River Field Office, 220 E. Market Street, Meeker, Colorado 81641.
Kent Walter, Field Manager, White River Field Office, at (970) 878-3800.
On January 8, 2008, the Department of Labor (Department) received a request for administrative reconsideration of the Department's Notice of Negative Determination regarding workers' eligibility to apply for Alternative Trade Adjustment Assistance (ATAA) applicable to workers and former workers of the subject firm. The determination was issued on November 30, 2007. The Department's Notice of Determination Regarding ATAA was published in the
The negative determination was based on the Department's findings that the workers in the workers' firm possess skills that are easily transferable.
In the request for reconsideration, a worker alleged that “salaries at other factories in similar jobs are much lower” than wages paid by the subject firm.
The Department has carefully reviewed the request for reconsideration and has determined that the Department will conduct further investigation.
After careful review of the application, I conclude that the claim is of sufficient weight to justify reconsideration of the U.S. Department of Labor's prior decision. The application is, therefore, granted.
In accordance with Section 223 of the Trade Act of 1974 (19 U.S.C. 2273), and Section 246 of the Trade Act of 1974 (26 U.S.C. 2813), as amended, the Department of Labor issued a Certification Regarding Eligibility to Apply for Worker Adjustment Assistance and a Negative Determination Regarding Eligibility to Apply for Alternative Trade Adjustment Assistance on September 28, 2005, applicable to workers of Sara Lee Branded Apparel, Division Office, Winston-Salem, North Carolina. The notice was published in the
At the request of a petitioner and the State agency, the Department reviewed the certification for workers of the subject firm. New information shows that a worker separation occurred involving an employee of the Division Office, Winston-Salem, North Carolina facility of the Sara Lee Branded Apparel located in Covington, Georgia. Ms. Charlene Gautier provided sales and merchandizing support function services for the activities related to the production of underwear (shorts and T-shirts) produced by the subject company.
Based on these findings, the Department is amending this certification to include an employee of the Division Office, Winston-Salem, North Carolina facility of the Sara Lee Branded Apparel located in Covington, Georgia.
The intent of the Department's certification is to include all workers of Sara Lee Branded Apparel, Division Office, Winston-Salem, North Carolina
The amended notice applicable to TA-W-57,802 is hereby issued as follows:
All workers of Sara Lee Branded Apparel, Division Office, Division of the Sara Lee Corporation, formerly known as National Textiles, LLC, currently known as Hanesbrands, Inc., Winston-Salem, North Carolina (TA-W-57,802), and including an employee of Sara Lee Branded Apparel, Division Office, Division of Sara Lee Corporation, currently known as Hanesbrands, Inc., Winston Salem, North Carolina, located in Covington, Georgia (TA-W-57,802F), who became totally or partially separated from employment on or after July 29, 2004, through September 28, 2007, are eligible to apply for adjustment assistance under Section 223 of the Trade Act of 1974.
I further determine that all workers of Sara Lee Branded Apparel, Division of the Sara Lee Corporation, formerly known as National Textiles, LLC, currently known as Hanesbrands, Inc., Winston-Salem, North Carolina (TA-W-57,802), and including an employee of Sara Lee Branded Apparel, Division Office, Division of Sara Lee Corporation, formerly known as National Textiles, LLC, currently known as Hanesbrands, Inc., Winston Salem, North Carolina, located in Covington, Georgia (TA-W-57,802F) are denied eligibility to apply for alternative trade adjustment assistance under Section 246 of the Trade Act of 1974.
In accordance with section 223 of the Trade Act of 1974, as amended (19 U.S.C. 2273) the Department of Labor herein presents summaries of determinations regarding eligibility to apply for trade adjustment assistance for workers (TA-W) number and alternative trade adjustment assistance (ATAA) by (TA-W) number issued during the period of
In order for an affirmative determination to be made for workers of a primary firm and a certification issued regarding eligibility to apply for worker adjustment assistance, each of the group eligibility requirements of Section 222(a) of the Act must be met.
I. Section (a)(2)(A) all of the following must be satisfied:
A. A significant number or proportion of the workers in such workers' firm, or an appropriate subdivision of the firm, have become totally or partially separated, or are threatened to become totally or partially separated;
B. the sales or production, or both, of such firm or subdivision have decreased absolutely; and
C. increased imports of articles like or directly competitive with articles produced by such firm or subdivision have contributed importantly to such workers' separation or threat of separation and to the decline in sales or production of such firm or subdivision; or
II. Section (a)(2)(B) both of the following must be satisfied:
A. A significant number or proportion of the workers in such workers' firm, or an appropriate subdivision of the firm, have become totally or partially separated, or are threatened to become totally or partially separated;
B. there has been a shift in production by such workers' firm or subdivision to a foreign country of articles like or directly competitive with articles which are produced by such firm or subdivision; and
C. One of the following must be satisfied:
1. The country to which the workers' firm has shifted production of the articles is a party to a free trade agreement with the United States;
2. the country to which the workers' firm has shifted production of the articles to a beneficiary country under the Andean Trade Preference Act, African Growth and Opportunity Act, or the Caribbean Basin Economic Recovery Act; or
3. there has been or is likely to be an increase in imports of articles that are like or directly competitive with articles which are or were produced by such firm or subdivision.
Also, in order for an affirmative determination to be made for secondarily affected workers of a firm and a certification issued regarding eligibility to apply for worker adjustment assistance, each of the group eligibility requirements of section 222(b) of the Act must be met.
(1) A Significant number or proportion of the workers in the workers' firm or an appropriate subdivision of the firm have become totally or partially separated, or are threatened to become totally or partially separated;
(2) the workers' firm (or subdivision) is a supplier or downstream producer to a firm (or subdivision) that employed a group of workers who received a certification of eligibility to apply for trade adjustment assistance benefits and such supply or production is related to the article that was the basis for such certification; and
(3) either—
(A) the workers' firm is a supplier and the component parts it supplied for the firm (or subdivision) described in paragraph (2) accounted for at least 20 percent of the production or sales of the workers' firm; or
(B) a loss or business by the workers' firm with the firm (or subdivision) described in paragraph (2) contributed importantly to the workers' separation or threat of separation.
In order for the Division of Trade Adjustment Assistance to issue a certification of eligibility to apply for Alternative Trade Adjustment Assistance (ATAA) for older workers, the group eligibility requirements of section 246(a)(3)(A)(ii) of the Trade Act must be met.
1. Whether a significant number of workers in the workers' firm are 50 years of age or older.
2. Whether the workers in the workers' firm possess skills that are not easily transferable.
3. The competitive conditions within the workers' industry (i.e., conditions within the industry are adverse).
The following certifications have been issued. The date following the company name and location of each determination references the impact date for all workers of such determination.
The following certifications have been issued. The requirements of section 222(a)(2)(A) (increased imports) of the Trade Act have been met.
The following certifications have been issued. The requirements of section 222(a)(2)(B) (shift in production) of the Trade Act have been met.
The following certifications have been issued. The requirements of section 222(b) (supplier to a firm whose workers are certified eligible to apply for TAA) of the Trade Act have been met.
The following certifications have been issued. The requirements of section 222(b) (downstream producer for a firm whose workers are certified eligible to apply for TAA based on increased imports from or a shift in production to
The following certifications have been issued. The date following the company name and location of each determination references the impact date for all workers of such determination.
The following certifications have been issued. The requirements of Section 222(a)(2)(A) (increased imports) and section 246(a)(3)(A)(ii) of the Trade Act have been met.
The following certifications have been issued. The requirements of section 222(a)(2)(B) (shift in production) and section 246(a)(3)(A)(ii) of the Trade Act have been met.
The following certifications have been issued. The requirements of Section 222(b) (supplier to a firm whose workers are certified eligible to apply for TAA) and section 246(a)(3)(A)(ii) of the Trade Act have been met.
The following certifications have been issued. The requirements of section 222(b) (downstream producer for a firm whose workers are certified eligible to apply for TAA based on increased imports from or a shift in production to Mexico or Canada) and section 246(a)(3)(A)(ii) of the Trade Act have been met.
In the following cases, it has been determined that the requirements of 246(a)(3)(A)(ii) have not been met for the reasons specified.
The Department has determined that criterion (1) of section 246 has not been met. The firm does not have a significant number of workers 50 years of age or older.
The Department has determined that criterion (2) of section 246 has not been met. Workers at the firm possess skills that are easily transferable.
The Department has determined that criterion (3) of section 246 has not been met. Competition conditions within the workers' industry are not adverse.
In the following cases, the investigation revealed that the eligibility criteria for worker adjustment assistance have not been met for the reasons specified.
Because the workers of the firm are not eligible to apply for TAA, the workers cannot be certified eligible for ATAA.
The investigation revealed that criteria (a)(2)(A)(I.A.) and (a)(2)(B)(II.A.) (employment decline) have not been met.
The investigation revealed that criteria (a)(2)(A)(I.B.) (Sales or production, or both, did not decline) and (a)(2)(B)(II.B.) (shift in production to a foreign country) have not been met.
The investigation revealed that criteria (a)(2)(A)(I.C.) (increased imports) and (a)(2)(B)(II.B.) (shift in production to a foreign country) have not been met.
The workers' firm does not produce an article as required for certification under Section 222 of the Trade Act of 1974.
The investigation revealed that criteria of section 222(b)(2) has not been met. The workers' firm (or subdivision) is not a supplier to or a downstream producer for a firm whose workers were certified eligible to apply for TAA.
I hereby certify that the aforementioned determinations were issued during the period of
In accordance with Section 223 of the Trade Act of 1974 (19 U.S.C. 2273), and Section 246 of the Trade Act of 1974 (26 U.S.C. 2813), as amended, the Department of Labor issued a Certification Regarding Eligibility to Apply for Worker Adjustment Assistance and Alternative Trade Adjustment Assistance on November 5, 2007, applicable to workers of Dexter Chemical LLC, Textile Chemicals Division, Charlotte, North Carolina. The notice was published in the
At the request of the State agency, the Department reviewed the certification for workers of the subject firm.
New information shows that a worker separation occurred involving an employee of the Charlotte, North Carolina facility of Dexter Chemical LLC, Textile Chemicals Division located in Marietta, Georgia. Mr. Richard H. Bass provided sales function services supporting the production of specialty chemicals for the textile industry that is produced at the subject firm.
Based on these findings, the Department is amending this certification to include an employee of the Charlotte, North Carolina facility of Dexter Chemical LLC, Textile Chemicals Division working out of Marietta, Georgia.
The intent of the Department's certification is to include all workers of Dexter Chemical LLC, Textile Chemicals Division, Charlotte, North Carolina who were adversely affected by increased imports as an upstream supplier of component parts for textiles.
The amended notice applicable to TA-W-62,210A is hereby issued as follows:
Petitions have been filed with the Secretary of Labor under Section 221(a) of the Trade Act of 1974 (“the Act”) and are identified in the Appendix to this notice. Upon receipt of these petitions, the Director of the Division of Trade Adjustment Assistance, Employment and Training Administration, has instituted investigations pursuant to Section 221(a) of the Act.
The purpose of each of the investigations is to determine whether the workers are eligible to apply for adjustment assistance under Title II, Chapter 2, of the Act. The investigations will further relate, as appropriate, to the determination of the date on which total or partial separations began or threatened to begin and the subdivision of the firm involved.
The petitioners or any other persons showing a substantial interest in the subject matter of the investigations may request a public hearing, provided such request is filed in writing with the Director, Division of Trade Adjustment Assistance, at the address shown below, not later than February 19, 2008.
Interested persons are invited to submit written comments regarding the subject matter of the investigations to the Director, Division of Trade Adjustment Assistance, at the address shown below, not later than February 19, 2008.
The petitions filed in this case are available for inspection at the Office of the Director, Division of Trade Adjustment Assistance, Employment and Training Administration, U.S. Department of Labor, Room C-5311, 200 Constitution Avenue, NW., Washington, DC 20210.
On November 30, 2007, the Department issued an Affirmative Determination Regarding Application for Reconsideration for the workers and former workers of the subject firm. The notice was published in the
The initial investigation resulted in a negative determination based on the finding that imports of kitchen cabinet parts did not contribute importantly to worker separations at the subject firm and no shift of production to a foreign source occurred. The investigation also revealed that the products manufactured at the subject firm are sent to other affiliated facilities for further finishing and assembly.
The Carpenters Industrial Council, United Brotherhood of Carpenters and Joiners of America filed a request for reconsideration in which they contend that the workers of the subject firm build and assemble the finished products, which does not require further manufacturing and are sold to customers. The petitioner also requested that the Department of Labor investigate whether there was an increase in imports of articles like or directly competitive with products manufactured at the subject firm.
The Department contacted a company official to verify products manufactured at the subject firm and whether the subject firm had any outside customers. During reconsideration, the company official provided new information and confirmed that the subject firm manufactures kitchen cabinet parts and hardwood cabinets which are sold to outside customers. The official also supplied the Department with a list of major declining customers who purchased hardwood cabinets from the subject firm.
The Department of Labor surveyed the major declining customers of the subject firm regarding their purchases of like or directly competitive products with hardwood cabinets purchased from the subject firm in 2005, 2006, and during January through September 2007 over the corresponding 2006 period. The survey revealed that the customers did not increase their import purchases while decreasing purchases from the subject firm.
The subject firm did not import hardwood cabinets nor was there a shift in production from subject firm abroad during the relevant period.
After reconsideration, I affirm the original notice of negative determination of eligibility to apply for worker adjustment assistance for
By letter dated December 28, 2007, a company official requested administrative reconsideration regarding the Department's Negative Determination Regarding Eligibility to Apply for Worker Adjustment Assistance, applicable to the workers of the subject firm. The denial notice was signed on November 28, 2007 and published in the
Pursuant to 29 CFR 90.18(c) reconsideration may be granted under the following circumstances:
(1) If it appears on the basis of facts not previously considered that the determination complained of was erroneous;
(2) If it appears that the determination complained of was based on a mistake in the determination of facts not previously considered; or
(3) If in the opinion of the Certifying Officer, a misinterpretation of facts or of the law justified reconsideration of the decision.
The initial investigation resulted in a negative determination which was based on the finding that imports of brominated chemical intermediates (i.e. bromobenzene, m-bromoanisole, n-propyl bromide, and other organics) did not contribute importantly to worker separations at the subject plant and no shift of production to a foreign source occurred. The “contributed importantly” test is generally demonstrated through a survey of the workers' firm's declining customers. The survey revealed customers did not purchase imported brominated chemical intermediates during the relevant period. The subject firm did not import brominated chemical intermediates and no shifted in production of brominated chemical intermediates to a foreign country occurred.
The petitioner stated that most of the subject firm's sales were for export, however, there were losses in sales to domestic customers. The petitioner provided the name of a customer which ceased purchases from the subject firm in 2005 and at the same time started importing products like or directly competitive with brominated chemical intermediates produced by the subject firm.
When assessing eligibility for Trade Adjustment Assistance (TAA), the Department exclusively considers import impact during the relevant time period (one year prior to the date of the petition). The Department surveyed customers of the subject firm regarding their purchases of brominated chemical intermediates during the relevant period. The survey revealed no imports of brominated chemical intermediates during the relevant period.
After review of the application and investigative findings, I conclude that there has been no error or misinterpretation of the law or of the facts which would justify reconsideration of the Department of Labor's prior decision. Accordingly, the application is denied.
By application dated December 28, 2007, a company official requested administrative reconsideration of the Department's negative determination regarding eligibility to apply for Trade Adjustment Assistance (TAA), applicable to workers and former workers of the subject firm. The denial notice was signed on November 28, 2007 and published in the
Pursuant to 29 CFR 90.18(c) reconsideration may be granted under the following circumstances:
(1) If it appears on the basis of facts not previously considered that the determination complained of was erroneous;
(2) If it appears that the determination complained of was based on a mistake in the determination of facts not previously considered; or
(3) If in the opinion of the Certifying Officer, a misinterpretation of facts or of the law justified reconsideration of the decision.
The investigation revealed that workers of the subject firm were in support of production of brominated chemical intermediates at Diaz Intermediates Corporation, West Memphis, Arkansas. The initial investigation resulted in a negative determination which was based on the finding that imports of brominated chemical intermediates (i.e., bromobenzene, m-bromoanisole, n-propyl bromide, and other organics) did not contribute importantly to worker separations at the subject plant and no shift of production to a foreign source occurred. The “contributed importantly” test is generally demonstrated through a survey of the workers' firm's declining customers. The survey revealed customers did not purchase imports of brominated chemical intermediates during the relevant period. The subject firm did not import brominated chemical intermediates and no shifted in production of brominated chemical intermediates to a foreign country occurred.
The petitioner stated that most of the subject firm's sales were for export, and that there were losses in sales to domestic customers. The petitioner provided the name of a customer which ceased purchases from the subject firm in 2005 and at the same time started importing products like or directly competitive with brominated chemical intermediates produced by the subject firm.
When assessing eligibility for TAA, the Department exclusively considers import impact during the relevant time period (one year prior to the date of the petition). The Department surveyed customers of the subject firm regarding their purchases of brominated chemical intermediates during the relevant period. The survey revealed no imports of brominated chemical intermediates during the relevant period.
After review of the application and investigative findings, I conclude that
Pursuant to Section 221 of the Trade Act of 1974, as amended, an investigation was initiated on January 11, 2008 in response to a worker petition filed by a company official on behalf of workers at Conrad Forest Products, North Bend, Oregon.
The petitioner has requested that the petition be withdrawn. Consequently, the investigation has been terminated.
Mine Safety and Health Administration, Labor.
Notice of petitions for modification of existing mandatory safety standards.
Section 101(c) of the Federal Mine Safety and Health Act of 1977 and 30 CFR Part 44 govern the application, processing, and disposition of petitions for modification. This notice is a summary of petitions for modification filed by the parties listed below to modify the application of existing mandatory safety standards published in Title 30 of the Code of Federal Regulations.
All comments on the petitions must be received by the Office of Standards, Regulations, and Variances on or before March 10, 2008.
You may submit your comments, identified by “docket number” on the subject line, by any of the following methods:
1.
2.
3.
4.
We will consider only comments postmarked by the U.S. Postal Service or proof of delivery from another delivery service such as UPS or Federal Express on or before the deadline for comments. Individuals who submit comments by hand-delivery are required to check in at the receptionist desk on the 21st floor.
Individuals may inspect copies of the petitions and comments during normal business hours at the address listed above.
Edward Sexauer, Chief, Regulatory Development Division at 202-693-9444 (Voice),
Section 101(c) of the Federal Mine Safety and Health Act of 1977 (Mine Act) allows the mine operator or representative of miners to file a petition to modify the application of any mandatory safety standard to a coal or other mine if the Secretary determines that: (1) An alternative method of achieving the result of such standard exists which will at all times guarantee no less than the same measure of protection afforded the miners of such mine by such standard; or (2) that the application of such standard to such mine will result in a diminution of safety to the miners in such mine. In addition, the regulations at 30 CFR 44.10 and 44.11 establish the requirements and procedures for filing petitions for modifications.
Occupational Safety and Health Administration (OSHA), Labor.
Notice.
This notice announces the Occupational Safety and Health Administration's final decision expanding the recognition of SGS U.S. Testing Company, Inc., (SGSUS) as a Nationally Recognized Testing Laboratory under 29 CFR 1910.7.
The expansion of recognition becomes effective on February 7, 2008.
MaryAnn Garrahan, Director, Office of Technical Programs and Coordination Activities, NRTL Program, Occupational Safety and Health Administration, U.S. Department of Labor, 200 Constitution Avenue, NW., Room N-3655, Washington, DC 20210, or phone (202) 693-2110.
The Occupational Safety and Health Administration (OSHA) hereby gives notice of the expansion of recognition of SGS U.S. Testing Company, Inc., (SGSUS) as a Nationally Recognized Testing Laboratory (NRTL). The expansion covers the use of additional test standards. OSHA's current scope of recognition for SGSUS may be found in the following informational Web page:
OSHA recognition of an NRTL signifies that the organization has met the legal requirements in Section 1910.7 of Title 29, Code of Federal Regulations (29 CFR 1910.7). Recognition is an acknowledgment that the organization can perform independent safety testing and certification of the specific products covered within its scope of recognition and is not a delegation or grant of government authority. As a result of recognition, employers may use products properly approved by the NRTL to meet OSHA standards that require testing and certification.
The Agency processes applications by an NRTL for initial recognition or for expansion or renewal of this recognition following requirements in Appendix A to 29 CFR 1910.7. This appendix requires that the Agency publish two notices in the
SGSUS applied on September 28, 2005, for expansion of its recognition to add seven test standards to its scope (see Exhibit 18-2, as cited in the preliminary notice). The NRTL Program staff determined that each of these standards is an “appropriate test standard” within the meaning of 29 CFR 1910.7(c). OSHA staff performed an on-site visit of the NRTL's Fairfield site in September 2005. Based on this visit, in February 2006, the staff recommended the expansion to include the seven additional test standards (see Exhibit 18-4, as cited in the preliminary notice). Therefore, OSHA is approving these test standards for the expansion.
The preliminary notice announcing the expansion application and the SGSUS renewal application was published in the
The most recent application processed by OSHA specifically related to the recognition of SGSUS granted an expansion, and the final notice for this expansion was published on May 12, 2000 (65 FR 30638).
You may obtain or review copies of all public documents pertaining to the SGSUS application by contacting the Docket Office, Occupational Safety and Health Administration, U.S. Department of Labor, 200 Constitution Avenue, NW., Room N-2625, Washington, DC 20210. Docket No. OSHA-2006-0040 (formerly NRTL2-90) contains all materials in the record concerning the recognition of SGSUS.
The current address of the SGSUS facility (site) already recognized by OSHA is: SGS U.S. Testing Company, Inc., 291 Fairfield Avenue, Fairfield, New Jersey 07004.
NRTL Program staff has examined the application, the assessor's recommendation, and other pertinent information. Based upon this examination and the assessor's recommendation, OSHA finds that SGSUS has met the requirements of 29 CFR 1910.7 for expansion of its recognition, subject to the limitation and conditions listed below. Pursuant to the authority in 29 CFR 1910.7, OSHA hereby expands the recognition of SGSUS, subject to this limitation and these conditions.
OSHA limits the expansion of recognition of SGSUS to testing and
The designations and titles of the above test standards were current at the time of the preparation of this final notice.
OSHA's recognition of SGSUS, or any NRTL, for a particular test standard is limited to equipment or materials (i.e., products) for which OSHA standards require third-party testing and certification before use in the workplace. Consequently, if a test standard also covers any product(s) for which OSHA does not require such testing and certification, an NRTL's scope of recognition does not include that product(s).
A test standard listed above may be approved as an American National Standard by the American National Standards Institute (ANSI). However, for convenience, we use the designation of the standards developing organization for the standard as opposed to the ANSI designation. Under our procedures, any NRTL recognized for an ANSI-approved test standard may use either the latest proprietary version of the test standard or the latest ANSI version of that standard. You may contact ANSI to find out whether or not a test standard is currently ANSI-approved.
SGSUS must also abide by the following conditions of the recognition, in addition to those already required by 29 CFR 1910.7:
OSHA must be allowed access to SGSUS's facilities and records for purposes of ascertaining continuing compliance with the terms of its recognition and to investigate as OSHA deems necessary;
If SGSUS has reason to doubt the efficacy of any test standard it is using under this program, it must promptly inform the test standard developing organization of this fact and provide that organization with appropriate relevant information upon which its concerns are based;
SGSUS must not engage in or permit others to engage in any misrepresentation of the scope or conditions of its recognition. As part of this condition, SGSUS agrees that it will allow no representation that it is either a recognized or an accredited Nationally Recognized Testing Laboratory (NRTL) without clearly indicating the specific equipment or material to which this recognition is tied, or that its recognition is limited to certain products;
SGSUS must inform OSHA as soon as possible, in writing, of any change of ownership, facilities, or key personnel, and of any major changes in its operations as an NRTL, including details;
SGSUS will meet all the terms of its recognition and will always comply with all OSHA policies pertaining to this recognition; and
SGSUS will continue to meet the requirements for recognition in all areas where it has been recognized.
Occupational Safety and Health Administration (OSHA), Labor.
Notice.
This notice announces the application of TUV America, Inc., (TUVAM) for expansion of its recognition and presents the Agency's preliminary finding to grant this request. This preliminary finding does not constitute an interim or temporary approval of this application.
You must submit information or comments, or any request for extension of the time to comment, by the following dates:
• Hard copy: postmarked or sent by February 22, 2008.
• Electronic transmission or facsimile: sent by February 22, 2008.
You may submit comments by any of the following methods:
MaryAnn Garrahan, Director, Office of Technical Programs and Coordination Activities, NRTL Program, Occupational Safety and Health Administration, U.S. Department of Labor, 200 Constitution Avenue, NW., Room N3655, Washington, DC 20210, or phone (202) 693-2110. Our Web page includes information about the NRTL Program (see
The Occupational Safety and Health Administration (OSHA) hereby gives
OSHA recognition of an NRTL signifies that the organization has met the legal requirements in Section 1910.7 of Title 29, Code of Federal Regulations (29 CFR 1910.7). Recognition is an acknowledgment that the organization can perform independent safety testing and certification of the specific products covered within its scope of recognition and is not a delegation or grant of government authority. As a result of recognition, employers may use products properly approved by the NRTL to meet OSHA standards that require testing and certification.
The Agency processes applications by an NRTL for initial recognition or for expansion or renewal of this recognition following requirements in Appendix A to 29 CFR 1910.7. This appendix requires that the Agency publish two notices in the
The most recent application processed by OSHA specifically related to TUVAM's recognition granted an expansion, and the final notice for this expansion was published on August 30, 2005 (70 FR 51373).
The current addresses of the TUVAM facilities already recognized by OSHA are: TUV Product Services (TUVAM), 5 Cherry Hill Drive, Danvers, MA 01923; TUV Product Services (TUVAM), 10040 Mesa Rim Road, San Diego, CA 92121; and TUV Product Services (TUVAM), 1775 Old Highway 8, NW., Suite 104, New Brighton (Minneapolis), MN 55112.
TUVAM submitted an application, dated October 6, 2005 (see Exhibit 11-1), to expand its recognition to include 142 additional test standards. It amended its application on February 17, 2006, to add two more test standards, and then in June 2006 and July 2007 further amended its application to reduce its request to 89 test standards (see Exhibits 11-2 through 11-4), one of which, however, has been withdrawn by the standards developing organization. Thus, TUVAM's request includes 88 standards. The NRTL Program staff has determined that each of the remaining standards is an “appropriate test standard” within the meaning of 29 CFR 1910.7(c). In connection with this request, NRTL Program assessment staff performed an on-site review of TUVAM's Massachusetts testing facility and recommended that TUVAM's recognition be expanded to include the additional test standards listed below (see Exhibit 11-5). As a result, the Agency would approve the 88 test standards for the expansion.
TUVAM seeks recognition for testing and certification of products for demonstration of conformance to the following test standards:
The designations and titles of the above test standards were current at the time of the preparation of this notice.
OSHA's recognition of TUVAM, or any NRTL, for a particular test standard is limited to equipment or materials (i.e., products) for which OSHA standards require third-party testing and certification before use in the workplace. Consequently, if a test standard also covers any product(s) for which OSHA does not require such testing and certification, an NRTL's scope of recognition does not include that product(s).
A test standard listed above may also be approved as an American National Standard by the American National Standards Institute (ANSI). However, for convenience, we use the designation of the standards developing organization for the standard as opposed to the ANSI designation. Under our procedures, any NRTL recognized for an ANSI-approved test standard may use either the latest proprietary version of the test standard or the latest ANSI version of that standard. You may contact ANSI to find out whether or not a test standard is currently ANSI-approved.
TUVAM has submitted an acceptable request for expansion of its recognition as an NRTL. Our review of the application file, the assessor's recommendation, and other pertinent documents indicate that TUVAM can meet the requirements, as prescribed by 29 CFR 1910.7, for the expansion for the additional test standards listed above. This preliminary finding does not constitute an interim or temporary approval of the application.
OSHA welcomes public comments, in sufficient detail, as to whether TUVAM has met the requirements of 29 CFR 1910.7 for expansion of its recognition as a Nationally Recognized Testing Laboratory. Your comments should consist of pertinent written documents and exhibits. Should you need more time to comment, you must request it in writing, including reasons for the request. OSHA must receive your written request for extension at the address provided above no later than the last date for comments. OSHA will limit any extension to 30 days, unless
The NRTL Program staff will review all timely comments and, after resolution of issues raised by these comments, will recommend whether to grant TUVAM's expansion request. The Assistant Secretary will make the final decision on granting the expansion and, in making this decision, may undertake other proceedings that are prescribed in Appendix A to 29 CFR Section 1910.7. OSHA will publish a public notice of this final decision in the
The Office of Nuclear Reactor Regulation (NRR) staff at the U.S. Nuclear Regulatory Commission (NRC) is implementing an electronic distribution initiative (EDI) that will modify the method of distributing selected categories (e.g., operating reactor license amendments) of operating reactor licensing correspondence. Specifically, this initiative involves replacing distribution of paper copies with electronic distribution to the plant mailing list for documents generated by NRR's Division of Operating Reactor Licensing. This initiative does not affect the availability of official agency records in NRC's Agencywide Documents Access and Management System (ADAMS), which are publicly available on the NRC's Web page
When this initiative is implemented, addressees will continue to receive the original correspondence, while those on the plant mailing list will receive electronic mail (e-mail). The distribution of safeguards information, proprietary or security-related information, or other information that is withheld from public disclosure will not be affected by this initiative. The NRC staff will protect the e-mail address from disclosure to others for privacy concerns.
In order to evaluate the feasibility of electronic distribution, the staff engaged in a pilot program with Exelon Generation Company, LLC (West). The pilot program began July 1, 2007, and ended September 30, 2007. A
During the pilot program, the method used for distribution was e-mail. The e-mail contained an electronic link to ADAMS providing direct access to the correspondence. In addition, addressees received an Adobe Acrobat
To obtain information to enhance the EDI, steps were taken to engage stakeholders. In the initial
Because the pilot program demonstrated feasibility and the feedback received was overwhelmingly favorable, the NRC is taking additional steps to pursue implementation of electronic distribution of correspondence. Recognizing the potential to provide a more effective and efficient method of distributing correspondence, the NRC intends to implement this initiative in 2008.
If you have specific comments regarding this initiative, please contact Mr. Russell Gibbs at 301-415-7198, or
For The Nuclear Regulatory Commission.
Securities and Exchange Commission (“Commission”).
Notice of an application for an order under section 6(c) of the Investment Company Act of 1940 (“Act”) for an exemption from sections 2(a)(32), 5(a)(1) and 22(d) of the Act and rule 22c-1 under the Act, and under sections 6(c) and 17(b) of the Act for an exemption from sections 17(a)(1) and (a)(2) of the Act, and under section 12(d)(1)(J) for an exemption from sections 12(d)(1)(A) and (B) of the Act.
Secretary, U.S. Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-1090. Applicants: Advisor and Trust, 301 West Roosevelt Road, Wheaton, IL 60187; Distributor, 11 Greenway Plaza, Houston, TX 77046-1173; AER, 30 Laurence Lane, Rye Beach, NH 03871.
Marilyn Mann, Branch Chief, or Michael W. Mundt, Assistant Director, at (202) 551-6821 (Division of Investment Management, Office of Investment Company Regulation).
The following is a summary of the application. The complete application may be obtained for a fee at the Commission's Public Reference Desk, 100 F Street, NE., Washington, DC 20549-0102 (tel. 202-551-5850).
1. The Trust is an open-end management investment company registered under the Act and organized as a Delaware business trust. The Trust will offer two initial series subadvised by AER: The PowerShares Active AlphaQ Portfolio and the PowerShares Active Alpha Multi-Cap Portfolio (the “Initial AER Funds”). The Trust will also offer two initial series subadvised by Invesco Institutional (N.A.), Inc. (“Invesco”): The PowerShares Active Mega-Cap Portfolio (“Mega-Cap Fund”) and PowerShares Active Low Duration Portfolio (“Low Duration Fund,” and together with the Mega-Cap Fund, the “Initial Invesco Funds”). The Initial AER Funds and Initial Invesco Funds are collectively referred to as the “Initial Funds.” Each Initial AER Fund's investment objective will be to provide long-term capital appreciation by investing in stocks selected according to a quantitative screening methodology developed by AER. The Mega-Cap Fund's investment objective will be to provide long-term growth of capital by investing primarily in the equity securities of mega-capitalization companies according to a quantitative approach developed by Invesco. The Low Duration Fund's investment objective is to provide total return by investing primarily in U.S. government and corporate debt securities.
2. The Advisor plans to introduce future series of the Trust or of other open-end management investment companies that will invest in equity or fixed income securities traded in the U.S. markets (“Future Funds”). Applicants request that the order apply to any such Future Funds. Any Future Fund will be (a) advised by the Advisor or an entity controlling, controlled by, or under common control with the Advisor, and (b) comply with the terms and conditions of the order. The Initial Funds and Future Funds together are the “Funds.” Funds that invest in equity securities are “Equity Funds” and Funds that invest in fixed income securities are “Fixed Income Funds.” Each Fund will operate as an actively-managed exchange-traded fund (“ETF”).
3. The Advisor, a Delaware limited liability company, is registered as an investment adviser under the Investment Advisers Act of 1940 (“Advisers Act”) and serves as investment adviser to each Fund. The Advisor has retained AER as subadvisor to the Initial AER Funds and Invesco as subadviser to the Initial Invesco Funds, and may in the future retain other subadvisers (together with AER and Invesco, the “Fund Subadvisors”) to manage the portfolios of other Funds. AER, a New Hampshire corporation, and Invesco, a Delaware corporation, are registered under the Advisers Act, and any other Fund Subadvisor will be registered under the Advisers Act. The Distributor, a Delaware corporation, is registered as a broker-dealer under the Securities Exchange Act of 1934 (“Exchange Act”) and serves as the principal underwriter and distributor for the Funds. Each of the Advisor, Invesco and the Distributor is an indirect wholly-owned subsidiary of Invesco PLC, a public limited company organized in the United Kingdom.
4. Shares of the Funds will be sold at a price of between $50 and $60 per Share in Creation Units of between 50,000 and 100,000 Shares. All orders to purchase Creation Units must be placed with the Distributor by or through a party that has entered into an agreement with the Trust and the Distributor (“Authorized Participant”). An Authorized Participant must be either: (a) A broker-dealer or other participant in the continuous net settlement system of the National Securities Clearing Corporation (“NSCC”), a clearing agency registered with the Commission, or (b) a participant in the Depository Trust Company (“DTC,” and such participant, “DTC Participant”). Shares of each Fund generally will be sold in Creation Units in exchange for an in-kind deposit by the purchaser of a portfolio of securities designated by the Advisor (the “Deposit Securities”), together with the deposit of a relatively small specified cash payment (“Cash Component”). The Cash Component is an amount equal to the difference between (a) the net asset value (“NAV”) per Creation Unit of the Fund and (b) the total aggregate market value per Creation Unit of the Deposit Securities.
5. An investor purchasing a Creation Unit from a Fund will be charged a fee (“Transaction Fee”) to prevent the dilution of the interests of the remaining shareholders resulting from costs in connection with the purchase of Creation Units.
6. Purchasers of Shares in Creation Units may hold such Shares or may sell such Shares into the secondary market. Shares will be listed and traded on a national securities exchange as defined in section 2(a)(26) of the Act (“Stock Exchange”). It is expected that one or more member firms of a listing Stock Exchange will be designated to act as a specialist and maintain a market for Shares on the Stock Exchange (the “Specialist”), or if Nasdaq is the listing Stock Exchange, one or more member firms of Nasdaq will act as a market maker (“Market Maker”) and maintain a market for Shares.
7. Applicants expect that purchasers of Creation Units will include institutional investors and arbitrageurs (which could include institutional investors). The Specialist, or Market Maker, in providing a fair and orderly secondary market for the Shares, also may purchase Creation Units for use in its market-making activities. Applicants expect that secondary market purchasers of Shares will include both institutional investors and retail investors.
8. Shares will not be individually redeemable, and owners of Shares may acquire those Shares from a Fund, or tender such Shares for redemption to the Fund, in Creation Units only. To redeem, an investor will have to accumulate enough Shares to constitute a Creation Unit. Redemption orders must be placed by or through an Authorized Participant. An investor redeeming a Creation Unit generally will receive (a) a portfolio of securities designated to be delivered for Creation Unit redemptions on the date that the request for redemption is submitted (“Fund Securities”), which may not be identical to the Deposit Securities required to purchase Creation Units on that date, and (b) a “Cash Redemption Payment,” consisting of an amount calculated in the same manner as the Cash Component, although the actual amount of the Cash Redemption Payment may differ from the Cash Component if the Fund Securities are not identical to the Deposit Securities on that day. An investor may receive the cash equivalent of a Fund Security in certain circumstances, such as if the investor is constrained from effecting transactions in the security by regulation or policy. A redeeming investor may pay a Transaction Fee, calculated in the same manner as a Transaction Fee payable in connection with purchases of Creation Units.
9. Neither the Trust nor any individual Fund will be marketed or otherwise held out as an “open-end investment company” or a “mutual fund.” Instead, each Fund will be marketed as an “actively-managed exchange-traded fund.” All marketing materials that describe the method of obtaining, buying or selling Shares, or refer to redeemability, will prominently disclose that Shares are not individually redeemable and that the owners of Shares may purchase or redeem Shares from a Fund in Creation Units only. The same approach will be followed in the SAI, shareholder reports and investor educational materials issued or circulated in connection with the Shares. The Funds will provide copies of their annual and semi-annual shareholder reports to DTC Participants for distribution to beneficial owners of Shares.
10. The Funds' Web site, which will be publicly available prior to the public offering of Shares, will include the Prospectus and other information about the Funds that is updated on a daily basis, including the mid-point of the bid-ask spread at the time of the calculation of NAV (“Bid/Ask Price”). On each Business Day, before the commencement of trading in Shares on the Stock Exchange, each Fund will disclose the identities and quantities of the securities (“Portfolio Securities”) and other assets held in the Fund portfolio that will form the basis for the Fund's calculation of NAV at the end of the Business Day.
1. Applicants request an order under section 6(c) of the Act granting an exemption from sections 2(a)(32), 5(a)(1) and 22(d) of the Act and rule 22c-1 under the Act; and under sections 6(c) and 17(b) of the Act granting an exemption from sections 17(a)(1) and (a)(2) of the Act, and under section 12(d)(1)(J) for an exemption from sections 12(d)(1)(A) and (B) of the Act.
2. Section 6(c) of the Act provides that the Commission may exempt any person, security or transaction, or any class of persons, securities or transactions, from any provision of the Act, if and to the extent that such exemption is necessary or appropriate in the public interest and consistent with the protection of investors and the purposes fairly intended by the policy and provisions of the Act. Section 17(b) of the Act authorizes the Commission to exempt a proposed transaction from section 17(a) of the Act if evidence establishes that the terms of the transaction, including the consideration to be paid or received, are reasonable and fair and do not involve overreaching on the part of any person concerned, and the proposed
3. Section 5(a)(1) of the Act defines an “open-end company” as a management investment company that is offering for sale or has outstanding any redeemable security of which it is the issuer. Section 2(a)(32) of the Act defines a redeemable security as any security, other than short-term paper, under the terms of which the holder, upon its presentation to the issuer, is entitled to receive approximately his proportionate share of the issuer's current net assets, or the cash equivalent. Because Shares will not be individually redeemable, applicants request an order that would permit each Fund, as a series of an open-end management investment company, to issue Shares that are redeemable in Creation Units only. Applicants state that investors may purchase Shares in Creation Units from each Fund and redeem Creation Units from each Fund. Applicants further state that because the market price of Shares will be disciplined by arbitrage opportunities, investors should be able to sell Shares in the secondary market at prices that do not vary substantially from their NAV.
4. Section 22(d) of the Act, among other things, prohibits a dealer from selling a redeemable security, which is currently being offered to the public by or through a principal underwriter, except at a current public offering price described in the prospectus. Rule 22c-1 under the Act generally requires that a dealer selling, redeeming, or repurchasing a redeemable security do so only at a price based on its NAV. Applicants state that secondary market trading in Shares will take place at negotiated prices, not at a current offering price described in the prospectus, and not at a price based on NAV. Thus, purchases and sales of Shares in the secondary market will not comply with section 22(d) of the Act and rule 22c-1 under the Act. Applicants request an exemption under section 6(c) from these provisions.
5. Applicants assert that the concerns sought to be addressed by section 22(d) of the Act and rule 22c-1 under the Act with respect to pricing are equally satisfied by the proposed method of pricing Shares. Applicants maintain that while there is little legislative history regarding section 22(d), its provisions, as well as those of rule 22c-1, appear to have been designed to (a) prevent dilution caused by certain riskless-trading schemes by principal underwriters and contract dealers, (b) prevent unjust discrimination or preferential treatment among buyers resulting from sales at different prices, and (c) assure an orderly distribution of investment company shares by eliminating price competition from dealers offering shares at less than the published sales price and repurchasing shares at more than the published redemption price.
6. Applicants believe that none of these purposes will be thwarted by permitting Shares to trade in the secondary market at negotiated prices. Applicants state that (a) secondary market trading in Shares does not involve the Funds as parties and cannot result in dilution of an investment in Shares, and (b) to the extent different prices exist during a given trading day, or from day to day, such variances occur as a result of third-party market forces, such as supply and demand. Therefore, applicants assert that secondary market transactions in Shares will not lead to discrimination or preferential treatment among purchasers. Finally, applicants contend that the proposed distribution system will be orderly because arbitrage activity will ensure that the difference between the market price of Shares and their NAV remains narrow.
7. Section 12(d)(1)(A) of the Act prohibits a registered investment company from acquiring shares of an investment company if the securities represent more than 3% of the total outstanding voting stock of the acquired company, more than 5% of the total assets of the acquiring company, or, together with the securities of any other investment companies, more than 10% of the total assets of the acquiring company. Section 12(d)(1)(B) of the Act prohibits a registered open-end investment company, its principal underwriter, or any other broker or dealer from selling its shares to another investment company if the sale will cause the acquiring company to own more than 3% of the acquired company's voting stock, or if the sale will cause more than 10% of the acquired company's voting stock to be owned by investment companies generally.
8. Applicants request that the order permit certain investment companies registered under the Act to acquire Shares beyond the limitations in section 12(d)(1)(A) and permit the Funds, any principal underwriter for the Funds, and any broker or dealer registered under the Exchange Act (“Brokers”), to sell Shares beyond the limitations in section 12(d)(1)(B). Applicants request that these exemptions apply to: (1) Any Fund that is currently or subsequently part of the same “group of investment companies” as the Initial Funds within the meaning of section 12(d)(1)(G)(ii) of the Act as well as any principal underwriter for the Funds and any Brokers selling Shares of a Fund to an Investing Fund (as defined below); and (2) each management investment company or unit investment trust registered under the Act that is not part of the same “group of investment companies” as the Funds within the meaning of section 12(d)(1)(G)(ii) of the Act and that enters into a FOF Participation Agreement (as defined below) with a Fund (such management investment companies are referred to herein as “Investing Management Companies,” such unit investment trusts are referred to herein as “Investing Trusts,” and Investing Management Companies and Investing Trusts are “Investing Funds”). Investing Funds do not include the Funds. Each Investing Trust will have a sponsor (“Sponsor”) and each Investing Management Company will have an investment adviser within the meaning of section 2(a)(20)(A) of the Act (“Investing Fund Advisor”) that does not control, is not controlled by or under common control with the Advisor. Each Investing Management Company may also have one or more investment advisers within the meaning of section 2(a)(20)(B) of the Act (each, a “Subadvisor”).
9. Applicants assert that the proposed transactions will not lead to any of the abuses that section 12(d)(1) was designed to prevent. Applicants submit that the proposed conditions to the requested relief address the concerns underlying the limits in section 12(d)(1), which include concerns about undue influence, excessive layering of fees and overly complex structures.
10. Applicants believe that neither the Investing Funds nor an Investing Fund Affiliate would be able to exert undue influence over the Funds.
11. Applicants propose other conditions to limit the potential for undue influence over the Funds, including that no Investing Fund or Investing Fund Affiliate (except to the extent it is acting in its capacity as an investment adviser to a Fund) will cause a Fund to purchase a security in any offering of securities during the existence of any underwriting or selling syndicate of which a principal underwriter is an Underwriting Affiliate (“Affiliated Underwriting”). An “Underwriting Affiliate” is a principal underwriter in any underwriting or selling syndicate that is an officer, director, member of an advisory board, Investing Fund Advisor, Subadvisor, employee or Sponsor of an Investing Fund, or a person of which any such officer, director, member of an advisory board, Investing Fund Advisor, Subadvisor, employee, or Sponsor is an affiliated person (except any person whose relationship to the Fund is covered by section 10(f) of the Act is not an Underwriting Affiliate).
12. Applicants do not believe that the proposed arrangement will involve excessive layering of fees. The board of directors or trustees of each Investing Management Company, including a majority of the disinterested directors or trustees, before approving any advisory contract under section 15 of the Act, will be required to determine that the advisory fees charged to the Investing Management Company are based on services provided that will be in addition to, rather than duplicative of, the services provided under the advisory contract(s) of any Fund in which the Investing Management Company may invest. In addition, the Investing Fund Advisor, trustee of an Investing Trust (“Trustee”) or Sponsor, as applicable, will waive fees otherwise payable to it by the Investing Fund in an amount at least equal to any compensation received from a Fund by the Investing Fund Advisor, Trustee or Sponsor, or an affiliated person of the Investing Fund Advisor, Trustee or Sponsor (other than any advisory fees), in connection with the investment by the Investing Fund in the Funds. Applicants also state that any sales charges and/or service fees charged with respect to shares of an Investing Fund will not exceed the limits applicable to a fund of funds set forth in Conduct Rule 2830 of the NASD (“Rule 2830”).
13. Applicants submit that the proposed arrangement will not create an overly complex fund structure. Applicants note that a Fund will be prohibited from acquiring securities of any investment company, or of any company relying on section 3(c)(1) or 3(c)(7) of the Act, in excess of the limits contained in section 12(d)(1)(A) of the Act.
14. To ensure that Investing Funds are aware of the terms and conditions of the requested order, the Investing Funds must enter into an agreement with the respective Funds (“FOF Participation Agreement”). The FOF Participation Agreement will include an acknowledgement from the Investing Fund that it may rely on the order only to invest in the Funds and not in any other investment company. The FOF Participation Agreement will further require any Investing Fund that exceeds the 5% or 10% limitations in section 12(d)(1)(A)(ii) and (iii) to disclose in its Prospectus that it may invest in ETFs and disclose, in “plain English,” in its Prospectus the unique characteristics of the Investing Funds investing in investment companies, including but not limited to the expense structure and any additional expenses of investing in investment companies.
15. Section 17(a)(1) and (2) of the Act generally prohibit an affiliated person of a registered investment company, or an affiliated person of such a person (“second tier affiliate”), from selling any security to or purchasing any security from the company. Section 2(a)(3) of the Act defines “affiliated person” to include any person directly or indirectly owning, controlling, or holding with power to vote 5% or more of the outstanding voting securities of the other person and any person directly or indirectly controlling, controlled by, or under common control with, the other person. Section 2(a)(9) of the Act provides that a control relationship will be presumed where one person owns more than 25% of another person's voting securities. The Funds may be deemed to be controlled by the Advisor or an entity controlling, controlled by or under common control with the Adviser and hence affiliated persons of each other. In addition, the Funds may be deemed to be under common control with any other registered investment company (or series thereof) advised by the Advisor or an entity controlling, controlled by or under common control with the Advisor (an “Affiliated Fund”). Applicants state that because the definition of “affiliated person” includes any person owning 5% or more of an issuer's outstanding voting securities, every purchaser of a Creation Unit will be affiliated with the Fund so long as fewer than twenty Creation Units are in existence, and any purchaser that owns more than 25% of a Fund's outstanding Shares will be affiliated with a Fund.
16. Applicants request an exemption from section 17(a) under sections 6(c) and 17(b), to permit in-kind purchases and redemptions by persons that are affiliated persons or second tier affiliates of the Funds solely by virtue of one or more of the following: (1) Holding 5% or more, or more than 25%, of the outstanding Shares of the Trust or one or more Funds; (2) an affiliation with a person with an ownership interest described in (1); or (3) holding 5% or more, or more than 25%, of the shares of one or more Affiliated Funds. Applicants also request an exemption in order to permit each Fund to sell Shares to and redeem Shares from, and engage in the in-kind transactions that would accompany such sales and redemptions with, any Investing Fund of which it is an affiliated person or second tier affiliate because of one or more of the following: (1) The Investing Fund holds 5% or more of the Shares of the Trust or one or more Funds; (2) an Investing Fund described in (1) is an affiliated person of the Investing Fund; or (3) the Investing Fund holds 5% or more of the shares of one or more Affiliated Funds.
17. Applicants contend that no useful purpose would be served by prohibiting affiliated persons or second tier affiliates of a Fund from purchasing or redeeming Creation Units through “in-kind” transactions. The deposit procedure for in-kind purchases and the redemption procedure for in-kind redemptions will be the same for all purchases and redemptions. Deposit Securities and Fund Securities will be valued under the same objective standards applied to valuing Portfolio Securities. Therefore, applicants state that in-kind purchases and redemptions will afford no opportunity for the affiliated persons and second tier affiliates described above to effect a transaction detrimental to the other holders of Shares. Applicants also believe that in-kind purchases and redemptions will not result in abusive self-dealing or overreaching by these persons of the Fund.
18. Applicants also submit that the sale of Shares to and redemption of Shares from an Investing Fund satisfies the standards for relief under sections 17(b) and 6(c) of the Act. Applicants note that the consideration paid for the purchase or received for the redemption of Shares directly from a Fund by an Investing Fund (or any other investor) will be based on the NAV of the Shares. In addition, the securities received or transferred by the Fund in connection with the purchase or redemption of Shares will be valued in the same manner as the Fund's Portfolio Securities and thus the transactions will not be detrimental to the Investing Fund. Applicants also state that the proposed transactions will be consistent with the policies of each Investing Fund and Fund and with the general purposes of the Act. Applicants state that the FOF Participation Agreement will require an Investing Fund to represent that its ownership of Shares issued by a Fund is consistent with the investment policies set forth in the Investing Fund's registration statement.
The applicants agree that any order of the Commission granting the requested relief will be subject to the following conditions:
1. Each Prospectus will clearly disclose that, for purposes of the Act, Shares are issued by a registered investment company and that the acquisition of Shares by investment companies and companies relying on sections 3(c)(1) or 3(c)(7) of the Act is subject to the restrictions of section 12(d)(1) of the Act, except as permitted by an exemptive order that permits registered investment companies to invest in a Fund beyond the limits in section 12(d)(1), subject to certain terms and conditions, including that the registered investment company enter into a FOF Participation Agreement with the Fund regarding the terms of the investment.
2. As long as the Funds operate in reliance on the requested order, the Shares of the Funds will be listed on a Stock Exchange.
3. Neither the Trust nor any Fund will be advertised or marketed as an open-end investment company or a mutual fund. Each Fund's Prospectus will prominently disclose that the Fund is an actively managed exchange-traded fund. Each Prospectus will prominently disclose that the Shares are not individually redeemable shares and will disclose that the owners of the Shares may acquire those Shares from the Fund and tender those Shares for redemption to the Fund in Creation Units only. Any advertising material that describes the purchase or sale of Creation Units or refers to redeemability will prominently disclose that the Shares are not individually redeemable and that owners of the Shares may acquire those Shares from the Fund and tender those Shares for redemption to the Fund in Creation Units only.
4. The website for the Funds, which is and will be publicly accessible at no charge, will contain the following information, on a per Share basis, for each Fund: (a) the prior Business Day's NAV and the Bid/Ask Price, and a calculation of the premium or discount of the Bid/Ask Price against such NAV; and (b) data in chart format displaying the frequency distribution of discounts and premiums of the daily Bid/Ask Price against the NAV, within appropriate ranges, for each of the four previous calendar quarters (or for the life of the Fund, if shorter).
5. The Prospectus and annual report for each Fund will also include: (a) the information listed in condition A.4(b), (i) in the case of the Prospectus, for the most recently completed year (and the most recently completed quarter or quarters, as applicable) and (ii) in the case of the annual report, for the immediately preceding five years (or for the life of the Fund, if shorter), and (b) calculated on a per Share basis for one-, five- and ten-year periods (or for the life of the Fund, if shorter), the cumulative total return and the average annual total return based on NAV and Bid/Ask Price.
6. On each Business Day, before commencement of trading in Shares on the Stock Exchange, the Fund will disclose on its website the identities and quantities of the Portfolio Securities and other assets held by the Fund that will form the basis for the Fund's calculation of NAV at the end of the Business Day.
7. The Advisor or Fund Subadvisor, directly or indirectly, will not cause any Authorized Participant (or any investor on whose behalf an Authorized Participant may transact with the Fund) to acquire any Deposit Security for the Fund through a transaction in which the Fund could not engage directly.
8. The requested order will expire on the effective date of any Commission rule under the Act that provides relief permitting the operation of actively managed exchange-traded funds.
1. The members of the Investing Fund's Advisory Group will not control (individually or in the aggregate) a Fund within the meaning of section 2(a)(9) of the 1940 Act. The members of the Investing Fund's Subadvisory Group will not control (individually or in the aggregate) a Fund within the meaning of section 2(a)(9) of the 1940 Act. If, as a result of a decrease in the outstanding voting securities of a Fund, the Investing Fund's Advisory Group or the Investing Fund's Subadvisory Group, each in the aggregate, becomes a holder of more than 25 percent of the outstanding voting securities of a Fund, it will vote its Shares of the Fund in the same proportion as the vote of all other holders of the Fund's Shares. This condition does not apply to the Investing Fund's Subadvisory Group with respect to a Fund for which the Subadvisor or a person controlling, controlled by or under common control with the Subadvisor acts as the investment adviser within the meaning of section 2(a)(20)(A) of the Act.
2. No Investing Fund or Investing Fund Affiliate will cause any existing or potential investment by the Investing Fund in a Fund to influence the terms of any services or transactions between the Investing Fund or an Investing Fund Affiliate and the Fund or a Fund Affiliate.
3. The board of directors or trustees of an Investing Management Company, including a majority of the disinterested directors or trustees, will adopt procedures reasonably designed to assure that the Investing Fund Advisor and any Subadvisor are conducting the investment program of the Investing Management Company without taking
4. Once an investment by an Investing Fund in the securities of a Fund exceeds the limit in section l2(d)(1)(A)(i) of the Act, the board of trustees (“Board”) of a Fund, including a majority of the disinterested Board members, will determine that any consideration paid by the Fund to the Investing Fund or an Investing Fund Affiliate in connection with any services or transactions: (i) Is fair and reasonable in relation to the nature and quality of the services and benefits received by the Fund; (ii) is within the range of consideration that the Fund would be required to pay to another unaffiliated entity in connection with the same services or transactions; and (iii) does not involve overreaching on the part of any person concerned. This condition does not apply with respect to any services or transactions between a Fund and its investment adviser(s), or any person controlling, controlled by or under common control with such investment adviser(s).
5. The Investing Fund Advisor, or Trustee or Sponsor, as applicable, will waive fees otherwise payable to it by the Investing Fund in an amount at least equal to any compensation (including fees received pursuant to any plan adopted by a Fund under rule 12b-l under the Act) received from a Fund by the Investing Fund Advisor, or Trustee or Sponsor, or an affiliated person of the Investing Fund Advisor, or Trustee or Sponsor, other than any advisory fees paid to the Investing Fund Advisor, or Trustee or Sponsor, or its affiliated person by the Fund, in connection with the investment by the Investing Fund in the Fund. Any Subadvisor will waive fees otherwise payable to the Subadvisor, directly or indirectly, by the Investing Management Company in an amount at least equal to any compensation received from a Fund by the Subadvisor, or an affiliated person of the Subadvisor, other than any advisory fees paid to the Subadvisor or its affiliated person by the Fund, in connection with the investment by the Investing Management Company in the Fund made at the direction of the Subadvisor. In the event that the Subadvisor waives fees, the benefit of the waiver will be passed through to the Investing Management Company.
6. No Investing Fund or Investing Fund Affiliate (except to the extent it is acting in its capacity as an investment adviser to a Fund) will cause a Fund to purchase a security in an Affiliated Underwriting.
7. The Board of the Fund, including a majority of the disinterested Board members, will adopt procedures reasonably designed to monitor any purchases of securities by the Fund in an Affiliated Underwriting, once an investment by an Investing Fund in the securities of the Fund exceeds the limit of section 12(d)(1)(A)(i) of the Act, including any purchases made directly from an Underwriting Affiliate. The Board will review these purchases periodically, but no less frequently than annually, to determine whether the purchases were influenced by the investment by the Investing Fund in the Fund. The Board will consider, among other things: (i) Whether the purchases were consistent with the investment objectives and policies of the Fund; (ii) how the performance of securities purchased in an Affiliated Underwriting compares to the performance of comparable securities purchased during a comparable period of time in underwritings other than Affiliated Underwritings or to a benchmark such as a comparable market index; and (iii) whether the amount of securities purchased by the Fund in Affiliated Underwritings and the amount purchased directly from an Underwriting Affiliate have changed significantly from prior years. The Board will take any appropriate actions based on its review, including, if appropriate, the institution of procedures designed to assure that purchases of securities in Affiliated Underwritings are in the best interest of shareholders.
8. Each Fund will maintain and preserve permanently in an easily accessible place a written copy of the procedures described in the preceding condition, and any modifications to such procedures, and will maintain and preserve for a period of not less than six years from the end of the fiscal year in which any purchase in an Affiliated Underwriting occurred, the first two years in an easily accessible place, a written record of each purchase of securities in Affiliated Underwritings once an investment by an Investing Fund in the securities of the Fund exceeds the limit of section 12(d)(1)(A)(i) of the 1940 Act, setting forth from whom the securities were acquired, the identity of the underwriting syndicate's members, the terms of the purchase, and the information or materials upon which the Board's determinations were made.
9. Before investing in a Fund in excess of the limit in section 12(d)(1)(A), an Investing Fund will execute a FOF Participation Agreement with the Fund stating that their respective boards of directors or trustees and their investment advisors, or Trustee and Sponsor, as applicable, understand the terms and conditions of the order, and agree to fulfill their responsibilities under the order. At the time of its investment in shares of a Fund in excess of the limit in section 12(d)(1)(A)(i), an Investing Fund will notify the Fund of the investment. At such time, the Investing Fund will also transmit to the Fund a list of the names of each Investing Fund Affiliate and Underwriting Affiliate. The Investing Fund will notify the Fund of any changes to the list as soon as reasonably practicable after a change occurs. The Fund and the Investing Fund will maintain and preserve a copy of the order, the FOF Participation Agreement, and the list with any updated information for the duration of the investment and for a period of not less than six years thereafter, the first two years in an easily accessible place.
10. Before approving any advisory contract under section 15 of the Act, the board of directors or trustees of each Investing Management Company, including a majority of the disinterested directors or trustees, will find that the advisory fees charged under such contract are based on services provided that will be in addition to, rather than duplicative of, the services provided under the advisory contract(s) of any Fund in which the Investing Management Company may invest. These findings and their basis will be recorded fully in the minute books of the appropriate Investing Management Company.
11. Any sales charges and/or service fees charged with respect to shares of an Investing Fund will not exceed the limits applicable to a fund of funds as set forth in Rule 2830.
12. No Fund will acquire securities of any investment company or company relying on section 3(c)(1) or 3(c)(7) of the Act in excess of the limits contained in section 12(d)(1)(A) of the Act.
By the Commission.
On December 19, 2007, the American Stock Exchange LLC (“Amex” or “Exchange”) filed with the Securities and Exchange Commission (“Commission”), pursuant to section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange proposes to create a new class of off-floor market makers in ETF securities and to make related changes to the Exchange's AEMI trading platform.
A DART will be a member or member organization physically located off-floor that will electronically enter competitive quotations into AEMI on a regular basis in all ETF securities to which it is assigned in the DARTs program. A DART may be either a regular or associate member of the Exchange that meets the requirements for electronic access to the Exchange's automated systems. The proposed DARTs program is similar to the Supplemental Registered Options Traders (“SROT”) program implemented by the Amex for options,
Amex's rules already provide for one type of competing market maker in ETF securities—Registered Traders. A Registered Trader is a member who is authorized to initiate trades in certain securities
Due to their lack of a physical presence in the trading crowd, which is a basic requirement of the auction market, DARTs will not participate in any post-trade allocation in connection with an auction trade. Instead, a DART's participation in an auction pair-off on the Exchange will be limited to the marketable amount of its quotation on the AEMI Book at the time of the pair-off. For purposes of the priority and parity rules of Rule 126-AEMI, a DART's quotation would be treated as another crowd order, similar to a Registered Trader.
Amex will establish minimum requirements for a DART to remain in the program, which may be modified by the Exchange from time to time. First, a DART must provide competitive quotations on a regular basis to satisfy market maker regulatory requirements.
In addition to the requirements described above, a DART will be required to meet eligibility criteria similar to those specified in the SROT program, which will include:
• Adequacy of resources including capital, technology, and personnel;
• History of stability, superior electronic capacity, and superior operational capacity;
• Level of market-making and/or specialist experience in a broad array of securities;
• Ability to interact with order flow in all types of markets;
• Existence of order flow commitments;
• Willingness and ability to make competitive markets on the Exchange and otherwise promote the Exchange in a manner that is likely to enhance the ability of the Exchange to compete successfully for order flow in the ETF securities it trades;
• The number of member organizations requesting approval to act as a DART; and
• Ability to transact in any ETF underlying markets.
The regulatory requirements applicable to DARTs will be surveilled for by the FINRA Amex Regulation Division (“FINRA Amex”) consistent with current surveillance procedures for Registered Traders on the Exchange. FINRA Amex staff will work with Amex technical staff on planning the necessary changes to AEMI to capture required surveillance data and surveilling the increased number of market makers that the program is expected to attract. Adjustments to current technology and surveillance procedures will likely also be necessitated by the fact that DARTs will not be physically located on the floor of the Exchange.
DARTs will interface with the Amex's Floor Officials in the case of trade disputes substantially in accordance with existing procedures used for SROTs. Each DART accordingly will be required to designate persons on and/or off-floor to be in direct real-time contact with Floor Officials on such matters. Regulation M will apply to DARTs in the same way that it applies to other market participants, as will Amex Rule 193 to the extent a DART is affiliated with a specialist member organization. However, no expansion of the application of Amex Rule 193 beyond current practice is intended.
Finally, the Comment Letter had observed that a provision proposed in SR-Amex-2007-85 relating to minimum capital requirements for DARTs is unnecessary due to its current inapplicability to DARTs (who will be subject to the Commission's net capital rule).
After careful review, the Commission finds that the proposed rule change is consistent with the requirements of the Act and the rules and regulations thereunder applicable to a national securities exchange.
Under the proposal, DARTs would be permitted to quote electronically in ETFs from off the Exchange's physical trading floor. Amex's rules already provide for one type of competing market maker in ETF securities—Registered Traders. Like Registered Traders, DARTs will not be permitted to enter quotations in equity securities. In addition, similar rules would govern the allocations of DARTs and Registered Traders, except DARTs will not be permitted to participate in a post-trade allocation in connection with an auction trade. The Commission believes it is reasonable and consistent with the Act for Amex to establish DARTs as remote competitive market makers subject to the allocation rules described in the proposal.
The Commission notes that DARTs will be required to meet certain eligibility requirements. The existence of order flow commitments between a DART applicant and order flow providers is one such factor. The Commission notes the Exchange's representation that a future change to, or termination of, any such commitments would not be used by the Exchange at any point in the future to terminate or take remedial action against a DART, and that the Exchange would not take remedial action solely because orders subject to any such commitments were not subsequently routed to the Exchange. Similarly, the Exchange has included the “willingness to promote the Exchange” as a factor that the Committee may consider when making its application decisions. The Commission notes the Exchange's representation that the Committee would not apply this factor to in any way restrict, either directly or indirectly, a DART's activities as a market maker or specialist on other exchanges, or to restrict how a DART handles orders it holds in a fiduciary capacity to which it owes a duty of best execution.
The Commission also notes that, should the Committee decide not to approve a DART applicant, or should a DART's appointment be suspended or terminated in one or more classes, a DART applicant or DART, respectively, would be entitled to a hearing under Article IV, section 1(g) of the Amex Constitution and Amex Rule 40.
Proposed Amex Rule 110A(b)-AEMI sets forth the obligations that a DART would be required to fulfill. Specifically, a DART would be required to generate continuous, two-sided quotations in all assigned ETF securities. A DART's affirmative market making obligations appear to be sufficient to justify the benefits it would receive as a market maker.
The proposal also appears reasonably designed to prevent the misuse of material, non-public information with any affiliates that may conduct a brokerage business in securities assigned to a DART, or that may act as a specialist or market maker in any security underlying a derivative security assigned to a DART.
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 amend its rules relating to the usage of its holdback timer. The text of the proposed rule change is available at CBOE, the Commission's Public Reference Room, and
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 proposal. The text of these statements may be examined at the places specified in Item IV below. CBOE has prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements.
On May 16, 2007, the Commission approved CBOE's proposed rule change, which implemented an additional quote mitigation strategy, namely, a holdback timer.
CBOE now proposes to clarify that it may utilize the holdback timer in any option classes traded on CBOE, including option classes traded on the Hybrid 3.0 Platform. CBOE believes that the holdback timer is an appropriate and useful tool in mitigating quotations, as it reduces the number of quotations that CBOE disseminates to OPRA, without negatively impacting transparency. CBOE also notes that the holdback timer has been endorsed by the Securities Information and Financial Markets Association. CBOE is not proposing to change the manner in which the holdback timer functions, as described in its original rule filing SR-CBOE-2007-45.
The Exchange believes that its proposal 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 that is not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were either solicited or received by the Exchange.
The proposed rule change has become effective pursuant to Section 19(b)(3)(A) of the Act
A proposed rule change filed under Rule 19b-4(f)(6) normally may not become operative prior to 30-days after the date of filing.
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 Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange proposes to adopt a voluntary professional designation. The text of the proposed rule change is available at CBOE, the Commission's Public Reference Room, and
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. CBOE has prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements.
This filing proposes to allow non-broker-dealer customers to voluntarily have their orders categorized as broker-dealer orders for order handling, order execution, and cancel fee calculation purposes (“Voluntary Professional(s)”). Specifically, these orders would be treated as broker-dealer orders for purposes of CBOE Rules 6.13 (CBOE Hybrid System's Automatic Execution Feature), 6.45 (Priority of Bids and Offers—Allocation of Trades), 6.45A (Priority and Allocation of Equity Option Trades on the CBOE Hybrid System), 6.45B (Priority and Allocation of Trades in Index Options and Options on ETFs on the CBOE Hybrid System), and 6.53C (Complex Orders on the Hybrid System).
Some Exchange users have requested this flexibility because it is more suitable to their trading strategies that involve high volume order submission and cancellation. These Voluntary Professionals would participate on trades on the same terms as broker-dealer orders for purposes of the rules set forth above. Orders from Voluntary Professionals would continue to be treated as public customer orders for purposes of the linkage-related rules. CBOE would provide the same away-market protection for orders from Voluntary Professionals as for orders from public customers. Additionally, orders from Voluntary Professionals that are cancelled would not be counted as public customer order cancellations in connection with the cancellation fee calculation applicable to clearing members. The Exchange intends to establish, via a separate rule filing under Section 19(b) of the Act, a transaction fee applicable to Voluntary Professionals and the Exchange would not commence the Voluntary Professional program until such fee was in place.
The Exchange believes that the proposed rule change is consistent with 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.
No written comments were solicited or received with respect to 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 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 Trading and Markets, pursuant to delegated authority.
On November 1, 2007, the Financial Industry Regulatory Authority, Inc. (“FINRA”) (f/k/a National Association of Securities Dealers, Inc. (“NASD”)) filed with the Securities and Exchange Commission (“Commission”) pursuant to section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The proposed rule change amends NASD Rule 2210 (Communications with the Public) to create an exception from the principal approval requirements for certain filed sales material.
NASD Rule 2210 (Communications with the Public) requires that a registered principal of a FINRA member firm approve in writing all advertisements, sales literature, and independently prepared reprints (collectively, “sales material”) prior to use. Certain types of sales materials, such as advertisements and sales literature concerning mutual funds or variable insurance products must be filed with the FINRA Advertising Regulation Department (“Department”).
For funds and variable products that are sold through intermediary firms, a registered principal at the fund's or variable product's underwriter typically approves sales material internally and files the material with the Department. FINRA rules require registered principals at each of the intermediary firms that use the underwriter's sales material to re-approve in writing each of these items used by their firms. (The intermediary firm is not required to re-file the sales material with the Department so long as it is used without material change.) If firms have selling agreements with multiple fund families and insurance companies, the number of items that require re-approval can easily be in the hundreds, and often thousands, per firm annually.
Based on recommendations made by its Small Firms Rules Impact Task Force,
The intermediary firm that relies on this exception could not materially alter the sales material or use it in a manner that is inconsistent with any conditions stated in the Department's review letter. For example, if the Department's review letter was based in part upon the representation by the filing firm that the sales material would be accompanied by a fund prospectus, the intermediary firm would be subject to a similar constraint.
Although FINRA anticipates that firms will utilize the exception primarily with respect to mutual fund and variable insurance product sales material, the exception is not limited to sales material for particular products. Thus, the exception also would apply to sales material for other products, such as real estate investment trusts or direct participation programs, provided the sales material meets the exception's requirements.
FINRA believes this exception would save intermediary firms' compliance personnel numerous hours that are currently spent reviewing sales material that has already been approved by a registered principal at the product underwriter, and that the Department staff also has reviewed and found to be consistent with applicable standards. Of course, some firms may want to continue to review this sales material, and the proposal would allow them to do so.
The proposed rule change would also revise certain of the advertising record-keeping requirements. Today, Rule 2210(b)(2)(A) states that firms must maintain a copy of all sales material for a period of three years from the date of last use. Existing practice has been to assume that the recordkeeping requirement begins on the date of first use. The proposal would codify this position. For sales material subject to the principal approval exception, firms would have to keep a record of the name of the firm that filed the sales material and a copy of the related FINRA review letter.
The Commission received three comment letters in response to the proposed rule change.
After careful review, the Commission finds that the proposed rule change is consistent with the requirements of the Act, and the rules and regulations thereunder that are applicable to a national securities association.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
FINRA is proposing to amend Schedule A to the FINRA By-Laws to amend the Gross Income Assessment (“GIA”) paid by each FINRA member and to update the references to NASD that appear in Schedule A to the FINRA By-Laws. The text of the proposed rule change is available at NASD, the Commission's Public Reference Room, and
In its filing with the Commission, FINRA 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. FINRA has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
On July 30, 2007, NASD and the New York Stock Exchange (“NYSE”) consolidated their member firm regulation operations into a combined organization, FINRA. The proposed rule change seeks to consolidate certain regulatory fees imposed by NASD and NYSE Regulation, Inc. (“NYSE Regulation”) to develop a single fee structure for FINRA that avoids duplicating fees charged by the two organizations.
FINRA's member regulatory pricing structure currently consists primarily of the following fees: the GIA; the Trading Activity Fee (“TAF”); the Personnel Assessment (“PA”); and the Branch Office Assessment (“BOA”). As part of the consolidation, NYSE committed to transfer to FINRA certain regulatory revenues for the remainder of 2007.
In anticipation of the termination of the agreement to remit fees collected by NYSE, FINRA evaluated whether to consolidate or eliminate any duplicative fees, as well as whether to maintain or increase any non-duplicative fees. FINRA undertook its regulatory pricing review with the objectives of maintaining a fair assessment level for firms and of preserving revenue levels necessary to fund FINRA's member regulatory activities, including the regulation of members through examination, policymaking, rulemaking and enforcement activities.
To achieve these objectives, FINRA determined that the most appropriate regulatory pricing structure would be to: (1) Eliminate NYSE Regulation's legacy registration fees for branch offices and registered representatives, which totals approximately $18.6 million in fee reductions;
The GIA is currently assessed through a three-tier rate structure with a minimum GIA of $1,200.00. Under the current GIA, members are required to pay an annual GIA equal to the greater of $1,200.00 or the total of:
(1) 0.125% of annual gross revenue less than or equal to $100 million;
(2) 0.029% of annual gross revenue greater than $100 million up to $1 billion; and
(3) 0.014% of annual gross revenue greater than $1 billion.
In contrast, the legacy GFF was assessed at a flat rate of $0.42 per $1,000 of gross FOCUS revenue (or 0.042%).
To consolidate these two legacy fees, FINRA proposes that the minimum assessment under the GIA of $1,200.00 will remain, with the ceiling increased from $960,000.00 to $1 million of annual assessable revenue. Because FINRA has committed to reduce the GIA by $1,200.00 per year for five years, subject to annual Board approval, this will effectively reduce the GIA to $0 for the first $1 million of annual assessable revenue. FINRA proposes that for annual gross revenue over $1 million, the regressive rate structure of the legacy GIA and the flat rate structure of the legacy GFF be combined into a new rate structure. Specifically, FINRA proposes to create a seven-tiered rate structure that balances the legacy GIA tiered rate structure with the legacy GFF flat rate structure.
Under the proposed rule change, members will be assessed a GIA of:
(1) $1,200 on annual gross revenue up to $1 million;
(2) 0.1215% of annual gross revenue greater than $1 million up to $25 million;
(3) 0.2599% of annual gross revenue greater than $25 million up to $50 million;
(4) 0.0518% of annual gross revenue greater than $50 million up to $100 million;
(5) 0.0365% of annual gross revenue greater than $100 million up to $5 billion;
(6) 0.0397% of annual gross revenue greater than $5 billion up to $25 billion; and
(7) 0.0855% of annual gross revenue greater than $25 billion.
FINRA estimates that the proposed rule change will result in aggregate fee reductions of approximately $25 million dollars in 2008 and forward, approximately $18.6 million of which relates to the elimination of NYSE Regulation's legacy registration fees and approximately $6.4 million for GIA rebates given to all FINRA member firms. FINRA estimates that, under the proposed rate structure described above, 93 percent of member firms will have either no change to their GIA or a reduced GIA due to this new rate structure. Certain firms with annual gross revenue exceeding $35 million dollars, however, will have an increase to their GIA under the proposed rate structure.
To minimize the impact on members, the new rate structure will be implemented over a three-year period beginning in 2008. During this period, the change in the GIA paid to FINRA by each member will be subject to a cap based on the fees that the member would have paid under the prior NASD and NYSE rate structures. In 2008, a member's GIA will not be impacted by the new rate structure. In 2009, any increase or decrease to the member's GIA resulting from the new rate structure will be capped at a five percent increase or decrease. In 2010, any increase or decrease to the member's GIA resulting from the new rate structure will be capped at a ten percent increase or decrease. During this implementation period, a firm's GIA
For firms that were members of NASD only (not NYSE) as of July 30, 2007, the cap will be calculated based upon the GIA that the member firm would have paid under the prior NASD GIA rate structure. For firms that became, or become, FINRA members on or after July 30, 2007 (excluding those firms that were members of NYSE only as of July 30, 2007 and were subsequently required to become FINRA members pursuant to NYSE Rule 2), the cap will be calculated based upon the GIA that the member firm would have paid under the prior NASD GIA rate structure. For firms that were members of the NYSE only (not NASD) as of July 30, 2007, the cap will be calculated based upon the NYSE GFF that the member would have paid under the prior NYSE GFF rate structure.
Despite the reduction in revenue that will result from the new rate structure, FINRA believes that the revenue collected under the pricing proposal will fund its member regulatory programs. The integration of the member firm regulation operations of NASD and NYSE into FINRA should take up to three years, given FINRA's need to establish a new examination and enforcement program under a consolidated rule book. A new cost structure and revised pricing structure will be evaluated once the integration is complete.
FINRA is proposing that the effective date of the proposed rule change will be retroactive to January 1, 2008. FINRA will announce the proposed rule change and subsequent approval in a
FINRA believes that the proposed rule change is consistent with the provisions of section 15A(b)(5) of the Act,
FINRA 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, 100 F Street, NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1)
FINRA is proposing to amend FINRA's NYSE Rules 421 (Periodic Reports), 440F (Public Short Sale Transactions Effected on the Exchange) and 440G (Transactions in Stock and Warrants for the Accounts of Members, Allied Members and Member Organizations)
Below is the text of the proposed rule change. Proposed new language is in italics; proposed deletions are in brackets.
No Change.
* * * Supplementary Material:
.10 Short positions.—Member organizations for which the Exchange is the designated examining authority are required to report “short” positions, including odd lots, in each stock or warrant listed on the Exchange, and in each other stock or warrant not listed on the Exchange which is not otherwise reported to another United States securities exchange or securities association, using such automated format and methods as prescribed by the Exchange. Such reports must include customer and proprietary positions and must be made at such times and covering such time period as may be designated by the Exchange.
Member organizations for which the Exchange is not the designated examining authority must report “short” positions to the self-regulatory organization which is its designated examining authority (“DEA”) if such DEA has a requirement for such reports. If the DEA does not have such a reporting requirement, then such member organization must comply with the provisions of Rule 421.
The term “designated examining authority” means the self-regulatory organization which has been assigned responsibility for examining a member organization for compliance with applicable financial responsibility rules. (See Rule 17d-1 under the Securities Exchange Act of 1934 (the “Exchange Act”).)
“Short” positions to be reported are those resulting from “short” sales as defined in Rule 200(a) of the Securities and Exchange Commission's Regulation SHO, but excluding positions
NOTE: A member organization which does not carry customers' margin accounts and does not clear its own transactions may obtain an exemption from reporting by notifying the Exchange in writing.
.20-.50 No Change.
* * * Supplementary Material:
.10 Requirements for filing. No Change.
General Instructions.—
(1)-(2) No Change.
(3) [Exclude short-exempt sales, except for short-exempt sales in securities subject to the SEC's Pilot Order (SEA Release No. 34-50104)(July 28, 2004), as amended by the SEC's Second Pilot Order (SEA Release No. 34-50747)(November 29, 2004), and any subsequent orders.
(4)] Exclude transactions in rights.
[(5)]
[(6)]
[(7)]
[(8)]
Specific Instructions.—
(1) No Change.
(2) Short sales for hedging accounts and short sales executed as such for arbitrage accounts should be included. [Sales made on a “short-exempt” basis for arbitrage accounts should not be included.]
(3) No Change.
* * * Supplementary Material:
.10 Requirements for filing. No Change.
Instructions.—
(1)-(8) No Change.
(9) [Short-exempt sales are to be included with total sales only. Solely for purposes of Rule 440G and Form 121, “short-exempt sales” in securities subject to the SEC's Pilot Order (SEA Release 34-50104)(July 28, 2004), as amended by the SEC's Second Pilot Order (SEA Release 34-50747)(November 29, 2004), and any subsequent orders, are to be included with short sales on Form 121.
(10)] Transactions are to be classified into one of the following three categories
(a)-(c) No Change.
[(11)]
[(12)]
[(13)]
[(14)]
[(15)]
In its filing with the Commission, FINRA 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. FINRA has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
FINRA is proposing changes to FINRA's NYSE Rules 421, 440F and 440G to conform these rules with the SEC's amendments to SEC Rule 10a-1 and Regulation SHO. The SEC's amendments, among other things, remove the short sale price test in SEC Rule 10a-1 and remove the “short exempt” marking requirements in Regulation SHO.
In light of the SEC's amendments, the NYSE has proposed amending its Rules 421,
Given these changes, FINRA is proposing to make conforming changes to FINRA's NYSE Rules 421, 440F and 440G to ensure consistency with NYSE's versions of Rules 421, 440F and 440G.
The proposed rule change is consistent with the provisions of Section 15A(b)(6) of the Act,
FINRA 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.
Because the foregoing proposed rule change does not: (i) Significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A) of the Act
FINRA has requested that the Commission waive the five-day pre-filing notice
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.
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 available publicly. All submissions should refer to File Number SR-FINRA-2007-025 and should be submitted on or before February 28, 2008.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The ISE is proposing to amend ISE Rules 713 (Priority of Quotes and Orders), 716 (Block Trades) and 723 (Price Improvement Mechanism for Crossing Transactions) to give certain non-broker-dealer orders the same priority as broker-dealer orders and market maker quotes. The ISE also proposes to charge the same fee for the execution of certain non-broker-dealer orders as is applicable to the execution of broker-dealer orders on the Exchange. The text of the proposed rule change is available on the Exchange's Web site (
In its filing with the Commission, the ISE 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 ISE has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
Under ISE rules, a “Public Customer” is any person or entity that is not a broker or dealer in securities, and a “Public Customer Order” is an order for the account of a Public Customer.
With respect to these ISE marketplace advantages, the Exchange does not believe the definitions of Public Customer and Non-Customer properly distinguish between non-professional retail investors and certain professionals. According to the Exchange, providing marketplace advantages based upon whether the order is for the account of a participant that is a registered broker-dealer is no longer appropriate in today's marketplace because some non-broker-dealer individuals and entities have access to information and technology that enables them to professionally trade listed options in the same manner as a broker or dealer in securities.
The Exchange therefore does not believe that it is consistent with fair competition for these professional account holders to continue to receive the same marketplace advantages as retail investors over broker-dealers trading on the ISE. Moreover, because Public Customer Orders at the same price are executed in time priority, retail investors are prevented from fully benefiting from the priority advantage when professional account holders are afforded Public Customer Order priority.
Accordingly, the Exchange is seeking to adopt two new terms that will be used to more appropriately provide ISE marketplace advantages to retail investors on the ISE. Under the proposal, execution priority under ISE Rules 713 (Priority of Quotes and Orders), 716 (Block Trades) and 723 (Price Improvement Mechanism for Crossing Transactions) will be given to “Priority Customer Orders” over “Professional Orders” and market maker quotes. Transaction fees will also be charged using these definitions. Specifically, the ISE will charge standard transaction fees currently applicable to broker-dealer orders for Professional Orders, and fee waivers currently available to Public Customer Orders will be limited to Priority Customer Orders. A Priority Customer Order will be defined as a person or entity that (i) is not a broker or dealer in securities, and (ii) does not place more than 390 orders in listed options per day on average during a calendar month for its own beneficial account(s). A “Professional Order” will be defined as an order that is for the account of a person or entity that is not a Priority Customer.
The use of these new terms in the execution rules and fee schedule will result in professional account holders participating in the ISE's allocation process on equal terms with broker-dealer orders and market maker quotes. It will also result in members paying the
In order to properly represent orders entered on the Exchange according to the new definitions, Electronic Access Members will be required to indicate whether Public Customer Orders are “Priority Customer Orders” or “Professional Orders.” To comply with this requirement, Electronic Access Members will be required to review their customers' activity on at least a quarterly basis to determine whether orders that are not for the account of a broker or dealer should be represented as Priority Customer Orders or Professional Orders.
The Exchange believes that identifying professional account holders based upon the average number of orders entered for a beneficial account is an appropriately objective approach that will reasonably distinguish such persons and entities from retail investors. The Exchange proposes the threshold of 390 orders per day on average over a calendar month because it believes it far exceeds the number of orders that are entered by retail investors in a single day,
The basis under the Act for this proposed rule change is the requirement under Section 6(b)(5)
The proposed rule change does not impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
The Exchange has not solicited, and does not intend to solicit, comments on this proposed rule change. The Exchange has not received any written comments from members or other interested parties.
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 Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The ISE proposes to allow, on a purely voluntary basis, non-broker-dealer customers to designate their orders as “Voluntary Professional.” Voluntary Professional orders will be treated the same as non-customer orders for purposes of execution priority and the ISE schedule of fees. The text of the proposed rule change is available at ISE, the Commission's Public Reference Room, and
In its filing with the Commission, the ISE 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 ISE has prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements.
Under ISE rules, a “Public Customer” is any person or entity that is not a broker or dealer in securities and a “Public Customer Order” is an order for the account of a Public Customer.
Members have indicated that certain of their non-broker-dealer customers employing sophisticated trading strategies that involve cancelling a large percentage of their orders before the orders are executed would prefer to have their orders categorized as Non-Customer Orders, thereby gaining relief from the Exchange's cancellation fee that member firms pass through to these customers. Accordingly, the Exchange proposes to allow, on a purely voluntary basis, non-broker-dealer customers to instruct member firms, in writing, to designate their orders as Voluntary Professional.
Under the proposal, Voluntary Professionals would participate in ISE's allocation process on equal terms with broker-dealer orders and market maker quotes. The proposal would also result in members paying the same transaction fees for the execution of Voluntary Professional orders as they do for broker-dealer orders. By definition, the Voluntary Professional designation would not otherwise affect these non-broker-dealer individuals or entities under the ISE rules. The Exchange notes that Voluntary Professional orders would continue to be treated the same as Public Customer Orders for purposes of linkage-related rules. For example, the ISE would provide the same away-market protection for orders designated as Voluntary Professional as it does for orders designated as Public Customer Orders by preventing incoming marketable orders from automatically executing at prices inferior to the best bid or offer on another national securities exchange. As provided in ISE Rule 714, such Voluntary Professional orders would be handled by the Primary Market Maker who may, according to ISE Rule 1901(c), send a P/A order to another exchange to get a better price for the customer.
The basis under the Act for this proposed rule change is the requirement under Section 6(b)(5) that an exchange have rules that are designed to prevent fraudulent and manipulative acts and practices, to promote just and equitable principles of trade, to remove impediments to and perfect the mechanism for a free and open market and a national market system, and, in general, to protect investors and the public interest.
The proposed rule change does not impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
The Exchange has not solicited, and does not intend to solicit, comments on this proposed rule change. The Exchange has not received any unsolicited written comments from members or other interested parties.
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 paper comments in triplicate to Nancy M. Morris, Secretary, Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-1090.
All submissions should refer to File Number SR-ISE-2007-76. This file number should be included on the subject line if e-mail is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site at (
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to section 19(b)(1)
The NYSE proposes to make conforming amendments to certain of its rules in light of recent changes to short sale provisions in Rule 10a-1
The text of the proposed rule change is available at the Exchange, on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of, and basis for, the proposed rule change. The text of these statements may be examined at
On June 28, 2007, the Commission approved final rules eliminating the price test of Rule 10a-1 and amending Regulation SHO (“Adopting Release”).
Accordingly, NYSE is proposing conforming amendments to the following rules: Rule 104 (Dealings by Specialists); Rule 111 (Reports of Executions); Rule 123A (Miscellaneous Reports); Rule 123C (Market on the Close Policy and Expiration Procedures); Rule 421(Periodic Reports); Rule 440B (Short Sales); Rule 440C (Short Sale Borrowing and Delivery Requirements); Rule 440F (Public Short Sale Transactions Effected on the Exchange); Rule 440G (Transactions in Stocks and Warrants for the Accounts of Members, Allied Members and Member Organizations); Rule 902 (Off-Hours Trading Orders); Rule 1000 (Automatic Execution of Limit Orders Against Orders Reflected in NYSE Published Quotation); and Rule 1003 (Application of Tick Tests).
Rule 10a-1 was adopted by the Commission as a means to restrict short selling in a declining market.
The Commission periodically added exceptions to Rule 10a-1 and granted numerous written requests for relief from the provisions of Rule 10a-1.
In 2004, the Commission adopted Regulation SHO to update short sale regulation in light of numerous market developments since short sale regulation was first adopted in 1938.
The Pilot commenced on May 2, 2005 and terminated on April 28, 2006.
Accordingly, in December 2006, the Commission, based on a careful study of the Pilot results and the status of price test restrictions, proposed amendments to remove the price test of Rule 10a-1 and add Rule 201 of Regulation SHO to provide that no price test, including any price test of any SRO, shall apply to short sales in any security.
The Adopting Release removed Rule 10a-1 and added Rule 201 of Regulation SHO to provide that no price test, including any price test by any SRO, shall apply to short selling in any security. Additionally, Rule 200 of Regulation SHO previously required broker-dealers to mark sales in all equity securities “long,” “short,” or “short exempt.” Under the Rule, an order could be marked “short exempt” if the seller was entitled to rely on any exception from the tick test, under Rule 10a-1 or any SRO price test. The amendments modified Rule 200(g) of Regulation SHO to remove the requirement that a broker-dealer mark a sell order of an equity security as “short exempt” if the seller is relying on an
The Exchange notes the Adopting Release statement that “although the current price test restrictions are being removed, today's markets are characterized by high levels of transparency and regulatory surveillance. These characteristics greatly reduce the risk of undetected manipulation and permit regulators to monitor for the types of activities that current price test restrictions are designed to prevent.” The Commission also noted that “the general anti-fraud and anti-manipulation provisions of the federal securities laws continue to prohibit activity designed to improperly influence the price of a security.”
The NYSE is proposing amendments to certain of its rules to conform to the Commission's amendments to Rule 10a-1 and Regulation SHO. Specifically, the Exchange is proposing amendments to remove short sale price test provisions, references to Rule 10a-1 and references to the “short exempt” marking requirement to update its rules in light of the amendments.
NYSE Rule 440B incorporates by reference Exchange Act Rule 10a-1 and Rules 200 and 203 of Regulation SHO. Rule 440B also includes an Explanatory Note, which generally describes changes to short sale regulation and implementation dates. Specifically, the Explanatory Note incorporates and explains the tick test under Rule 10a-1. In addition, the Explanatory Note incorporates the Pilot order, issued under Regulation SHO by the SEC, which suspended the NYSE tick test and any SRO price test for designated securities.
The proposed amendments to Rule 440B would delete the Explanatory Note as such information is no longer accurate as a result of the above-mentioned expiration of Rule 202T and the Commission's amendments rescinding Rule 10a-1 and prohibiting any SRO price tests on short sales.
Current Rule 440B(a) provides restrictions on certain short sales pursuant to Rule 10a-1. Current Rule 440B(c) suspends subsection (a) for such time and as to such securities as are designated under the Pilot. Additionally, Rule 440B(b) currently restricts a short sale by a specialist in which such specialist is registered for his own account or any other person in reliance upon the exemption provided under Rule 10a-1(e)(5). The Exchange is proposing to delete sections (a)-(c) of Rule 440B to reflect the rescission of Rule 10a-1.
Current Rule 440B.10 generally explains Rule 10a-1 and sets forth the application of Rule 440B in connection with Rule 10a-1 and Regulation SHO. The Exchange is proposing to delete all references to Rule 10a-1 and its requirements in this provision. The Exchange is also proposing to amend Rule 440B.11 to delete any reference to Rule 10a-1 and to delete Rule 440B.12 which sets forth the place of transaction requirements in connection with Rule 10a-1. The Exchange also proposes to delete Rule 440B.15 as it describes prices at which short sales are to be made in accordance with Rule 10a-1.
Further, the Exchange proposes to amend Rule 440B.13 to delete references to the “short exempt” marking requirement, and to delete Rule 440B.20, which sets forth such marking requirement, in its entirety, as the “short exempt” marking requirement has been removed by the Commission. The Supplementary Material of Rule 440B will be renumbered to reflect the proposed amendments.
NYSE Rule 440C governs borrowing and deliveries against short sales by incorporating by reference the requirements of Rule 203 of Regulation SHO and Exchange Act Rule 10a-1. The Exchange is proposing to delete reference in Rule 440C to Rule 10a-1.
NYSE Rule 421 requires that member organizations submit to the Exchange periodic reports with respect to short positions in securities, covering such time period as may be designated by the Exchange. Also, Rule 421.10 provides that short positions to be reported exclude positions resulting from certain provisions of Rule 10a-1(e).
The proposed amendment to Rule 421.10 would delete reference to Rule 10a-1(e)(1), (6), (7), (8) and (10) based on the rescission of Rule 10a-1, and add the language from these specific provisions to the rule text. Although the tick test is being eliminated, the substance of these provisions will be maintained as it is appropriate to retain an exception to the short sale interest reporting requirements. Thus, Rule 421 will continue to provide the same exception as previously provided by Rule 10a-1(e)(1), (6), (7), (8), and (10) to the short sale reporting requirements.
The proposed amendment to NYSE Rules 104, 111, 123A, 123C and 1000 would delete all references to Rule 10a-1 and short sale tick tests. The amendments would delete NYSE Rule 1003 in its entirety as it relates solely to tick tests. Further, the proposed amendments would delete references to the “short exempt” marking requirement in current NYSE Rules 440F, 440G and 902.
The statutory basis for the proposed rule change is section 6(b)(5)
The Exchange does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act.
The Exchange has neither solicited nor received written comments on the proposed rule change.
Because the foregoing rule change does not: (A) Significantly affect the protection of investors or the public interest; (B) impose any significant burden on competition; and (C) become operative for 30 days after the date of
The Exchange has requested that the Commission waive the 5-day pre-filing notice requirement
At any time within 60 days of the filing of such 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.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Phlx proposes to: (1) Adopt a tiered per contract floor broker options subsidy payable to member organizations with Exchange registered floor brokers for eligible contracts (as defined below) that are entered into the Exchange's Floor Broker Management System (”FBMS”)
Although changes to the fee schedule pursuant to this proposal are effective upon filing, the Exchange intends to implement the subsidy and delete the floor brokerage assessment beginning with transactions settling on or after February 1, 2008.
The text of the proposed rule change is available at the Exchange, the Commission's Public Reference Room, and
In its filing with the Commission, the Exchange included statements
The details of the tiered per contract floor broker subsidy program are set forth below.
To qualify for the per contract subsidy, a member organization with Exchange registered floor brokers must have: (1) More than an average of 75,000 executed contracts per day in the applicable month; and (2) at least 40,000 executed contracts or more per day for at least eight trading days during that same month.
In the event that two or more member organizations with Exchange registered floor brokers each entered one side of a transaction into FBMS, then the executed contracts would be divided among each qualifying member organization that participates in that transaction.
To be eligible for the per contract subsidy, an order must be entered through the Exchange's FBMS and subsequently executed on the Exchange.
As previously stated, customer-to-customer transactions would count towards reaching the 75,000 contract and 40,000 contract thresholds, but a per contract subsidy would not be paid on any customer-to-customer transactions.
Dividend, merger and short stock interest strategies would be excluded from all threshold volume calculations, and no per contract subsidy would be paid on these transactions.
The per contract subsidy would be paid based on the average daily contract volume for that month, which are customer-to-non-customer transactions
When computing the threshold amounts, the Exchange intends to first count all customer-to-customer transactions and then all other customer-to-non-customer transactions.
The Exchange also proposes to eliminate the floor brokerage assessment that is set forth on the Exchange's fee schedule in several places, specifically the Summary of Equity Option and RUT and RMN Charges, the Summary of Index Option Charges, the Summary of U.S. Dollar-Settled Foreign Currency Option Charges, and the Summary of Physical Delivery Currency Option Charges.
The Exchange states that purpose of providing for a subsidy and deleting the floor brokerage assessment is to attract additional floor brokerage business to the Exchange, which should, in turn, attract more consistent liquidity as the Exchange's market share increases. The purpose of deleting the floor brokerage assessment on the Summary of Physical Delivery Currency Option Charges is to delete a fee that is deemed no longer necessary by the Exchange at this time.
The Exchange represents that this proposal should not adversely affect its commitment of resources to its regulatory oversight program.
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 solicited or received with respect to the proposed rule change.
The foregoing proposed rule change has been designated as a fee change pursuant to Section 19(b)(3)(A)(ii) of the Act
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. 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 Trading and Markets, pursuant to delegated authority.
The Summer Institute for European Student Leaders will offer a group of twenty young Europeans from a broad range of ethnic, religious and socio-economic backgrounds the opportunity to learn about the United States and build leadership skills during a five-week program on an American campus. The Fulbright Commissions in Denmark, France, the Netherlands, Norway, Portugal, Spain, Sweden, and the United Kingdom will recruit participants who are first- or second-year undergraduate students or recent high school graduates who will enter university in fall 2008. The goals of the Institute are to promote study and learning about the United States, leadership development, and civic engagement through academic coursework and participatory activities that will serve the participants in their academic and professional careers and to promote mutual understanding between the United States and their home countries. ECA anticipates that program dates will be for the approximate period of July 13-August 16, 2008.
Overall grant making authority for this program is contained in the Mutual Educational and Cultural Exchange Act of 1961, Public Law 87-256, as amended, also known as the Fulbright-Hays Act. The purpose of the Act is “to enable the Government of the United States to increase mutual understanding between the people of the United States and the people of other countries * * *; to strengthen the ties which unite us with other nations by demonstrating the educational and cultural interests, developments, and achievements of the people of the United States and other nations * * * and thus to assist in the development of friendly, sympathetic and peaceful relations between the United States and the other countries of the world.” The funding authority for the program above is provided through legislation.
(a) An academic program that will introduce participants to the important events, people, and documents that have shaped the United States and contemporary American life. The host institution is encouraged to identify or develop an academic course that Institute participants can take together with American students at the university.
(b) A cultural component that complements and reinforces the academic component. Activities should include visits to historical and cultural sites of interest and participation in extra-curricular activities that will allow an optimal level of interaction with American peers. This component should include plans for participants to be engaged in a community service activity one to two hours per week.
(c) An English language component designed to strengthen the English proficiency of all participants. While all program activities should aim to promote English-language learning, preparations should be in place to assist students through one-on-one or small group tutorials. Institute participants will be required to take the Oral Proficiency Interview (OPI) administered by American Council on the Teaching of Foreign Languages (ACTFL). The host institution will work with ACTFL to administer the OPI to participants before they depart Europe for the United States. The one-on-one and/or small group tutorials should be held at least three times a week throughout the duration of the Institute and will be mandatory for those participants deemed to require additional language instruction based on the OPI assessment.
(d) A U.S. student mentor program. The host institution should retain four qualified U.S. mentors/escorts (upper division or graduate students) who exhibit cultural sensitivity and an understanding of the Institute's objectives to serve as cultural interpreters and accompany the participants throughout the program. The mentors should reside in the dormitories or other campus housing with the participants.
Applicants should take into account that the participants may not be familiar with the American student-centered classroom approach and will have varying degrees of experience in expressing their opinions in a classroom environment. All aspects of the Institute program should be designed to encourage the students to interact with each other and American counterparts.
ECA anticipates that the participants will travel to the United States and directly to the host institution campus on approximately Sunday, July 13, 2008, and depart for Europe from Washington, DC, on Thursday, August 14, 2008. Round-trip international travel will be booked and paid for by the participating Fulbright Commissions.
○ ECA will select participants who are nominated by the participating Fulbright Commissions.
○ ECA will facilitate sending pre-arrival orientation materials electronically to participants via the participating Fulbright Commissions.
○ ECA will enroll all participants in the Accident and Sickness and Sickness Program for Exchanges (ASPE). This health benefits program will be of no cost to the host institution. The participants will be responsible for the co-pays for medical treatment.
○ ECA will issue DS-2019s for the participants to enter the United States on J-visas.
○ ECA will organize a debriefing session in Washington, DC, at the conclusion of the Institute. All costs for the debriefing (travel to Washington, lodging, meals) will be the responsibility of the host institution and should be included in the proposal budget.
○ ECA will provide the host institution with biographical information about the participants and their travel itineraries.
○ ECA will be available to provide additional guidance and consultation.
When cost sharing is offered, it is understood and agreed that the applicant must provide the amount of cost sharing as stipulated in its proposal and later included in an approved grant agreement. Cost sharing may be in the form of allowable direct or indirect costs. For accountability, you must maintain written records to support all costs which are claimed as your contribution, as well as costs to be paid by the Federal government. Such records are subject to audit. The basis for determining the value of cash and in-kind contributions must be in accordance with OMB Circular A-110, (Revised), Subpart C.23—Cost Sharing and Matching. In the event you do not provide the minimum amount of cost sharing as stipulated in the approved budget, ECA's contribution will be reduced in like proportion.
(a) Bureau grant guidelines require that organizations with less than four years experience in conducting international exchanges be limited to $60,000 in Bureau funding. ECA anticipates awarding one grant, in an amount up to $180,000 to support program and administrative costs required to implement this exchange program. Therefore, organizations with less than four years experience in conducting international exchanges are ineligible to apply under this competition. The Bureau encourages applicants to provide maximum levels of cost sharing and funding in support of its programs.
Please read the complete announcement before sending inquiries or submitting proposals. Once the RFGP deadline has passed, Bureau staff may not discuss this competition with applicants until the proposal review process has been completed.
Please contact the
The Solicitation Package contains the Proposal Submission Instruction (PSI) document which consists of required application forms, and standard guidelines for proposal preparation.
It also contains the Project Objectives, Goals and Implementation (POGI) document, which provides specific information, award criteria and budget instructions tailored to this competition.
Please specify
The entire Solicitation Package may be downloaded from the Bureau's Web site at
Applicants must follow all instructions in the Solicitation Package. The application should be submitted per the instructions under IV.3f. “Application Deadline and Methods of Submission” section below.
The Bureau of Educational and Cultural Affairs places critically important emphases on the security and proper administration of the Exchange Visitor (J visa) Programs and adherence by grantees and sponsors to all regulations governing the J visa. Therefore, proposals should demonstrate the applicant's capacity to meet all requirements governing the administration of the Exchange Visitor Programs as set forth in 22 CFR 62, including the oversight of Responsible Officers and Alternate Responsible Officers, screening and selection of program participants, provision of pre-arrival information and orientation to participants, monitoring of participants, proper maintenance and security of forms, record-keeping, reporting and other requirements. ECA will be responsible for issuing DS-2019 forms to participants in this program.
A copy of the complete regulations governing the administration of Exchange Visitor (J) programs is
United States Department of State, Office of Exchange Coordination and Designation, ECA/EC/ECD—SA-44, Room 734, 301 4th Street, SW., Washington, DC 20547, Telephone: (202) 203-5029, FAX: (202) 453-8640.
Please refer to Solicitation Package for further information.
Pursuant to the Bureau's authorizing legislation, programs must maintain a non-political character and should be balanced and representative of the diversity of American political, social, and cultural life. “Diversity” should be interpreted in the broadest sense and encompass differences including, but not limited to ethnicity, race, gender, religion, geographic location, socio-economic status, and disabilities. Applicants are strongly encouraged to adhere to the advancement of this principle both in program administration and in program content. Please refer to the review criteria under the ‘Support for Diversity’ section for specific suggestions on incorporating diversity into your proposal. Public Law 104-319 provides that “in carrying out programs of educational and cultural exchange in countries whose people do not fully enjoy freedom and democracy,” the Bureau “shall take appropriate steps to provide opportunities for participation in such programs to human rights and democracy leaders of such countries.” Public Law 106—113 requires that the governments of the countries described above do not have inappropriate influence in the selection process. Proposals should reflect advancement of these goals in their program contents, to the full extent deemed feasible.
Proposals must include a plan to monitor and evaluate the project's success, both as the activities unfold and at the end of the program. The Bureau recommends that your proposal include a draft survey questionnaire or other technique plus a description of a methodology to use to link outcomes to original project objectives. The Bureau expects that the grantee will track participants or partners and be able to respond to key evaluation questions, including satisfaction with the program, learning as a result of the program, changes in behavior as a result of the program, and effects of the program on institutions (institutions in which participants work or partner institutions). The evaluation plan should include indicators that measure gains in mutual understanding as well as substantive knowledge.
Successful monitoring and evaluation depend heavily on setting clear goals and outcomes at the outset of a program. Your evaluation plan should include a description of your project's objectives, your anticipated project outcomes, and how and when you intend to measure these outcomes (performance indicators). The more that outcomes are “smart” (specific, measurable, attainable, results-oriented, and placed in a reasonable time frame), the easier it will be to conduct the evaluation. You should also show how your project objectives link to the goals of the program described in this RFGP.
Your monitoring and evaluation plan should clearly distinguish between program
We encourage you to assess the following four levels of outcomes, as they relate to the program goals set out in the RFGP (listed here in increasing order of importance):
1. Participant satisfaction with the program and exchange experience.
2. Participant learning, such as increased knowledge, aptitude, skills, and changed understanding and attitude. Learning includes both substantive (subject-specific) learning and mutual understanding.
3. Participant behavior, concrete actions to apply knowledge in work or community; greater participation and responsibility in civic organizations; interpretation and explanation of experiences and new knowledge gained; continued contacts between participants, community members, and others.
4. Institutional changes, such as increased collaboration and partnerships, policy reforms, new programming, and organizational improvements.
Consideration should be given to the appropriate timing of data collection for each level of outcome. For example, satisfaction is usually captured as a short-term outcome, whereas behavior and institutional changes are normally considered longer-term outcomes.
Overall, the quality of your monitoring and evaluation plan will be judged on how well it (1) specifies intended outcomes; (2) gives clear descriptions of how each outcome will be measured; (3) identifies when particular outcomes will be measured; and (4) provides a clear description of the data collection strategies for each outcome (i.e., surveys, interviews, or focus groups). (Please note that evaluation plans that deal only with the first level of outcomes [satisfaction] will be deemed less competitive under the present evaluation criteria.)
Grantees will be required to provide reports analyzing their evaluation findings to the Bureau in their regular program reports. All data collected, including survey responses and contact information, must be maintained for a minimum of three years and provided to the Bureau upon request.
Applications may be submitted in one of two ways:
(1) In hard-copy, via a nationally recognized overnight delivery service (i.e., DHL, Federal Express, UPS, Airborne Express, or U.S. Postal Service Express Overnight Mail, etc.), or
(2) Electronically through
Along with the Project Title, all applicants must enter the above Reference Number in Box 11 on the SF-424 contained in the mandatory Proposal Submission Instructions (PSI) of the solicitation document.
Applications must be shipped no later than the above deadline. Delivery services used by applicants must have in-place, centralized shipping identification and tracking systems that may be accessed via the Internet and
When preparing your submission please make sure to include one extra copy of the completed SF-424 form and place it in an envelope addressed to “ECA/EX/PM”.
The original and
Applicants submitting hard-copy applications must also submit the “Executive Summary” and “Proposal Narrative” sections of the proposal in a Microsoft Word format on a CD-ROM.
Several of the steps in the
Direct all questions regarding
Applicants have until midnight (12 a.m.), Washington, DC time of the closing date to ensure that their entire application has been uploaded to the
Applicants will receive a confirmation e-mail from
It is the responsibility of all applicants submitting proposals via the
The Bureau will review all proposals for technical eligibility. Proposals will be deemed ineligible if they do not fully adhere to the guidelines stated herein and in the Solicitation Package. All eligible proposals will be reviewed by the program office, as well as the Public Diplomacy section overseas, where appropriate. Eligible proposals will be subject to compliance with Federal and Bureau regulations and guidelines and forwarded to Bureau grant panels for advisory review. Proposals may also be reviewed by the Office of the Legal Adviser or by other Department elements. Final funding decisions are at the discretion of the Department of State's Assistant Secretary for Educational and Cultural Affairs. Final technical authority for cooperative agreements resides with the Bureau's Grants Officer.
Technically eligible applications will be competitively reviewed according to the criteria stated below. These criteria are not rank ordered and all carry equal weight in the proposal evaluation:
1.
2.
3.
4.
5.
6.
Unsuccessful applicants will receive notification of the results of the application review from the ECA program office coordinating this competition.
Terms and Conditions for the Administration of ECA agreements include the following:
Office of Management and Budget Circular A-122, “Cost Principles for Nonprofit Organizations.”
Office of Management and Budget Circular A-21, “Cost Principles for Educational Institutions.”
OMB Circular A-87, “Cost Principles for State, Local and Indian Governments”.
OMB Circular No. A-110 (Revised), Uniform Administrative Requirements for Grants and Agreements with Institutions of Higher Education, Hospitals, and other Nonprofit Organizations.
OMB Circular No. A-102, Uniform Administrative Requirements for Grants-in-Aid to State and Local Governments.
OMB Circular No. A-133, Audits of States, Local Government, and Non-profit Organizations
Please reference the following Web sites for additional information:
You must provide ECA with a hard copy original plus 8 copies of the following reports:
(1) A final program and financial report no more than 90 days after the expiration of the award;
Grantees will be required to provide reports analyzing their evaluation findings to the Bureau in their regular program reports. (Please refer to IV. Application and Submission Instructions (IV.3.d.3) above for Program Monitoring and Evaluation information.)
All data collected, including survey responses and contact information, must be maintained for a minimum of three years and provided to the Bureau upon request.
All reports must be sent to the ECA Grants Officer and ECA Program Officer listed in the final assistance award document.
For questions about this announcement, contact: Carolina Chavez, ECA/A/E/EUR, Room 246, ECA/A/E/EUR 08-04, U.S. Department of State, SA-44, 301 4th Street, SW., Washington, DC 20547, 202-453-8524,
All correspondence with the Bureau concerning this RFGP should reference the above title and number ECA/A/E/EUR 08-03.
Please read the complete announcement before sending inquiries or submitting proposals. Once the RFGP deadline has passed, Bureau staff may not discuss this competition with applicants until the proposal review process has been completed.
The terms and conditions published in this RFGP are binding and may not be modified by any Bureau representative. Explanatory information provided by the Bureau that contradicts published language will not be binding. Issuance of the RFGP does not constitute an award commitment on the part of the Government. The Bureau reserves the right to reduce, revise, or increase proposal budgets in accordance with the needs of the program and the availability of funds. Awards made will be subject to periodic reporting and evaluation requirements per section VI.3 above.
Notice is hereby given of the following determinations: Pursuant to the authority vested in me by the Act of October 19, 1965 (79 Stat. 985; 22 U.S.C. 2459), Executive Order 12047 of March 27, 1978, the Foreign Affairs Reform and Restructuring Act of 1998 (112 Stat. 2681,
For further information, including a list of the exhibit objects, contact Richard Lahne, Attorney-Adviser, Office of the Legal Adviser, U.S. Department of State (telephone: 202/453-8058). The address is U.S. Department of State, SA-44, 301 4th Street, SW., Room 700, Washington, DC 20547-0001.
The U.S. Advisory Commission on Public Diplomacy will hold a public meeting on February 21, 2008, in Room 602 (Lindner Family Commons) at the Elliot School of International Affairs, George Washington University, 1957 E Street NW., Washington, DC. The meeting will be held from 9 a.m. to 12 noon. The Commissioners will discuss public diplomacy issues, including the application of political communication theory, and associated disciplines, in U.S. government public diplomacy efforts.
The Advisory Commission was originally established under 604 of the United States Information and Exchange Act of 1948, as amended (22 U.S.C. 1469) and section 8 of Reorganization Plan Numbered 2 of 1977. It was reauthorized pursuant to Public Law 110-21 (2007). The Commission is a bipartisan panel created by Congress in 1948 to assess public diplomacy policies and programs of the U.S. government and publicly funded
Seating at this meeting is limited. To attend and for more information, please contact Carl Chan at (202) 203-7883. E-mail:
Department of Transportation.
Notice of Order to Show Cause (Order 2008-2-3) Dockets DOT-OST-2000-7668, DOT-OST-2003-14985, and DOT-OST-2004-19919.
The Department of Transportation is directing all interested persons to show cause why it should not issue an order finding that Boston-Maine Airways, Corp, is not fit, willing, and able, to provide air transportation as a U.S. certificated air carrier.
Persons wishing to file objections should do so no later than March 3, 2008.
Objections and answers to objections should be filed in Dockets DOT-OST-2000-7668, DOT-OST-2003-14985, and DOT-OST-2004-19919 and addressed to Docket Management Facility, U.S. Department of Transportation, 1200 New Jersey Ave SE., West Building, Room W12-140, Washington, DC 20590, and should be served upon the parties listed in Attachment B to the order.
Vanessa R. Balgobin, Air Carrier Fitness Division, U.S. Department of Transportation, 1200 New Jersey Ave SE., West Building, Room W86-463, Washington, DC 20590, (202) 366-9721.
Federal Motor Carrier Safety Administration (FMCSA), DOT.
Notice of renewal of exemptions; request for comments.
FMCSA announces its decision to renew the exemptions from the vision requirement in the Federal Motor Carrier Safety Regulations for 6 individuals. FMCSA has statutory authority to exempt individuals from the vision requirement if the exemptions granted will not compromise safety. The Agency has concluded that granting these exemption renewals will provide a level of safety that is equivalent to, or greater than, the level of safety maintained without the exemptions for these commercial motor vehicle (CMV) drivers.
This decision is effective March 7, 2008. Comments must be received on or before March 10, 2008.
You may submit comments bearing the Federal Docket Management System (FDMS) Docket ID FMCSA-99-5748, FMCSA-99-6156, using any of the following methods.
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•
•
•
Each submission must include the Agency name and the docket number for this Notice. Note that DOT posts all comments received without change to
Dr. Mary D. Gunnels, Director, Medical Programs, (202) 366-4001,
Under 49 U.S.C. 31136(e) and 31315, FMCSA may renew an exemption from the vision requirements in 49 CFR 391.41(b)(10), which applies to drivers of CMVs in interstate commerce, for a two-year period if it finds “such exemption would likely achieve a level of safety that is equivalent to, or greater than, the level that would be achieved absent such exemption.” The procedures for requesting an exemption (including renewals) are set out in 49 CFR part 381.
This notice addresses 6 individuals who have requested a renewal of their exemption in accordance with FMCSA procedures. FMCSA has evaluated these 6 applications for renewal on their merits and decided to extend each
These exemptions are extended subject to the following conditions: (1) That each individual have a physical examination every year (a) by an ophthalmologist or optometrist who attests that the vision in the better eye continues to meet the standard in 49 CFR 391.41(b)(10), and (b) by a medical examiner who attests that the individual is otherwise physically qualified under 49 CFR 391.41; (2) that each individual provide a copy of the ophthalmologist's or optometrist's report to the medical examiner at the time of the annual medical examination; and (3) that each individual provide a copy of the annual medical certification to the employer for retention in the driver's qualification file and retain a copy of the certification on his/her person while driving for presentation to a duly authorized Federal, State, or local enforcement official. Each exemption will be valid for two years unless rescinded earlier by FMCSA. The exemption will be rescinded if: (1) The person fails to comply with the terms and conditions of the exemption; (2) the exemption has resulted in a lower level of safety than was maintained before it was granted; or (3) continuation of the exemption would not be consistent with the goals and objectives of 49 U.S.C. 31136(e) and 31315.
Under 49 U.S.C. 31315(b)(1), an exemption may be granted for no longer than two years from its approval date and may be renewed upon application for additional two-year periods. In accordance with 49 U.S.C. 31136(e) and 31315, each of the 6 applicants has satisfied the entry conditions for obtaining an exemption from the vision requirements (64 FR 40404; 64 FR 66962; 67 FR 10475; 69 FR 8260; 71 FR 6824; 64 FR 54948; 65 FR 159). Each of these 6 applicants has requested renewal of the exemption and has submitted evidence showing that the vision in the better eye continues to meet the standard specified at 49 CFR 391.41(b)(10) and that the vision impairment is stable. In addition, a review of each record of safety while driving with the respective vision deficiencies over the past two years indicates each applicant continues to meet the vision exemption standards. These factors provide an adequate basis for predicting each driver's ability to continue to drive safely in interstate commerce. Therefore, FMCSA concludes that extending the exemption for each renewal applicant for a period of two years is likely to achieve a level of safety equal to that existing without the exemption.
FMCSA will review comments received at any time concerning a particular driver's safety record and determine if the continuation of the exemption is consistent with the requirements at 49 U.S.C. 31136(e) and 31315. However, FMCSA requests that interested parties with specific data concerning the safety records of these drivers submit comments by March 10, 2008.
FMCSA believes that the requirements for a renewal of an exemption under 49 U.S.C. 31136(e) and 31315 can be satisfied by initially granting the renewal and then requesting and evaluating, if needed, subsequent comments submitted by interested parties. As indicated above, the Agency previously published notices of final disposition announcing its decision to exempt these 6 individuals from the vision requirement in 49 CFR 391.41(b)(10). The final decision to grant an exemption to each of these individuals was based on the merits of each case and only after careful consideration of the comments received to its notices of applications. The notices of applications stated in detail the qualifications, experience, and medical condition of each applicant for an exemption from the vision requirements. That information is available by consulting the above cited
Interested parties or organizations possessing information that would otherwise show that any, or all of these drivers, are not currently achieving the statutory level of safety should immediately notify FMCSA. The Agency will evaluate any adverse evidence submitted and, if safety is being compromised or if continuation of the exemption would not be consistent with the goals and objectives of 49 U.S.C. 31136(e) and 31315, FMCSA will take immediate steps to revoke the exemption of a driver.
Federal Transit Administration (FTA), DOT.
Notice of Availability of Proposed Amendments to the 2007 National Transit Database Urbanized Area Annual Reporting Manual.
This notice provides interested parties with the opportunity to comment on changes to the Federal Transit Administration's (FTA) 2008 National Transit Database (NTD) Urbanized Area Annual Reporting Manual (Annual Manual). Pursuant to 49 U.S.C. 5335, FTA requires recipients of FTA Urbanized Area Formula Grants to provide an annual report to the Secretary of Transportation via the NTD reporting system according to a uniform system of accounts (USOA). Other transit agencies in urbanized areas report to the NTD under these requirements on a voluntary basis, for purposes of including data from their transit agencies in the apportionment of Urbanized Area Formula Grants. In an ongoing effort to improve the NTD reporting system and be responsive to the needs of the transit agencies reporting to the NTD, FTA annually refines and clarifies the reporting requirements through revisions to the Annual Manual.
Comments must be received on or before March 10, 2008. FTA will consider late filed comments to the extent practicable.
You may submit comments [identified by DOT Docket ID Number FTA-2008-0002] at the Federal eRulemaking Portal at:
For program issues, John D. Giorgis, Office of Budget and Policy, (202) 366-5430 (telephone); (202) 366-7989 (fax); or
The National Transit Database (NTD) is the Federal Transit Administration's (FTA's) primary database for statistics on the transit industry. Recipients of FTA's Urbanized Area Formula Program (section 5307) and Other Than Urbanized Area Formula Program (section 5311) are required by statute to submit data to the NTD. These data are used to “help meet the needs of... the public for information on which to base public transportation service planning...” (49 U.S.C 5335). Other transit agencies in urbanized areas report to the NTD under these requirements on a voluntary basis, for purposes of including data from their transit agencies in the apportionment of Urbanized Area Formula Grants. FTA details the NTD reporting requirements for urbanized area transit agencies in the NTD Urbanized Area Annual Reporting Manual (Annual Manual).
Currently, over 650 transit agencies in urbanized areas report to the NTD through an Internet-based reporting system. Each year, performance data from these submissions are used to apportion over $4 billion of FTA funds under the Urbanized Area Formula Grants Program. These data are also used in the annual National Transit Summaries and Trends report, the biennial Conditions and Performance Report to Congress, and in meeting FTA's obligations under the Government Performance and Results Act.
In an ongoing effort to improve the NTD Internet reporting system and to be responsive to the needs of the transit agencies reporting to the NTD and the transit community, FTA annually refines and clarifies reporting requirements to the NTD. This notice provides interested parties with the opportunity to comment on changes to FTA's 2008 Annual Manual. For purposes of comparison, the 2007 Annual Manual can be reviewed on the NTD Web site,
FTA proposes to greatly simplify this form so as to reduce the substantial confusion that this form has caused among reporters in the past. Under FTA's proposal, this form will allow reporters to report three types of relationships: (1) Traditional purchased transportation contracts; (2) taxicab contracts for demand response service; and (3) pass-through relationships. This change responds to the numerous difficulties that reporters have had in the past in reporting their taxicab contracts and pass-through relationships on a form that had been designed for traditional purchased transportation contracts.
For traditional purchased transportation contracts and taxicab contracts the simplified form will make it clear to transit agencies that they are to report: (1) The vehicles and maintenance facilities that may be provided to, or nominally leased to, the seller; (2) the number of months the contract was operated in the past year; (3) the number of vehicles or rail passenger cars operated during maximum service by the seller of service; (4) the fare revenues accrued under the service; (5) whether the fare revenues are retained by the seller, or returned to the purchasing transit agency; (6) the contract administration expenses incurred by the purchasing transit agency; and (7) all other costs incurred by the purchasing agency to support the contract, such as fuel, maintenance, insurance, and marketing costs.
The new option for
The new option for
FTA currently requires transit agencies to identify funds earned from various types of dedicated taxes (specifically, income, sales, property, gasoline, and other taxes; as well as regular tolls, high-occupancy tolls, and other dedicated revenues) from various types of sources (each of the above generated from independent political entities, local governments, and state governments, respectively) and to specify how much of each of these were expended on operations and how much of each of these were expended on capital. FTA proposes to eliminate this requirement at the level of individual types of taxes, and to only report the total revenue earned from each type of dedicated tax from each type of source. FTA proposes to only require transit agencies to separate funds earned and spent on operations from funds earned and spent on capital in the context of fare revenues, total directly-generated revenues (e.g. parking and advertising revenues), contributed services (e.g. services provided directly by another government body), the various sources of Federal funds, total state government revenues, total local government revenues, and total revenues from independent political entities.
Additionally, FTA proposes to simplify this form by only making the option to report revenue from independent political entities available to those transit agencies that qualify as such entities, by virtue of having their own tax-raising authority.
FTA proposes to eliminate the requirement to report Bond and Loan payments separately for each category of funding. Instead, FTA proposes simplified bond and loan reporting that would require transit agencies to report: (1) Year-beginning principal outstanding; (2) new bonds and loans (new principal); (3) total interest paid; (4) total principal repaid; and (5) total year-end principal outstanding.
FTA proposes to reduce the reporting requirements by no longer requiring transit agencies to separately report
FTA proposes to reduce the reporting requirements by combining separate reporting for
Additionally, FTA proposes to simplify this form by limiting the
FTA proposes to eliminate collecting
FTA proposes to stop collecting
FTA proposes to stop collecting information on lease agreements on this form. Leases should already be collected as part of the cost of purchased transportation.
FTA proposes to continue collecting information on reconciling items on this form, but will require an explanation of all reconciling items.
FTA proposes to discontinue this form. FTA already collects data on employees, and employee hours on the R-10 Form, and FTA already collects data on employees' pay and benefits on the F-10 Form. Discontinuing this form will mean that FTA will no longer collect the hours and expenditures on employees based on
For Motorbus and Trolleybus services, FTA proposes to change the categories currently labeled
For rail service, FTA proposes to make similar changes: (1) Changing
For demand response service, FTA proposes similar changes for directly operated and purchased transportation services: (1) Changing
For vanpool service, FTA proposes similar changes: (1) Eliminating
For jitney and público services, FTA proposes similar changes: (1) Eliminating
FTA proposes similar changes for ferryboat and aerial tramway services: (1) Changing
For heavy rail, light rail, and commuter rail systems, in 2007 FTA introduced a requirement for these systems agencies to report Average Weekday Unlinked Passenger Trips and
FTA proposes to add reporting of
FTA proposes to drop the reporting requirement for
FTA also proposes to require that this form be completed by transit agencies for purchased transportation service (it is currently only required for directly operated services). These data would produce a clear picture of the role of maintenance breakdowns in transit service.
FTA proposes to drop the lines on this form for certain rarely-used fuels, specifically,
FTA also proposes to require that this form be completed for purchased transportation services (it is currently only required for directly operated services). These data would support the significant public interest in the fuel needs and emissions of transit services.
FTA proposes to expand some of the reporting requirements for stations. Currently, FTA requires transit agencies to only report how many of their stations are multi-modal. FTA proposes to begin requiring transit agencies to specify the nature of the multi-modal services at each station. Transit agencies will be able to group together similar stations, as is done for asset reporting on revenue vehicles. For example, a transit agency will be able to report that it has 10 stations that are multi-modal with light rail and motorbus service. In addition to reporting the transit modes providing service at each station, FTA proposes to have transit agencies indicate if the transit station has Intercity Bus, Amtrak, Airport, Seaport, Car Rental, Bicycle Rental, or Parking Lot facilities.
For motorbus, trolleybus, and light rail service, FTA proposes to ask transit agencies to report how many stops and how many shelters that they have. Previously, FTA only collected the number of enclosed stations for each mode, which understated the number of transit stations for these services.
Both of these data collections will assist FTA in assessing the scope and needs of the Nation's transit systems for the biennial Conditions and Performance Report to Congress.
FTA proposes to merge this Form with the Fixed Guideway Segments (S-20) Form, to reduce reporting burden. For each segment of rail fixed guideway reported on the S-20 form, FTA proposes to have transit agencies report the construction-type of the segment (
FTA proposes to simply collect whether the vehicles are compliant with the Americans with Disabilities Act (ADA Accessible), and to not separately collect those vehicles that are ADA Accessible by virtue of having lifts and those that are ADA Accessible by virtue of having ramps or low floors.
FTA also proposes to stop collecting
FTA proposes to make this form required for all transit agencies serving more than one urbanized area, or an urbanized area and a non-urbanized area. This form is currently required only for transit agencies serving an urbanized area over 200,000 in population and either a non-urbanized area or another urbanized area. This form is used to allocate service data from transit agencies across the various urbanized areas (and any non-urbanized areas) served by the transit agency for purposes of apportioning Urbanized Area Formula Grants. With the passage of the Safe, Accountable, Flexible, Efficient, Transportation Equity Act: A Legacy for Users (SAFETEA-LU), the Urbanized Area Formula Grant formula was amended to include grants for Small Transit-Intensive Cities (STIC Grants.) Prior to SAFETEA-LU service data was only used to apportion Urbanized Area Formula Grants to urbanized areas over 200,000 in population. The STIC Grants, however, use service data to apportion grants to urbanized areas under 200,000 in population. Therefore, FTA must require the FFA-10 form from transit agencies in small urbanized areas, in order to ensure to support the accurate apportionment of STIC Grants.
Office of Foreign Assets Control, Treasury.
Notice.
The Treasury Department's Office of Foreign Assets Control (“OFAC”) is publishing the names of 4 newly-designated entities and individuals whose property and interests in property are blocked pursuant to Executive Order 13391 of November 22, 2005, “Blocking Property of Additional Persons Undermining Democratic Processes or Institutions in Zimbabwe”.
The designation by the Director of OFAC of the four entities and individuals identified in this notice, pursuant to Executive Order 13391, is effective January 30, 2008.
Assistant Director, Compliance Outreach & Implementation, Office of
Information about this designation and additional information concerning OFAC are available from OFAC's Web site (
On November 22, 2005, the President issued Executive Order 13391 (the “Order”) with respect to Zimbabwe pursuant to,
Section 1 of the Order blocks, with certain exceptions, all property, and interests in property, that are in, or hereafter come within, the United States or the possession or control of United States persons for persons listed in the Annex and those persons determined by the Secretary of the Treasury, after consultation with the Secretary of State, to satisfy any of the criteria set forth in subparagraphs (a)(ii)(A) through (a)(ii)(D) of section 1. On January 30, 2008, the Director of OFAC exercised the Secretary of the Treasury's authority to designate, pursuant to one or more of the criteria set forth in section 1, subparagraphs (a)(ii)(A) through (a)(ii)(D) of the Order, the following two individuals and two entities, whose names have been added to the list of Specially Designated Nationals and whose property and interests in property are blocked, pursuant to the Order:
The United States Mint is adjusting prices for its American Eagle Platinum Proof Coins and American Eagle Platinum Uncirculated Coins.
Pursuant to the authority that 31 U.S.C. 5111(a) and 5112(k) grant the Secretary of the Treasury to mint and issue platinum coins, and to prepare and distribute numismatic items, the United States Mint mints and issues 2007 American Eagle Platinum Proof and Uncirculated Coins in four denominations with the following weights: one-ounce, one-half ounce, one-quarter ounce, one-tenth ounce. The United States Mint also produces American Eagle Platinum Proof and Uncirculated four-coin sets that contain one coin of each denomination. In accordance with 31 U.S.C. 9701(b)(2)(B), the United States Mint is changing the price of these coins to reflect the increase in value of the underlying precious metal content of the coins—the result of increases in the market price of platinum.
Accordingly, effective February 1, 2008, the United States Mint will commence selling the following 2007 American Eagle Proof and Uncirculated Coins according to the following price schedule:
Gloria C. Eskridge, Associate Director for Sales and Marketing; United States Mint; 801 Ninth Street, NW., Washington, DC 20220; or call 202-354-7500.
31 U.S.C. 5111, 5112 & 9701.
The United States Mint is adjusting prices for its 2007 American Eagle Gold Proof and Uncirculated Coins.
Pursuant to the authority that 31 U.S.C. 5111(a) and 5112(a)(7-10) grant the Secretary of the Treasury to mint and issue gold coins, and to prepare and distribute numismatic items, the United States Mint mints and issues 2007 American Eagle Gold Proof and Uncirculated Coins with the following weights: One-ounce, one-half ounce, one-quarter ounce, one-tenth ounce. The United States Mint also produces an American Eagle four-coin set that contains one coin of each denomination. In accordance with 31 U.S.C. 9701(b)(2)(B), the United States Mint is changing the price of these coins to reflect the increase in value of the underlying precious metal content of the coins—the result of increases in the market price of gold.
Accordingly, effective February 1, 2008, the United States Mint will commence selling the following 2007 American Eagle Gold Uncirculated Coins and the 2007 American Eagle
Gloria C. Eskridge, Associate Director for Sales and Marketing; United States Mint; 801 Ninth Street, NW., Washington, DC 20220; or call 202-354-7500.
31 U.S.C. 5111, 5112 & 9701.
Federal Energy Regulatory Commission, Department of Energy.
Final Rule.
Pursuant to section 215 of the Federal Power Act (FPA), the Commission approves eight Critical Infrastructure Protection (CIP) Reliability Standards submitted to the Commission for approval by the North American Electric Reliability Corporation (NERC). The CIP Reliability Standards require certain users, owners, and operators of the Bulk-Power System to comply with specific requirements to safeguard critical cyber assets. In addition, pursuant to section 215(d)(5) of the FPA, the Commission directs NERC to develop modifications to the CIP Reliability Standards to address specific concerns.
Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G. Kelly, Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff.
1. Pursuant to section 215 of the Federal Power Act (FPA),
2. Section 215 of the FPA requires a Commission-certified Electric Reliability Organization (ERO) to develop mandatory and enforceable Reliability Standards, which are subject to Commission review and approval. Once approved, the Reliability Standards may be enforced by the ERO, subject to Commission oversight, or the Commission can independently enforce Reliability Standards.
3. Pursuant to section 215 of the FPA, the Commission established a process to select and certify an ERO
4. In April 2007, the Commission approved delegation agreements between NERC and each of the eight Regional Entities.
5. Prior to being certified by the Commission as the ERO, NERC had developed a cyber security standard for the electric industry on a voluntary basis. This voluntary standard, Urgent Action 1200, was adopted in 2003, and remained in effect on a voluntary basis until June 1, 2006, at which time the eight CIP Reliability Standards that are the subject of the current rulemaking replaced the Urgent Action 1200 standard.
6. On August 28, 2006, NERC submitted to the Commission for approval the following eight CIP Reliability Standards:
7. NERC states that these CIP Reliability Standards provide a comprehensive set of requirements to protect the Bulk-Power System from malicious cyber attacks. They require Bulk-Power System users, owners, and operators to establish a risk-based vulnerability assessment methodology to identify and prioritize critical assets and critical cyber assets. Once the critical cyber assets are identified, the CIP Reliability Standards require, among other things, that the responsible entities establish plans, protocols, and controls to safeguard physical and electronic access, to train personnel on security matters, to report security incidents, and to be prepared for recovery actions. Further, NERC developed an implementation plan that provides for a three-year phase-in to achieve full compliance with all requirements.
8. Each CIP Reliability Standard uses a common organizational format that includes five sections, as follows: (A) Introduction, which includes “Purpose” and “Applicability” sub-sections; (B) Requirements; (C) Measures; (D) Compliance; and (E) Regional Differences. In this Final Rule, these section titles are capitalized when referencing a designated provision of a Reliability Standard.
9. In a separate filing, NERC submitted 162 Violation Risk Factors that correspond to Requirements of the proposed CIP Reliability Standards.
10. On December 11, 2006, the Commission released a “Staff
11. On July 20, 2007, the Commission issued the CIP NOPR, which proposed to approve the eight CIP Reliability Standards submitted to the Commission for approval by NERC. In addition, the Commission proposed to direct NERC to develop modifications to the CIP Reliability Standards to address specific concerns identified by the Commission.
12. In response to the CIP NOPR, comments were filed by about 70 interested persons. In the discussion below, we will address the issues raised by these comments. Appendix A to this Final Rule lists the entities that filed comments on the CIP NOPR. Five comments were filed after the time prescribed in the CIP NOPR. Nevertheless, the Commission will consider these comments, as they will neither prejudice the other commenters, nor delay the proceeding.
13. In the Final Rule, the Commission approves the eight CIP Reliability Standards, finding that they are just and reasonable, not unduly discriminatory or preferential and in the public interest. Further, the Commission approves NERC's implementation plan that sets milestones for responsible entities to achieve full compliance with the CIP Reliability Standards. The Commission also directs NERC to develop modifications to the CIP Reliability Standards through its Reliability Standards development process to address specific concerns identified by the Commission. Similar to our approach in Order No. 693, we view such directives as a separate action from approval, consistent with our authority in section 215(d)(5) of the FPA to direct the ERO to develop a modification to a Reliability Standard. As discussed below, such modification should not affect the current implementation plan. Rather, NERC is directed to develop a timetable for development of the modifications to the CIP Reliability Standards and, if warranted, to develop and file with the Commission for approval, a second implementation plan.
14. Other determinations in the Final Rule include:
A directive that the ERO must develop modifications to the CIP Reliability Standards to remove the “reasonable business judgment” language.
The ERO must also develop modifications to remove “acceptance of risk” exceptions from the CIP Reliability Standards.
The ERO is directed to develop specific conditions that a responsible entity must satisfy to invoke the “technical feasibility” exception. This structure for use of the technical feasibility exception allows flexibility and customization of implementation of the CIP Reliability Standards in a controlled manner.
The Commission directs the ERO to provide additional guidance regarding the development of a risk-based assessment methodology for the identification of critical assets pursuant to CIP-002-1. Further, external review of critical asset lists is required.
The Commission directs the ERO to make specific revisions to its Violation Risk Factor designations.
15. In the CIP NOPR, the Commission proposed to approve NERC's eight proposed CIP Reliability Standards as mandatory and enforceable. As a separate action, pursuant to section 215(d)(5) of the FPA, the Commission proposed to direct NERC to modify certain provisions of the CIP Reliability Standards.
16. Most commenters strongly support the Commission's proposal to approve the CIP Reliability Standards as mandatory and enforceable.
17. By contrast, ABB argues that the Commission should defer action so that equipment vendors and the standard-setting organizations such as the Institute of Electrical and Electronics Engineers can coordinate electric power system cyber security initiatives. Applied Control Solutions argues that the proposals in the CIP NOPR do not go far enough, and that the Commission should go further and immediately adopt the National Institute of Standards and Technology (NIST) Security Risk Management Framework in place of the CIP Reliability Standards.
18. NIST itself argues that the Commission should adopt the NERC proposed CIP Reliability Standards, as appropriately enhanced based on the Commission's proposed directives in the CIP NOPR, as an interim measure. NIST advocates that the Commission prescribe plans for a two to three year transition to cyber security standards that are identical to, consistent with, or based on SP 800-53 and related NIST standards and guidelines.
19. WIRAB supports NERC's CIP Reliability Standards and states that they represent a significant advancement for cyber security and Bulk-Power System reliability. Yet, WIRAB recommends that the Commission remand the CIP Reliability Standards to NERC with guidance as to the types of changes the Commission would like to see, but without direction to make any specific change. WIRAB expresses concern that the CIP NOPR proposes numerous detailed directives to modify the CIP Reliability Standards and goes beyond providing guidance to NERC. WIRAB states that a remand would allow the Reliability Standards development process to work as anticipated and, in doing so, would avoid problems with different Reliability Standards or different levels of enforcement on different sides of the international border.
20. In response to our proposal to modify certain CIP Reliability Standards, some commenters maintain that the Commission's proposals were
21. Commenters also express concern that the Commission might intend to sidestep the NERC stakeholder process and have NERC simply revise the CIP Reliability Standards in accordance with the Commission's proposals without providing NERC stakeholders an opportunity to participate in this process.
22. KCPL supports the Commission's proposal to direct NERC to develop modifications to the CIP Reliability Standards to address potential improvements using the Reliability Standards development process. KCPL believes that the Commission has authority to direct the ERO to modify the CIP Reliability Standards and to provide sufficient guidance to the direction that grid reliability should take so as to fulfill its obligations under the Energy Policy Act of 2005. However, KCPL too is concerned that several of the Commission's proposed requirement directives are overly prescriptive.
23. The New York Commission opposes the Commission placing any conditions on its approval of the CIP Reliability Standards, such as requiring NERC to rewrite them as a condition for their approval.
24. The Commission approves the eight CIP Reliability Standards pursuant to section 215(d) of the FPA, as discussed below. In approving the CIP Reliability Standards, the Commission concludes that they are just, reasonable, not unduly discriminatory or preferential, and in the public interest. These CIP Reliability Standards, together, provide baseline requirements for the protection of critical cyber assets that support the nation's Bulk-Power System. Thus, the CIP Reliability Standards serve an important reliability goal.
25. The Commission believes that the NIST standards may provide valuable guidance when NERC develops future iterations of the CIP Reliability Standards. Thus, as discussed below, we direct NERC to address revisions to the CIP Reliability Standards CIP-002-1 through CIP-009-1 considering applicable features of the NIST framework. However, in response to Applied Control Solutions, we will not delay the effectiveness of the CIP Reliability Standards by directing the replacement of the current CIP Reliability Standards with others based on the NIST framework.
26. With regard to WIRAB's recommendation, we share the ongoing concern of promoting coordinated action on Reliability Standards on an international basis. However, in this instance, we do not believe a remand to NERC, which would result in significant delays in having mandatory and enforceable cyber security requirements in effect in the United States, is justified or would further such coordination. The implementation schedule provided by NERC, which applies continent-wide, requires applicable entities to achieve “auditable compliance” no earlier than mid-2009. This should provide adequate time for entities responsible for compliance with the CIP Reliability Standards in the United States, Canada and Mexico to achieve compliance on a common timetable. As discussed later, future modifications to the CIP Reliability Standards developed pursuant to the direction provided in the Final Rule would not overlap with the NERC implementation plan. Accordingly, the Commission concludes that this is not a satisfactory reason for remanding the CIP Reliability Standards.
27. In approving the CIP Reliability Standards and directing the ERO to modify them, the Commission is taking two independent actions and does not condition our approval on the ERO modifying the CIP Reliability Standards. First, we are exercising our authority to approve a proposed Reliability Standard. Second, we are directing the ERO to submit a modification of the Reliability Standards to address specific issues or concerns.
28. With regard to the concerns raised by some commenters about the prescriptive nature of the Commission's proposed modifications, the Commission agrees that a direction for modification should not be so overly prescriptive as to preclude the consideration of viable alternatives in the ERO's Reliability Standards development process. However, in identifying a specific matter to be addressed in a modification to a CIP Reliability Standard, it is important that the Commission provide sufficient guidance so that the ERO has an understanding of the Commission's concerns and an appropriate, but not necessarily exclusive, outcome to address those concerns. Without such direction and guidance, a Commission proposal to modify a CIP Reliability Standard might be so vague that the ERO would not know how to adequately respond.
29. Thus, in some instances, while we provide specific details regarding the Commission's expectations, we intend by doing so to provide useful guidance to assist in the Reliability Standards development process, not to impede it. We find that this is consistent with statutory language that authorizes the Commission to order the ERO to submit a modification “that addresses a specific matter” if the Commission considers it appropriate to carry out section 215 of the FPA. In the Final Rule, we have considered commenters' concerns and, where a directive for modification appears to be determinative of the outcome, the Commission provides flexibility by directing the ERO to
30. Consistent with section 215 of the FPA, our regulations, and Order No. 693, any modification to a Reliability Standard, including a modification that addresses a Commission directive, must be developed and fully vetted through NERC's Reliability Standard development process. Until the Commission approves NERC's proposed modification to a Reliability Standard, the preexisting Reliability Standard will remain in effect.
31. The Applicability section of each proposed CIP Reliability Standard identifies the following 11 categories of responsible entities that must comply with the CIP Reliability Standard: Reliability coordinators, balancing authorities, interchange authorities,
32. The CIP NOPR explained that, with regard to the applicability of the CIP Reliability Standards to the ERO, NERC has modified its Rules of Procedure to provide that the ERO will comply with each Reliability Standard that identifies the ERO as an applicable entity.
33. The Commission also indicated in the CIP NOPR that it would rely on the NERC registration process to determine applicability with the CIP Reliability Standards.
34. The Commission also raised concerns regarding operation of critical cyber assets by out-sourced entities.
35. Most commenters that address the issue support the Commission's approach to assuring NERC and Regional Entity compliance with the CIP Reliability Standards. Commenters also support the Commission's reliance on the NERC registration process to identify appropriate entities. Numerous commenters address the issue of third-party vendors, indicating that such third parties are not subject to mandatory Reliability Standards and that responsible entities need to address the matter through contractual provisions with their vendors.
36. EEI supports the Commission's conclusion that NERC's modifications to its Rules of Procedure and the delegation agreements between NERC and each of the eight Regional Entities with respect to compliance with approved Reliability Standards is sufficient and does not require any additional measures or revisions at this time. EEI expects that the Commission will provide oversight with respect to compliance by NERC and a Regional Entity. However, unlike responsible entities, the ERO and Regional Entities are not subject to penalties under the FPA. Therefore, in considering what level of oversight to provide for these entities, EEI urges the Commission to consider that these entities do not have the same incentive as responsible entities to comply with the CIP Reliability Standards.
37. Progress believes that the CIP Reliability Standards must apply to the ERO and the Regional Entities since they have access to critical data of many electric systems and may be perceived as more strategic targets than other registered entities. California Commission, Northern Indiana and Northeast Utilities also assert that the CIP Reliability Standards should apply to NERC and the Regional Entities. Northern Indiana states that subjecting NERC to the CIP Reliability Standards would obviate Northern Indiana's concern with providing NERC personnel with access to information they may need when reviewing and evaluating Northern Indiana's compliance measures.
38. California Commission comments that the CIP NOPR properly recognized the ERO as an applicable entity. It also states that the delegation agreements between NERC and the Regional Entities mandate that the Regional Entities will be subject to the CIP Reliability Standards. California Commission states that, if the ERO or Regional Entities do not adhere to the CIP Reliability Standards, they could become the weak link whose failure could harm the Bulk-Power System.
39. NRECA, MEAG Power and other commenters support the Commission's reliance on the NERC registration process to identify appropriate entities and also share the concern that entities not registered could become a weakness in the security of the Bulk-Power System.
40. EEI and ISO/RTO Council agree with the statement in the CIP NOPR that demand side aggregators might also need to be included in the NERC registration process if their load shedding capacity would affect the reliability or operability of the Bulk-Power System. EEI comments that demand side aggregators do not fit into any of the current registry categories and their inclusion would likely require the development of a definition of “demand response” and “direct load control,” as well as size thresholds, which are best addressed in the NERC Reliability Standards development process.
41. California Commission comments that small entities can become a weak link whose failure could harm Bulk-Power System reliability. It is concerned that an entity that should be registered may slip through the identification process. Accordingly, California Commission suggests that any entity connected to the Bulk-Power System, regardless of size, must comply with the CIP Reliability Standards irrespective of their registration status.
42. The majority of commenters contend that neither the ERO, nor the Commission, have authority to extend the applicability of the CIP Reliability Standards to third-party vendors.
43. EEI agrees with the CIP NOPR statement that responsible entities, as owners of critical assets, are ultimately accountable for their cyber security protection under the Reliability Standards. EEI also comments that it is reasonable that responsible entities may wish to provide their vendors with incentives to comply with CIP Reliability Standards while satisfying their other contractual obligations.
44. ISO/RTO Council comments that, when an application is developed and maintained by an outsourced provider, that provider manages access to the environment on which the application runs and therefore must be contractually obligated by the responsible entity to comply with the CIP Reliability Standards. While not in NERC's registry, such third parties must perform the services and operate the applications in a manner consistent with the CIP Reliability Standards. According to ISO/RTO Council, the responsible entity should be charged with incorporating contractual terms and conditions into its agreements with the third-party provider that obligates the provider to comply with the requirements of the CIP Reliability Standards. Responsibility for non-compliance by the third-party vendor should be borne by the responsible entity that made the business decision to outsource the application.
45. Other commenters contend that the CIP Reliability Standards must apply to vendors and contractors as well as responsible entities. For example, California Commission suggests that the CIP Reliability Standards should apply to every entity that has a cyber connection to the Bulk-Power System. However, in California Commission's view, some special rules must be developed on CIP Reliability Standards applicability for entities that are not responsible entities but that have entered contracts obligating them to comply with the CIP Reliability Standards. Consumers claims that vendors and contactors with access (remote and on-site) to the critical cyber assets should be required to comply with the CIP Reliability Standards' personnel risk assessment guidelines. Consumers also advocates that vendor companies should have a personnel risk assessment policy, i.e., background check, for all new personnel and all systems (software applications and hardware devices) should be tested for quality and reliability.
46. Northern Indiana comments that third-party vendors working for NERC must comply with the CIP Reliability Standards, e.g., background checks, just as Northern Indiana's third-party vendors must. Otherwise, NERC's vendors should not be given access to critical cyber assets.
47. The Commission adopts the CIP NOPR approach regarding NERC and Regional Entity compliance with the CIP Reliability Standards. The Commission maintains its belief that NERC's compliance is necessary in light of its interconnectivity with other entities that own and operate critical assets. Further, we conclude that NERC's Rules of Procedure, which state that the ERO will comply with each Reliability Standard that identifies the ERO as an applicable entity, provide an adequate means to assure that NERC is obligated to comply with the CIP Reliability Standards. Likewise, the delegation agreements between NERC and each Regional Entity expressly state that the Regional Entity is committed to comply with approved Reliability Standards.
48. With regard to EEI's concerns about NERC's incentives to comply with the CIP Reliability Standards, we believe that NERC's position as overseer of Bulk-Power System reliability provides a level of assurance that it will take compliance seriously. Moreover, section 215(e)(5) of the FPA provides that the Commission may take such action as is necessary or appropriate against the ERO or a Regional Entity to
49. The Commission also adopts its CIP NOPR approach and concludes that reliance on the NERC registration process at this time is an appropriate means of identifying the entities that must comply with the CIP Reliability Standards.
50. With regard to EEI's request for clarification, the NERC registry process is designed to identify and register entities for compliance with Reliability Standards, and not identify lists of assets. In the CIP NOPR, the Commission explained that it would expect NERC to register the owner or operator of an important asset, such as a blackstart unit, even though the facility may be relatively small or connected at low voltage.
51. Likewise, we believe that NERC should register demand side aggregators if the loss of their load shedding capability, for reasons such as a cyber incident, would affect the reliability or operability of the Bulk-Power System. EEI and ISO/RTO Council concur that the need for the registration of demand side aggregators may arise, but state that it is not clear whether aggregators fit any of the current registration categories defined by NERC. We agree with EEI and ISO/RTO Council that NERC should consider whether there is a current need to register demand side aggregators and, if so, to address any related issues and develop criteria for their registration.
52. The Commission agrees with the many commenters that suggest that the responsibility of a third-party vendor for compliance with the CIP Reliability Standards is a matter that should be addressed in contracts between the registered entity that is responsible for mandatory compliance with the Standards and its vendor. To the extent that the responsible entity makes a business decision to hire an outside contractor to perform services for it, the responsible entity remains responsible for compliance with the relevant Reliability Standards. Thus, it is incumbent upon the responsible entity to assure that its third-party vendor acts in compliance with the CIP Reliability Standards. We agree with ISO/RTO Council's characterization of the matter:
. . . when an application is developed and maintained by an outsourced provider, that outsourced provider manages physical and cyber access to the environment on which the application runs and therefore must be contractually obligated to the Responsible Entity to comply with the Reliability Standards.
While such providers are not registered entities subject to the Reliability Standards, they must perform the services and operate the applications in a manner consistent with the Reliability Standards . . . the Responsible Entity should be charged with incorporating contractual terms and conditions into agreements with third-party service providers that obligate the providers to comply with the requirements of the Reliability Standards. In that regard, if a Responsible Entity determines that it is necessary to outsource a service that is essential to the reliable operation of a Critical Asset, Critical Cyber Asset, or the bulk electric system, it is clear that the Responsible Entity must be held responsible and accountable for compliance with the Reliability Standards.[
53. Further, it is incumbent upon a responsible entity to conduct vigorous oversight of the activities and procedures followed by the vendors they employ. Thus, we expect a responsible entity to address in its security policy under CIP-003-1 its policies regarding its oversight of third-party vendors.
54. The CIP NOPR expressed concern that the lack of specificity within the proposed CIP Reliability Standards could result in inadequate implementation efforts and inconsistent results.
55. The CIP NOPR also noted that the CIP Reliability Standards do not provide a mechanism to measure performance. The Commission identified three strategies for monitoring performance: (1) Internal and external oversight of a responsible entity's activities; (2) documenting, monitoring and revisiting a responsible entity's exercise of flexibility in a way that excepts it from a Requirement; and (3) reporting certain wide-area information and analysis to the Commission.
56. NERC and others comment that the CIP Reliability Standards should prescribe what outcome must be accomplished, but should not prescribe how that outcome is accomplished.
57. In addition, NERC expresses concern that including acceptable solutions as part of the CIP Reliability Standards could introduce common vulnerabilities based on all industry participants using a nearly identical solution to a given vulnerability.
58. A number of commenters also provide comment regarding performance measurement and the Commission's proposal for internal and external oversight. NERC contends that much of the proposed additional oversight is in place in the existing ERO and regional compliance and audit programs. NERC explains that these programs are being updated based on the Requirements of the CIP Reliability Standards.
59. Other commenters, such as EEI, ISO/RTO Council and Puget Sound, suggest that the determination of whether a responsible entity meets or fails to meet the requirements of a CIP Reliability Standard should be determined in an audit based on the specific facts and circumstances of its use, ownership or operation of the Bulk-Power System. EEI argues that a strong auditing requirement serves to ensure quality control, and will result in consistency in the implementation of the CIP Reliability Standards. KCPL states that the information technology associated with cyber security provides a unique challenge for the audit function and auditors must have a significant amount of experience with both the industry and the cyber security needs to ensure that the obligations to the CIP Reliability Standards are properly evaluated during an audit. SERC-CIPC adds that the distinction between mandatory requirements and non-binding guidance should be made clear to auditors, noting that these differences could be subtle.
60. With regard to external oversight, Northern Indiana believes that certain independent entities' employees “such as [those performing] the internal audit function” can provide a wide-area view. Northern Indiana requests clarification on what the Commission means by the term “external oversight.”
61. The Commission received comments on both sides of the issue of specificity. Some commenters caution against the CIP Reliability Standards being too specific, while others request more guidance to help them comply. In general, the Commission believes it is appropriate to provide sufficient guidance to explain Requirements so that responsible entities have a high degree of certainty that they understand what is necessary to comply with a Requirement. More guidance will allow responsible entities to implement measures adapted to their specific situations more consistently and effectively. Additional guidance need not be included in a specific Requirement, but could be in the form of examples. The Commission is not directing that the ERO establish a specific end result. Our concern is simply that responsible entities have guidance on how to achieve an appropriate result in individual cases, which can vary on a case-by-case basis. Therefore, in several instances throughout this Final Rule, the Commission gives the ERO direction to provide additional guidance. In some cases, we require that the guidance be placed in modifications to the CIP Reliability Standards. In other cases, we note that some or all of the additional guidance could be placed in a reference document separate from the CIP Reliability Standards.
62. Some of the more specific directives in this Final Rule pertain to issues that the Commission considers necessary to carry out its statutory responsibilities. Examples of this include areas of oversight, exceptions to Requirements, and reports to the Commission. In developing these directives, we have tried to strike a balance between our needs to implement the statute and the concerns expressed by commenters.
63. We agree in general with commenters who point out that compliance issues should be determined in audits and that a strong auditing process will help to ensure quality control and consistency in the implementation of the CIP Reliability Standards. However, we point out that audits are only one aspect of the ERO's compliance monitoring and enforcement process. All aspects of that process must function well. In addition, we note compliance audits are conducted after-the-fact and do not diminish the necessity for internal and external reviews of compliance efforts, including the identification of critical assets and critical cyber assets.
64. In response to Northern Indiana, we explain “external oversight” in our discussions and determinations of specific Requirements in the Final Rule.
65. The CIP NOPR noted that many of the Requirements of the CIP Reliability Standards consist of broad directives, with corresponding Measures and Compliance provisions focusing largely on proper documentation.
66. The Commission also noted that, while certain Requirements of the CIP Reliability Standards obligate a responsible entity to develop and maintain a plan, policy or procedure, the Requirements do not always explicitly require implementation of the plan, policy or procedure. The Commission proposed to interpret such provisions to include an implicit implementation requirement.
67. SPP and ReliabilityFirst agree with the Commission that adequate documentation does not substitute for substantive compliance with the responsibilities set forth in the requirements of the CIP Reliability Standards. However, they express concern that not relying on objective documentation requirements to demonstrate compliance could result in subjective variations in the audit process and uneven application of the Requirements of a Reliability Standard. ReliabilityFirst states that, while it is reasonable to apply subjective reasoning as part of a readiness assessment, any audit that could result in financial sanctions for non-compliance must rely solely upon clearly defined objective measures. To remedy the concern that documentation may not assure compliance with a CIP Reliability Standard, SPP suggests that the Requirements and Measures prescribed in a CIP Reliability Standard be enhanced to define the minimum acceptable documentation content.
68. In the context of measuring performance, Northern Indiana states that it generally supports the Commission's desire to clarify the CIP Reliability Standards but cautions the Commission from prescribing modifications that would limit a responsible entity's discretion. Northern Indiana comments that, while in some instances (such as testing vulnerabilities on a real-time, active system basis) documentation should suffice to demonstrate compliance, in other situations documentation does not suffice. In these instances, even though the responsible entity's documentation may comply with the CIP Reliability
69. Xcel notes that, in the CIP NOPR, the Commission indicated that “compliance will in all cases be measured by whether a party met or failed to meet the Requirement given the specific facts and circumstances.”
70. EEI, FirstEnergy, ISO/RTO Council, Northeast Utilities and PG&E agree that certain CIP requirements do not explicitly require implementation of a plan, policy or procedure that the responsible entity is required to develop and maintain. Thus, they support directing NERC, in the course of its scheduled industry Reliability Standards development process, to consider making explicit that a responsible entity must implement a plan, policy or procedure that it is required to develop.
71. Xcel asks the Commission to clarify what it means to implement a plan, policy or procedure. Specifically, Xcel asks the Commission to clarify that “this does not mean that an entity has to follow every aspect of its plans, policies or procedures to the letter or be in violation * * *.”
72. While the Commission agrees with commenters that relying on an objective determination such as whether a document exists would facilitate the compliance audit process, we do not believe such a cursory approach is the best way to ensure the protection of the Bulk-Power System. We adopt our proposal in the CIP NOPR that responsible entities must comply with the substance of a Requirement. In this way we affirm the Commission's position established in Order No. 693 that, “while Measures and Levels of Non-Compliance provide useful guidance to the industry, compliance will in all cases be measured by determining whether a party met or failed to meet the Requirement given the specific facts and circumstance of its use, ownership or operation of the Bulk-Power System.”
73. Xcel seeks clarification regarding responsible entities that comply with the substance of a Requirement but violate the documentation provisions. In Order No. 693, in response to a similar request by Xcel, the Commission explained that, “[w]hile the Commission generally agrees that it is a violation of the Requirements that is subject to a penalty, we recognize that because Measures are intended to gauge or document compliance, failure to meet a Measure is almost always going to result in a violation of a Requirement.”
74. In the CIP NOPR, the Commission also noted that, while certain Requirements of the CIP Reliability Standards obligate a responsible entity to develop and maintain a plan, policy or procedure, the Requirements do not always explicitly require implementation of the plan, policy or procedure. The Commission proposed to interpret such provisions to include an implicit implementation requirement.
75. Consistent with that proposal, the Commission concludes that, where the CIP Reliability Standards obligate a responsible entity to develop and maintain a plan, policy or procedure, there should be a corresponding obligation to implement the plan, policy or procedure. However, while the CIP NOPR proposed to interpret the CIP Reliability Standards as including an implicit obligation to implement plans, policies and procedures, we are persuaded by the commenters that a better approach is for the ERO to develop modifications to the CIP Reliability Standards that contain appropriate implementation language. Accordingly, we direct the ERO to develop modifications to the CIP Reliability Standards that require a responsible entity to implement plans, policies and procedure that it must develop pursuant to the CIP Reliability Standards.
76. As to Xcel's argument that, at times, the proper course is to deviate from a plan, we agree that the details of such plans are not equivalent to Requirements of a CIP Reliability Standard. However, the responsible entity's plan should be followed unless a deliberate decision is made for good reason not to follow it. Such reason should be documented and available for compliance auditors to review. Merely ignoring plan provisions is equivalent to not having a plan. For clarity, we note that a decision not to follow a particular plan provision due to circumstances will not except a responsible entity from a related Requirement in a CIP Reliability Standard. As discussed below, we find that any exception to a CIP Reliability Standard must comply with the required conditions for a technical feasibility exception.
77. In the CIP NOPR, the Commission explained that, because the CIP Reliability Standards are new and require applicable entities in many cases to develop new cyber security systems and procedures, NERC developed an implementation plan based on a schedule that provides for implementation of the CIP Reliability Standards over a three-year period.
78. The Commission proposed to approve NERC's implementation plan, including the proposed timelines for achieving compliance.
79. Numerous commenters urge the Commission to accept NERC's proposed implementation plan and the proposed timeline for achieving compliance with the CIP Reliability Standards.
80. Many of these same commenters express concern about how the Commission's proposal in the CIP NOPR to direct that NERC develop certain modifications to the CIP Reliability Standards would affect the implementation schedule. NERC explains that the implementation plan and time frame are for the existing CIP Reliability Standards as submitted to the Commission. NERC states that any changes to the CIP Reliability Standards resulting from the Final Rule will potentially impact the implementation plan and time frame, and a new schedule will need to be developed during the Reliability Standards development process associated with those changes.
81. Similarly, EEI and Entergy advocate that the Final Rule make clear that modifications developed pursuant to the Reliability Standards development process should not be implemented until the conclusion of the NERC implementation plan.
82. Manitoba Hydro comments that the Commission should reject NERC's proposed implementation schedule because it is based on the unrealistic expectation that the CIP Reliability Standards would be approved without the need for any revisions. Muscatine Power & Water argues that if the Commission requires utilities to base their risk-based assessments on formal guidelines provided by NERC, then the implementation schedule must be extended to allow additional time for compliance.
83. APPA/LPPC suggest the implementation plan may need adjustment if the Regional Entities or some other region-wide institutions supplement a responsible entity's list of critical assets. In such cases, APPA/LPPC request that the Commission direct NERC to develop a reasonable schedule for determining the timeline for being auditably compliant with respect to the newly designated assets.
84. Entergy characterizes the CIP NOPR as proposing to “remand” CIP-002-1, which according to Energy would leave unresolved the basic issue of which assets are subject to the CIP Reliability Standards. Entergy contends that without knowledge of which assets the CIP Reliability Standards apply, the proposed timeline is unworkable.
85. SPP maintains that there is no table prescribing a schedule in which an existing registered entity can bring a newly identified critical asset and its critical cyber assets into compliance. While not expected to change frequently, the critical asset list can change for any number of valid reasons, and the registered entity needs an appropriate period of time in which to achieve compliance for that asset. In the absence of a compliance schedule, no guidance is available to either the registered entity or the auditor. SPP recommends that a new table be developed defining a compliance schedule for newly identified critical assets and based upon the date of the risk-based assessment. SPP argues that the table should include milestones for tasks already completed and milestones for tasks yet to be done that will require additional resources and time to comply.
86. The Commission adopts its CIP NOPR proposal and approves NERC's implementation plan and time frames for responsible entities to achieve auditable compliance. Responsible entities require a reasonable period of time to purchase and install new cyber software and equipment and develop new programs and procedures to achieve compliance. Commenters indicate that the implementation plan provides that reasonable period of time. Further, we agree with commenters that there is an urgent need to move forward without any delays. Accordingly, we approve NERC's implementation plan.
87. Commenters raise concerns regarding the impact on the implementation plan of the Commission's directives for modifications to the CIP Reliability Standards. As explained above, the Commission is not modifying the CIP Reliability Standards in this Final Rule. Rather, pursuant to section 215(d)(5) of the FPA, the Commission in the Final Rule directs the ERO to develop certain modifications to the CIP Reliability Standards pursuant to the NERC Reliability Standards development process. Even though the development of such modifications will take time, this does not present a reason for delay or revision to the NERC implementation plan for implementing the CIP
88. The Commission believes that the modifications to the CIP Reliability Standards developed by the NERC Reliability Standards development process should not be audited prior to the conclusion of the approved implementation plan. EEI and other commenters claim that commencing the development of such modifications prior to the conclusion of the implementation plan would be discouraging to industry. The Commission, however, finds that it is unacceptable to delay the development of the modifications directed in this Final Rule until after the conclusion of the implementation plan. Since it is uncertain how long it will take to develop revised CIP Reliability Standards, we believe it is not reasonable to wait until the 2009-2010 time period for the process to start. Features such as enhanced conditions on technical feasibility exceptions and oversight of critical asset determinations are too important to the protection of the Bulk-Power System to wait that long.
89. While we are both sympathetic and concerned about straining industry resources, the Commission and the electric industry must do their best to protect the electric infrastructure that is essential to the health and safety of the nation. Therefore, we direct the ERO to submit a work plan for Commission approval for developing and filing for approval the modifications to the CIP Reliability Standards that we are directing in this Final Rule. As suggested by NERC, the Commission will consider a second implementation plan for achieving compliance with the forthcoming revised CIP Reliability Standards.
90. The Commission did not propose to remand CIP-002-1 as argued by Entergy. Nonetheless, Entergy raises a valid concern since the Commission's directive, discussed below, that the ERO develop modifications to CIP-002-1 could affect a responsible entity's identification of critical assets. We share Entergy's concern that there are threshold issues regarding CIP-002-1 that must be addressed before responsible entities can have certainty regarding which assets must be protected according to the CIP Reliability Standards. We also believe that responsible entities need certainty regarding the conditions for a technical feasibility exception to inform their decisions about how to comply with the CIP Reliability Standards, even in their current form. Therefore, we direct the ERO, in its development of a work plan, to consider developing modifications to CIP-002-1 and the provisions regarding technical feasibility exceptions as a first priority, before developing other modifications required by the Final Rule.
91. In the CIP NOPR, the Commission expressed concern over whether responsible entities will be fully prepared for compliance upon reaching the implementation deadline and will take reasonable action to protect the Bulk-Power System during the interim period.
92. Many commenters oppose directing NERC to consider a self-certification process with more frequent self-certifications than on an annual basis.
93. Other commenters, such as APPA/LPPC, MidAmerican, Northern Indiana and SDG&E either support or do not object to more frequent self-certifications. APPA/LPPC support NERC's proposed self-certification process as a reasonable means of tracking the progress made by responsible entities toward full, auditable compliance. Nor do they object to the Commission's proposal that such certification be rendered quarterly or semi-annually. Northern Indiana supports semi-annual self-certification during the transition until the implementation plan is completed. Northern Indiana contends that more frequent self-certification would be unduly burdensome.
94. METC-ITC also support quarterly or semi-annual self-certifications because the certifications will properly pressure entities to take timely steps to achieve compliance by the deadline for auditable compliance. METC-ITC are concerned, however, that having NERC monitor progress toward compliance with the CIP Reliability Standards via self-certifications, may place a burden on the ERO and the Regional Entities that their current staffs may be unable to properly administer. Thus, METC-ITC propose that the Commission require the ERO to file plans addressing how it will satisfy the new requirements for providing assistance to responsible entities and further assessing CIP implementation as part of its readiness reviews.
95. SDG&E supports semi-annual certifications, but comments that quarterly certifications would be distracting to the main goal, as well as burdensome, time consuming and paper intensive. It agrees with the Commission that an entity should not be penalized if it cannot certify that it is on schedule. SDG&E does not object to the Commission's proposal that the ERO and the Regional Entities should work with such an entity to achieving full compliance, provided that the Commission clarify that this means “getting back” on schedule and not accelerating compliance.
96. While the Commission is sensitive to concerns that more frequent self-certifications may be burdensome, it is important that the ERO and the Commission know whether industry, or segments of industry, are having difficulty implementing the CIP Reliability Standards. Therefore, we direct the ERO to require more frequent, semi-annual, self-certifications prior to
97. Further, we adopt our CIP NOPR proposals that, while an entity should not be subject to a monetary penalty if it is unable to certify that it is on schedule, such an entity should explain to the ERO the reason it is unable to self-certify. The ERO and the Regional Entities should then work with such an entity either informally or, if appropriate, by requiring a remedial plan to assist such an entity in achieving full compliance in a timely manner. Further, we expect the ERO and the Regional Entities to provide informational guidance, upon request, to assist a responsible entity in assessing its progress in reaching “auditably compliant” status.
98. With regard to METC-ITC's comment, we will not require NERC and the Regional Entities to submit plans describing how it will undertake these responsibilities. Rather, the ERO and Regional Entities can address any need for additional resources in the ERO's annual budget filing. If necessary to fulfill their statutory obligations, the ERO and Regional Entities may file a request for additional funding to supplement their Commission approved budgets.
99. With regard to SDG&E's comment, we clarify that the goal of a Regional Entity working with a responsible entity that is unable to self-certify is to assist the entity in meeting the NERC time frames for auditable compliance, and not to accelerate compliance ahead of schedule.
100. To further address the Commission's concerns about the period prior to when responsible entities achieve full compliance with the CIP Reliability Standards, the CIP NOPR also proposed that the ERO add a cyber security assessment to NERC's existing readiness reviews.
101. NERC and other commenters oppose the addition of a cyber security assessment to NERC's existing readiness reviews.
102. Northeast Utilities asks the Commission to reconsider its proposal prior to the 2009 deadline for full compliance with the CIP Reliability Standards. According to Northeast Utilities, readiness reviews are performed by industry peer volunteers under Regional Entity guidance to identify best practices and ensure that system operators have the tools, processes and procedures in place to operate reliably. It contends that, given the limited industry experience with cyber security, the readiness review process will not produce the benefits the Commission expects.
103. In contrast, MidAmerican and SDG&E agree with the Commission that adding a cyber component to the readiness audit process would be beneficial, provided an exception is made for publication of any weaknesses found during a typical readiness audit. They submit that any areas of concern uncovered by the audit should be considered sensitive and confidential with appropriate safeguards developed and in place to protect this information. MidAmerican also recommends that the Commission consider including a cyber security assessment within the ERO's existing readiness reviews.
104. Xcel asks the Commission to clarify that the CIP NOPR, in proposing that NERC add cyber security assessments to its existing schedule of reliability readiness reviews, did not intend for NERC to revise its schedule of reviews but, rather, add a new element to the previously-scheduled reviews.
105. The Commission is persuaded by comments regarding the limited reach of readiness reviews and the questionable utility of such reviews prior to the date by which entities are to be compliant; thus, adding the CIP Reliability Standards to the readiness reviews at this time will delay industry's compliance efforts. Therefore, the Commission will not require that the CIP Reliability Standards be added to the readiness reviews at this time.
106. The CIP NOPR discussed specific terminology used in the CIP Reliability Standards that, while providing flexibility for a responsible entity in achieving compliance, also raise concerns regarding enforceability of the Standards. Specifically, the Commission raised concerns regarding the terms “reasonable business judgment,” “acceptance of risk,” and “technical feasibility.” As discussed below, the Commission adopts the CIP NOPR proposals and directs NERC to modify the CIP Reliability Standards through the Reliability Standards development process to remove the first two terms, and develop specific conditions that a responsible entity must satisfy to invoke the “technical feasibility” exception. Moreover, in response to concerns raised by commenters, the Commission has changed certain conditions for invoking the technical feasibility exception.
107. As we stated in the CIP NOPR,
These standards recognize the differing roles of each entity in the operation of the Bulk Electric System, the criticality and vulnerability of the assets needed to manage Bulk Electric System reliability, and the risks to which they are exposed. Responsible entities should interpret and apply Standards CIP-002 through CIP-009 using reasonable business judgment.
108. In addition, each of the subsequent CIP Reliability Standards (
109. The Commission pointed out in the CIP NOPR that NERC's Glossary of Terms Used in Reliability Standards (NERC Glossary) does not define reasonable business judgment, and the CIP Reliability Standards do not otherwise suggest how the term is to be interpreted. NERC's Frequently Asked Questions (FAQ) document that accompanies the CIP Reliability Standards provides the only available guidance on the issue.
110. The Commission proposed, in the CIP NOPR, to direct the ERO to modify the CIP Reliability Standards to remove references to the “reasonable business judgment” language before compliance audits start in 2009.
111. The Commission noted that flexibility and discretion are essential in implementing the CIP Reliability Standards and that implementing those Reliability Standards must be done on the basis of the specific facts and circumstances applicable in the individual case at hand. Cyber security problems do not lend themselves to one-size-fits-all solutions. In addition, the Commission acknowledged that cost can be a valid consideration in implementing the CIP Reliability Standards. However, the Commission concluded that the traditional concept of reasonable business judgment is ill suited to the task of implementing an appropriate program of cyber security pursuant to section 215 of the FPA.
112. That concept was developed specifically to address the issue of how courts should approach business decisions made by a company's officers or directors, and the answer it provides is based on certain assumptions about how our economic system operates and who is most likely to have the knowledge and expertise needed to make appropriate business decisions. However, the concept of reasonable business judgment takes on a very different meaning when removed from its original context and applied to a different factual situation where very different assumptions apply.
113. The Commission noted in the CIP NOPR that cyber security standards are essential to protecting the Bulk-Power System against attacks by terrorists and others seeking to damage the grid. Because of the interconnected nature of the grid, an attack on one system can affect the entire grid. It is therefore unreasonable to allow each user, owner or operator to determine compliance with the CIP Reliability Standards based on its own “business interests.” Business convenience cannot excuse compliance with mandatory Reliability Standards. The Commission also noted that the explanation of reasonable business judgment found in the FAQ document closely tracks the treatment of the concept in the corporate law context.
114. The Commission stated that this test is fundamentally incompatible with Congress' decision to adopt a regime of mandatory Reliability Standards. The Commission explained that the issue under section 215 of the FPA is not whether the management of a business is acting in the interest of its own shareholders, but rather whether an entity is taking appropriate action to avert risks that could threaten the entire grid. Finally, the Commission noted that in the corporate governance context, the business judgment rule is invoked only in extreme circumstances, generally when an officer or director is found to have acted fraudulently, in bad faith, or with gross or culpable negligence. For all these reasons, the Commission proposed in the CIP NOPR that the ERO remove references to the “reasonable business judgment” language from the CIP Reliability Standards.
115. NERC and numerous parties, including California Commission, Texas Commission, ISO-NE and ReliabilityFirst, agree that references to reasonable business judgment should be removed from the CIP Reliability Standards. National Grid concurs to the extent that this language adds confusion by incorporating a business law concept into the CIP Reliability Standards or could be construed to allow responsible entities to avoid liability for violations unilaterally and subjectively. APPA/LPPC state that use of reasonable business judgment overstates the appropriate amount of discretion to the extent that term was intended to incorporate a body of law developed in the corporate governance context. NRECA agrees that the term would give responsible entities too much latitude in essence to exempt themselves from the CIP Reliability Standards. Xcel states that reasonable business judgment has developed an exculpatory meaning in corporate law that is not applicable to compliance with the CIP Reliability Standards. ISO-NE states that the term provides no measurable value to any of the Requirements and appears to be an open-ended caveat that is susceptible to abuse.
116. Texas Commission states that, in reviewing costs associated with upgrades for physical and cyber security for prudence, it applies a more rigorous criterion than reasonable business judgment. It argues that a looser criterion in the CIP Reliability Standards could require a company to purchase more equipment or software than would later be compensated for in their rates. Texas Commission states that reasonable business judgment does not relieve an entity from showing that any expenditures it made were just and reasonable as required in Texas Commission rate cases. Texas Commission concludes that it is in the best interest of regulated entities either to remove the term or to replace it with a more narrowly focused term with a clearly defined statutory basis.
117. Numerous commenters argue that use of the term reasonable business judgment was never intended to import corporate law concepts into the CIP Reliability Standards but rather to ensure that Responsible Entities have sufficient flexibility when implementing them.
118. Mr. Brown states that neither the CIP Reliability Standards nor the FAQ document state that the use of
119. A number of commenters either oppose removal of reasonable business judgment from the CIP Reliability Standards or express serious concern about removing it. Tampa Electric argues that the term should be retained or at the very least replaced with language that ensures flexibility. SDG&E disagrees with wholesale elimination of the business judgment rule and instead urges that parameters or guidelines be adopted that determine when and how to apply the concept. MidAmerican suggests that it can be retained if accompanied by a mitigation plan with a sunset clause. Northern Indiana supports retaining the language, explaining that the CIP Reliability Standards are new, and the development of best practices regarding them continues to evolve. Responsible entities thus must have the flexibility to exercise discretion and make the appropriate strategic decisions when implementing the Reliability Standards.
120. A number of commenters argue that use of reasonable business judgment makes it clear that cost is a relevant factor. EEI states that a responsible entity is expected to weigh cyber security options in light of the risk to reliability in the same manner as similarly situated entities. Reasonable business judgment does not imply that it is acceptable to make purely economic choices to avoid protecting a critical cyber asset and thus to jeopardize grid reliability. Evaluating whether an asset is critical requires considering the asset's role, its cost, and the impact of the asset being compromised, as well as the costs of potential protection strategies, consistent with good business practice in the electric industry. EEI states that even with the inclusion of this language, the other requirements in the CIP Reliability Standards, such as documentation of decision-making and rigorous auditing, will prevent unfettered discretion in identifying and securing critical cyber assets.
121. Ontario Power states that outright removal will render the CIP Reliability Standards too rigid and that removal could be interpreted by some to mean that compliance is required regardless of the cost, the impact on production systems, or the risk to the Bulk-Power System. Tampa Electric argues that without the leeway afforded by reasonable business judgment, responsible entities could be forced into cost-prohibitive controls that do not add value in terms of security simply to satisfy an external requirement that is ill-fitted to the particular circumstances. SDG&E states that because the cost should not exceed the security benefit, certain security investments require business judgment. There must be latitude to develop a reasonable business case for determining the costs and benefits of investing in or implementing a security control based on key risk and investment factors specific to an entity.
122. A number of commenters defend the use of reasonable business judgment in terms that focus more on the issue of liability than simple flexibility or economic considerations. AMP-Ohio states that the plain language of the proposed CIP Reliability Standards could create a strict liability environment if there is no exception for “good faith” or “reasonable judgment.” Mr. Brown states that the proposal to remove the reasonable business judgment language appears to hold utilities, and perhaps individual managers, officers and directors, directly responsible for any adverse impact of decisions based upon their inherently imperfect knowledge and information regardless of whether they acted in good faith and made reasonably well-informed decisions. Entergy states that the industry must have reasonable assurance that the actions they are implementing meet the CIP Reliability Standards and Requirements if they acted in good faith, performed the proper evaluation, and took actions consistent with their evaluation.
123. Mr. Brown maintains that there are 200 years of legal precedent for determining what constitutes prudent behavior, and nothing in the legislative history of section 215 of the FPA suggests that Congress intended to depart from that precedent in this case. He states that the Commission should proceed with great caution when it proposes to depart from this precedent for determining prudent behavior without a clear, express mandate from Congress to do so.
124. EEI and other commenters argue that if the reasonable business judgment language is removed from the CIP Reliability Standards, it should be replaced with alternative language developed in the Reliability Standards development process.
125. APPA/LPPC suggest that phrases such as “reasonable judgment” or “judgment consistent with Good Utility Practice” as substitutes for reasonable business judgment. A number of commenters, including NIPSCO and Georgia Operators, point to the phrase “good utility practice” in the pro forma OATT as a model or starting point for alternative language.
126. A number of commenters, including Manitoba Hydro and NRECA, criticize the proposal to remove references to reasonable business judgment as overly prescriptive. Manitoba Hydro states that the proposal appears to preclude the consideration of alternative wording. These commenters stress the importance of reliance on the Reliability Standards development process.
127. Southwest TDUs state that, while the Commission correctly proposes to eliminate the so-called business judgment rule, the CIP NOPR does not address the dichotomy in application of the CIP Reliability Standards between public and private entities. While the Commission correctly concludes that flexibility and discretion in implementation are necessary, there is no discussion of what that means for a public body, nor is there any recognition that a public body may be governed by state requirements and possibly by local ordinances.
128. Consistent with the CIP NOPR, the Commission concludes that the concept of reasonable business judgment is inappropriate in the context of mandatory CIP Reliability Standards. Accordingly, the Commission directs the ERO to develop modifications to the CIP Reliability Standards that do not include this term. We note that many commenters, including NERC, agree that the reasonable business judgment language should be removed based largely on the rationale articulated by the Commission in the CIP NOPR.
129. While there may have been no intention to import corporate law concepts into the CIP Reliability Standards, it is difficult to draw any other conclusion on the basis of the
130. In short, the only explanation of reasonable business judgment in the documentation responsible entities would rely on focuses on corporate law concepts. We thus reject Mr. Brown's claim what we are being hyper-legalistic and constructing straw men rather than addressing the clear intent of the language. Mr. Brown fails to identify where some intent other than to adopt the traditional business judgment rule is clearly stated, and his references to 200 years of legal precedent only serve to reinforce our conclusion. We are unaware of any such extensive body of precedent on reasonable business judgment other than that developed in the corporate law context.
131. The most common argument raised in favor of reasonable business judgment is that it ensures flexibility. The Commission, however, acknowledged the importance of flexibility and discretion in the CIP NOPR.
132. Many commenters suggest that the issue is not simply flexibility, but rather the flexibility to balance costs against other factors when implementing the CIP Reliability Standards. Many of the arguments about cost have been raised in connection with the problem of technical feasibility as it relates to long-life legacy equipment. We will address that issue below and note here simply that cost is a relevant consideration for those purposes, and recourse to reasonable business judgment is unnecessary to confirm that or to address the problem appropriately. Beyond that we disagree that deleting references to reasonable business judgment will lead to overly burdensome requirements or counterproductive results. For example, we disagree with Tampa Electric that without the leeway afforded by reasonable business judgment responsible entities would be forced into cost-prohibitive controls that do not add value in terms of security. No explanation was provided as to how this might occur. The Commission acknowledged the validity of cost considerations in the CIP NOPR and reaffirms that position here. The funds available for cyber security will not be infinite and, therefore, a responsible entity will need to make careful judgments to ensure that available funds are spent effectively. We do not see how the absence of references to reasonable business judgment will prevent this from happening.
133. Finally, some commenters link the need for flexibility with the problem of liability. We are keenly aware that unlike many other aspects of Bulk-Power System operations, cyber security represents a new and rapidly developing field. In other areas, the substance of appropriate practices is well established and well understood, but there can be considerably more uncertainty in the cyber security realm. Responsible entities therefore quite understandably wish to have, in Entergy's words, assurances that their actions meet the CIP Reliability Standards and Requirements if they act in good faith, perform the proper evaluation, and act consistent with their evaluation. We agree that they should have such assurances, but we disagree that references to reasonable business judgment are an appropriate way to provide such assurances. The real issue is whether responsible entities take reasonable and prudent actions based on an informed understanding of the current state of cyber security practice and how it applies to their situation. The Commission, therefore, disagrees with AMP-Ohio and Mr. Brown that the absence of references to reasonable business judgment will lead to a strict liability enforcement regime.
134. We disagree with Mr. Brown's claim that removal of reasonable business judgment could lead to liability for individual managers under section 215 of the FPA. That section applies to users, owners, and operators of the Bulk-Power System, and any liability arising under section 215 applies to them, not their employees.
135. Although we disagree with National Grid and others that alternative language is necessary to ensure necessary flexibility, we agree that the ERO and the participants in the Reliability Standards development process may choose to develop alternative language to replace reasonable business judgment and propose it for Commission approval. Such language would need to be adapted to the issues involved in forming judgments on proper cyber security measures and embody an objective standard focused on conduct that promotes the interests of Bulk-Power System security and reliability. Such language would also need to take into consideration our finding discussed below that a responsible entity cannot excuse itself from compliance with a requirement of the CIP Reliability Standards.
136. In response to the Southwest TDUs, we note that the CIP Reliability Standards apply in the same way to both public and private users, owners, and operators of the Bulk-Power System. Any specific issues that Southwest TDUs have with the Reliability Standards should be raised in the Reliability Standards development process.
137. Finally, we reject arguments that we are being overly prescriptive in directing the ERO to remove all references to reasonable business judgment from the CIP Reliability Standards. We discuss that general issue elsewhere in this Final Rule and will not repeat that discussion here. It is, however, important to note that such objections are inapposite in this instance for an additional reason that involves the specific nature of the issue raised. The concept of reasonable business judgment speaks to a general legal standard of conduct proposed to apply under a statute that Congress has directed the Commission to administer. It does not involve matters specific to
138. Based on the above discussion, as well as our lengthy analysis in the CIP NOPR, the Commission directs the ERO to modify the CIP Reliability Standards through its Reliability Standards development process to remove references to reasonable business judgment before compliance audits begin.
139. The Commission explained in the CIP NOPR that some Requirements in the CIP Reliability Standards permit an entity not to take the actions specified in the Requirement if they “document compensating measures applied to mitigate risk exposure or an acceptance of risk.”
140. Numerous commenters, including NERC, support the removal of acceptance of risk language, provided that this is accomplished using NERC's Reliability Standards development process.
141. EEI, FirstEnergy, Manitoba Hydro and others contend that the proposal to remove the acceptance of risk language from the CIP Reliability Standards mandates a specific outcome and fails to allow for consideration of alternatives to address the Commission's concerns in the NERC Reliability Standards development process. FPL recommends directing the ERO to consider the issue and either (1) make the appropriate modifications based on the Commission's concerns or (2) provide justification for an acceptance of risk provision. EEI states that the Commission's concerns regarding this language are valid, but should be reasonably tempered by the Commission's expectation that industry will use the mutual distrust posture.
142. Some commenters suggest alternate language to replace the term “acceptance of risk.”
143. A number of other commenters, including Tampa Electric, note that it is not possible to eliminate all risks and state that the goal should be to minimize risks to an acceptable level that still allows business processes to function. Idaho Power states that all businesses carry and accept some level of risk, and it is not appropriate to shift the burden to the company, ratepayer or shareholder to develop systems that may remove all risk. A company can perform an analysis of risk to determine a risk level that delivers an adequate level of security for the company, neighboring utilities and consumers, while remaining manageable to the company from a cost standpoint.
144. APPA/LPPC agree that the CIP Reliability Standards cannot be ignored simply because a company deems a risk acceptable, but believe that the intent of this language was to provide a degree of discretion where compliance is perceived to pose a greater risk to critical asset availability than non-compliance. They envision situations where it is reasonable to conclude that compliance poses a significant risk in the specific instances where acceptance of risk language appears. For example, with respect to Requirement R3.2 of CIP 007-1 (security patch management), inadequately tested patches can pose a risk of system failure, and an entity must weigh the risk of using software with a known flaw against the risk that the vendor's patch will introduce even greater risk.
145. Tampa Electric maintains that the impact of risk to the grid should be weighed before disallowing acceptance of risk. References to acceptance of risk should not be removed because, when a measure is not technically feasible, an effective compensatory control or mitigation, short of replacing the system, is not always possible. In addition, acceptance of risk is not always based on cost reasons. A compensatory step could cause safety issues or some other process problem that makes it highly undesirable.
146. Mr. Brown states that acceptance of risk does not permit an entity simply to decline compliance. The intent was to require explanation, mitigation efforts, evaluation of the potential ramifications of accepting the risk, or other accountability to demonstrate how the CIP Reliability Standards are being complied with in essence. Mr. Brown states that greater transparency is welcome, but removing the language does not mean that such decisions will no longer be made. Rather it will result in such decisions being kept out of sight.
147. FPL Group states that the CIP Reliability Standards provide guidance that allows documentation of measures taken to mitigate risk exposure or an acceptance of risk. This guidance is reasonable and based on control system best practices. It allows responsible entities to evaluate the value of the mitigation with regard to operability and reliability of the Bulk-Power System in comparison to overall feasibility. Responsible entities should not have to bear unreasonable burdens for mitigation that yields only limited benefit. Responsible entities can make the determination to accept the risk-based on reasonable technical judgment insofar as there is no material negative impact to the Bulk-Power System.
148. Entergy opposes eliminating acceptance of risk. It argues that acceptance of risk by senior management is a long-established practice and predates the CIP Reliability Standards. Because of legacy technology, removing this option would require expenditure of significant
149. With regard to CIP-007-1, MidAmerican supports the proposal to eliminate acceptance of risk from Requirement R2.3 but believes the term should remain in Requirement R3 if accompanied by a mitigation plan and sunset provision. MidAmerican argues that, by requiring a mitigation plan and a time frame for compliance, the CIP Reliability Standard would provide needed flexibility while maintaining the certainty of a committed end-date.
150. The Commission continues to view the term “acceptance of risk” as representing an uncontrolled exception from compliance that creates unnecessary uncertainty about the existence of potential vulnerabilities. Responsible entities should not be able to opt out of compliance with mandatory Reliability Standards. The Commission, therefore, directs the ERO to remove acceptance of risk language from the CIP Reliability Standards.
151. In response to concerns raised by NERC, EEI and others, we agree that this action should occur through the Reliability Standards development process. In response to the concerns of many commenters who argue that it should be possible to propose alternative language, we note that this is consistent with the Reliability Standards development process. However, any alternative language that provides a similar opportunity for a responsible entity to opt out of compliance would be subject to remand. Rather, the Commission believes that alternative language that deals with such issues in terms of technical feasibility is preferable. To that end, we have adapted the concept of technical exceptions to encompass a broader range of valid justifications. Elsewhere in this Final Rule we address the criticism that our actions are overly prescriptive and those remarks apply equally here.
152. Expanding the use of the technical feasibility conditions would address the desire for flexibility expressed by some commenters while providing the control that the Commission finds to be necessary. It would provide for documentation, reporting and approval of how responsible entities have elected to comply with the CIP Reliability Standards and thus would permit the ERO and Regional Entities to assess the significance of any possible vulnerability. As to the argument by METC-ITC that a technical feasibility exception may not be possible in all cases, we note that we have found that technical feasibility should not be limited simply to whether something is technically possible but also whether it is technically safe and operationally reasonable. Thus, this approach addresses the issue of inadequately tested patches raised by APPA/LPPC, and similar general concerns raised by Tampa Electric.
153. In response to Entergy, we note that a long-established practice of risk acceptance by senior management does not mean that a continuation of this practice is appropriate under a new system of mandatory cyber security Reliability Standards. We have addressed Entergy's concerns about costs-related legacy equipment in connection with technical feasibility.
154. Many commenters defend retention of the acceptance of risk language by pointing out that it is impossible to eliminate all risk. While likely true, it is beside the point. The acceptance of risk language in the CIP Reliability Standards fails to acknowledge that the real issue is whether the nature and level of inevitable risk is acceptable from a system-wide perspective. Within a system of CIP Reliability Standards intended to protect the Bulk-Power System as a whole, that problem can be addressed by a system that documents and reports the risks in question and ultimately subjects them to approval by the ERO or Regional Entities. The Commission's concern in the CIP NOPR was with the lack of appropriate controls, and eliminating references to acceptance of risk does not imply that all risk can be eliminated.
155. We disagree with Mr. Brown that mutual distrust means that risks accepted by one entity do not affect others on an interconnected control system. A mutual distrust approach is a good security posture. However, its value depends on how well it is implemented. There will likely be a variety of levels of sophistication applied to implementing mutual distrust. It is not a basis for allowing other responsible entities to ignore their obligations under mandatory CIP Reliability Standards.
156. Accordingly, the Commission directs the ERO to develop through its Reliability Standards development process revised CIP Reliability Standards that eliminate references to acceptance of risk.
157. As the Commission explained in the CIP NOPR, two proposed CIP Reliability Standards provide exceptions from compliance with Requirements based on “technical feasibility.”
Technical feasibility refers only to engineering possibility and is expected to be a “can/cannot” determination in every circumstance. It is also intended to be determined in light of the equipment and facilities already owned by the responsible entity. The responsible entity is not required to replace any equipment in order to achieve compliance with the Cyber Security Standards. When existing equipment is replaced, however, the responsible entity is expected to use reasonable business judgment to evaluate the need to upgrade the equipment so that the new equipment can perform a particular specified technical function in order to meet the requirements of these standards.
158. Based on these concerns, the Commission proposed in the CIP NOPR to allow, in the near term, exceptions from compliance based on the concept of “technical feasibility” in a limited set of circumstances, but also stated that responsible entities should not be permitted to invoke technical feasibility on the basis of “reasonable business judgment.” In addition, a responsible entity should not be able to except itself unilaterally from a Requirement of a mandatory CIP Reliability Standard with no oversight.
159. Thus, the Commission proposed in the CIP NOPR to direct that the ERO establish a structure to require accountability from those who rely on “technical feasibility” as the basis for an exception. The CIP NOPR described such a structure as requiring a responsible entity to: (1) Develop and implement interim mitigation steps to address the vulnerabilities associated with each exception; (2) develop and implement a remediation plan to eliminate the exception, including interim milestones and a reasonable completion date; and (3) obtain written
160. The Commission stated in the CIP NOPR that this proposed structure should include a review by senior management of the expediency and effectiveness of the manner in which a responsible entity has addressed each of these three proposed conditions. In addition, the Commission proposed to require a responsible entity to report and justify to the ERO and the Regional Entity for approval each exception and its expected duration. In situations where any of the proposed conditions are not satisfied, the Commission proposed that the ERO or the Regional Entity would inform the responsible entity that its claim to an exception based on technical feasibility is insufficient and therefore not approved. Failure to timely rectify the deficiency would invalidate the exception for compliance purposes.
161. The Commission stated its belief that it is important that the ERO, Regional Entities and the Commission understand the circumstances and manner in which responsible entities invoke the technical feasibility provision as well as other provisions that function as exceptions to the CIP Reliability Standards. The Commission, therefore, proposed to direct the ERO to submit an annual report that would include, at a minimum, the frequency of the use of such provisions, the circumstances or justifications that prompt their use, the interim mitigation measures used to address the vulnerabilities, and the milestone schedule to eliminate them and to bring the entities into compliance to eliminate future reliance on the exception.
162. The Commission sought comment on additional categories of information that should be included in the content of this report that would be useful for the Commission, as well as the ERO and Regional Entities, in evaluating the invocation of technical feasibility and similar provisions, and the impact on protection of critical assets.
163. Finally, the Commission proposed to direct the ERO to consider making “technically feasible,” and derivative forms of that phrase as used in the CIP Reliability Standards, defined terms in the NERC Glossary, pursuant to the prior clarifications, without any reference to reasonable business judgment.
164. Below, we first address issues related to the general rationale underlying technical feasibility exceptions. We then address issues connected with documentation of exceptions and their remediation and mitigation. Finally, we address the approval of these exceptions.
165. Numerous commenters focused on the need for technical feasibility exceptions generally and their underlying rationale. Most support technical feasibility exceptions in some form.
166. Texas Commission expresses concern that technical feasibility could be used to justify inaction. It states that flexibility can be achieved by other means, but if reference to technical feasibility is retained, responsible entities should not be allowed to use it to avoid taking necessary action. Texas Commission comments that it is reasonable to develop a process under which entities with known vulnerabilities self-report to NERC and the Regional Entity and provide a timeline for correcting these deficiencies.
167. NERC states that the Commission properly recognized the appropriateness of an exception based on technical feasibility and suggests that it be designated an “exemption for reliability.”
168. NERC and others believe that the appropriate way to address the Commission's specific proposed directives is through the Commission-approved Reliability Standards development process.
169. NERC explains that the CIP Reliability Standards include references to technical feasibility to recognize that, in many cases, equipment in place in substation and generating plant environments was implemented with operational functions paramount to all other considerations, including security. This equipment is not at the end of its useful life and historically has not been designed with ready access to software updates and patches. Such software upgrades that could increase functionality without directly contributing to reliability generally have not been made. NERC states that modern replacement equipment is more readily compatible with an environment where updates and patches are more commonplace and security functionality is an understood necessity. Securable equipment will be used when equipment is replaced due to natural end-of-life or failure, but this modern equipment represents a very small percentage of the installed base of all cyber equipment in substations and generating plants.
170. Many commenters, including APPA/LPPC, Duke, Entergy, NRECA and ReliabilityFirst, concur with this explanation of rationale for the references to technical feasibility. Duke agrees that technical feasibility exceptions should be controlled, but it argues that replacing legacy equipment on an accelerated schedule could create industry-wide logistical problems and unwarranted ratepayer impacts. NRECA maintains that rapid replacement of equipment would mean costs for customers, could overwhelm the supply chain, and could lead to premature obsolescence of replacement equipment as security technology continues to improve. Consumers Energy states that technical feasibility exceptions are proposed as a last resort that is forced by the limitations of available technology, support and service limitations of existing technology, and as-built limitations.
171. Entergy maintains that the older equipment in question generally cannot be compromised through typical hacker techniques, and physical access to it is often required. This presents greater challenges for attackers and means that only local impact will result from a successful attack. Entergy recommends allowing industry three to five years to upgrade critical assets with modern cyber controls that will provide the needed operational efficiency
172. ReliabilityFirst notes that a very small percentage of the installed base of all cyber equipment in substations and power plants incorporates security functionality. Consumers Energy explains that older control systems can still be very reliable, but many assets identified as critical cyber assets do not have malware and virus protection, in some cases due to technology conflicts with virus and malware protection systems. In addition, managing updates on devices that are continuously online is a difficult task. Consumers Energy states that there are adequate alternate measures in such cases such as firewalls with content security functions that restrict any options for infecting systems with viruses and that implement intrusion detection for the perimeter with advanced content security services.
173. NERC states that the drafting team believed that cyber security standards should not unnecessarily impede the primary mission of maintaining reliable Bulk-Power System operations. NERC and ReliabilityFirst argue that changes must be carefully planned and tested to ensure that no unintended consequences occur. Technologies are constantly evolving, and it is impractical to think that equipment always can maintain a leading-edge cyber security posture without introducing operating issues.
174. Manitoba Hydro states that industry attempted to strike a balance for security at the various types of facilities while recognizing the large base of legacy systems at remote locations. The security framework focused on routable protocols and dial up access. The Commission's proposals to limit technical feasibility exceptions and implement a defense in depth measure in front of legacy systems would have a nominal impact on control centers but a significant impact on other facilities, systems and equipment, forcing unjustified early equipment replacement or installation of technology to provide mitigating controls. Manitoba Hydro argues that modifying the Reliability Standards on this point could add considerable work for responsible entities and require modifications to the implementation period.
175. Northern Indiana, Ontario Power and SoCal Edison support retaining the term technical feasibility. Ontario Power maintains that removing references to technical feasibility could be interpreted by some to mean that mandatory compliance is required, regardless of the cost, the impact on production systems, or the risk to the Bulk-Power System. Northern Indiana concurs with the Commission's proposal to treat instances of technical infeasibility as exceptions that require reporting and certain alternative courses of action. However, it disagrees with what it describes as the Commission's restrictive interpretation of the term and urges the Commission to acknowledge that technical infeasibility may apply to future assets as well. Northern Indiana advocates that the Commission instead direct NERC to interpret technical feasibility narrowly with regard to the technical characteristics of both existing and future assets. Northern Indiana states that the Commission should not assume technical infeasibility will exist only during the transition period and not afterwards, nor should it assume only one single means will exist, on a going forward basis, to comply with the Reliability Standards.
176. Mr. Brown states that technical feasibility has less to do with whether to comply than with how to comply. Whether or not something is technically feasible is purely an engineering issue. On the other hand, whether or when to replace equipment that cannot do something due to technical feasibility with equipment that can do so is purely a managerial decision. Mr. Brown states that in light of his interpretation of reasonable business judgment, the Commission should have much less concern about the interplay between technical feasibility and reasonable business judgment.
177. Teltone states that it is now easy to incorporate CIP-related features such as two-factor authentication (with unique user names and passwords) to both dial-up and Internet protocol devices without replacing them, upgrading their software, or taking them offline. Access and usage logging of legacy devices at substations is easily accomplished, something Teltone maintains should quell the problem of technical feasibility.
178. The Commission adopts the CIP NOPR proposal and directs the ERO to develop a set of conditions or criteria that a responsible entity must follow when relying on the technical feasibility exception contained in specific Requirements of the CIP Reliability Standards. We will modify some of our proposed criteria for that framework of accountability further below. We are persuaded by commenters that the proposed conditions for invoking the technical feasibility exception should allow for operational considerations. In response to Northern Indiana and other commenters, we note that the Commission did not propose to eliminate references to technical feasibility from the CIP Reliability Standards, only that the term be interpreted narrowly and without reference to considerations of business judgment.
179. In response to those commenters who argue that the Commission's concerns and directives should be addressed through the Reliability Standards development process, we agree that to the degree revisions to the Reliability Standards are necessary to address our concerns, they would be made through that process. We disagree, however, with the arguments that claim we are rewriting the CIP Reliability Standards or adhering to a one-size-fits-all approach. With respect to the latter point, we note that technical feasibility issues are by their nature something that must be dealt with on a case-by-case basis, as they only arise in specific circumstances. Our concern here is primarily with the framework within which decisions on technical feasibility are made and ensuring that this framework promotes sound decisions that lead to effective results. The oversight provisions we describe below are essential elements of such a framework.
180. We agree with NERC and other commenters on the underlying rationale for a technical feasibility exception, i.e., that there is long-life equipment in place that is not readily compatible with a modern environment where cyber security issues are an acknowledged concern. While equipment replacement will often be appropriate to comply with the CIP Reliability Standards, such as in instances where equipment is near the end of its useful life or when alternative or supplemental security measures are not possible, we acknowledge that the possibility of being required to replace equipment before the end of its useful life is a valid concern.
181. The Commission, however, disagrees with Northern Indiana that technical feasibility should be interpreted to apply to future assets also. The justification presented for technical feasibility exceptions is rooted in the problem of long-life legacy equipment and the economic considerations involved in the replacement of such equipment before the end of its useful life. We recognize that these considerations can be valid in some cases, but Northern Indiana has not explained why technical feasibility exceptions should apply to replacement equipment. The Commission neither assumes that technical infeasibility issues will be present only during the transition period, nor does it assume
182. The Commission agrees with various commenters that the implementation of the CIP Reliability Standards should not be permitted to have an adverse effect on reliability and that proper implementation requires that care be taken to avoid unintended consequences. We thus believe it is important to clarify that the meaning of “technical feasibility” should not be limited simply to whether something is technically possible but also whether it is technically safe and operationally reasonable.
183. We disagree with Mr. Brown's view that whether or when to replace equipment that cannot do something due to technical feasibility with equipment that can do so is purely a managerial decision, especially since he intertwines this proposition with the concept of reasonable business judgment. While we accept NERC's rationale for technical feasibility exceptions, as discussed below, an integral issue in individual cases where legacy equipment presents a technical feasibility issue is whether an alternative course of action protects the reliability of the Bulk-Power System to an equal or greater degree than compliance would. This is not a purely managerial decision involving reasonable business judgment, regardless of what meaning one imparts to that term.
184. While a number of commenters agree that it is important to clarify the meaning of technical feasibility, none appear to support defining the term in the NERC Glossary. Therefore, in light of the comments received generally and the specific guidance that we are providing to the ERO in connection with technical feasibility, we conclude that a definition of this type is unnecessary. A definition cannot substitute for a framework of conditions or criteria to provide accountability, and if those conditions or criteria are implemented, a definition is not needed. We do not agree with NERC that replacing the term technical feasibility with “exemption for reliability” would be helpful. We note, in particular, that an “exemption” normally is understood to be a release from an obligation whereas what is under discussion here is an exception that forms an alternative obligation.
185. While the Commission will not address the merits of any particular technology, we note that Teltone's comments raise an important general consideration when developing policy on technical feasibility. While technical limitations present real issues, and while one should not be overly optimistic that technological developments will resolve them sooner than expected, one should not be overly pessimistic either. Indeed, high standards should, if anything, encourage the development of technical solutions.
186. Based on the above considerations, the Commission adopts its proposal in the CIP NOPR that technical feasibility exceptions may be permitted if appropriate conditions are in place. The term technical feasibility should be interpreted narrowly to not include considerations of business judgment, but we agree with commenters that it should include operational and safety considerations.
187. As mentioned above, in the CIP NOPR, the Commission proposed a three step structure to require accountability when a responsible entity relies on technical feasibility as the basis for an exception. This proposed structure would require a responsible entity to: (1) Develop and implement interim mitigation steps to address the vulnerabilities associated with each exception; (2) develop and implement a remediation plan to eliminate the exception, including interim milestones and a reasonable completion date; and (3) obtain written approval of these steps by the senior manager assigned with overall responsibility for leading and managing the entity's implementation of, and adherence to, the CIP Reliability Standards, along with regional approval through the ERO.
188. NERC supports clarification of the CIP Reliability Standards to ensure that the use of a technical feasibility exemption must be documented and justified in terms of its impact on Bulk-Power System reliability. Duke also agrees with the proposal to require documentation, including appropriate mitigation and a senior management-approved remediation plan.
189. National Grid states that the Commission's mitigation proposal is reasonable and appropriate, but it maintains that the Commission should clarify that acceptable mitigation for older assets entails measures short of replacement, upgrades, or retrofits. A mitigation requirement otherwise would undermine any relief associated with an exception. Mitigation measures for vulnerabilities associated with older assets will need to be in place as long as those assets remain in service. National Grid states that the Commission's references to “interim” mitigation and remediation implementation milestones could suggest that older assets must be replaced before the end of their useful lives or that the mitigation measures would not be as effective as the solutions codified in the Reliability Standards. National Grid argues that mitigation measures should be as or more effective than compliance, and in the case of minor technical or administrative requirements, replacement of certain assets before the end of their useful lives would be wasteful and inefficient.
190. SPP believes it is reasonable to treat technical feasibility as a documented exception. Such exceptions should be reviewed and approved annually, but identifying a reasonable completion date for remediation may not always be possible. SPP states that to require remediation of a technical feasibility exception by a date certain is contrary to the Commission's acknowledgement that cost can be a prohibiting factor. Technical limitations may prohibit compliance with a requirement. The appropriate response in such cases is to mitigate the risk by implementing compensating measures. SPP questions the need for remediation where compensating measures are equally effective in reducing risk. It recommends that responsible entities be required initially to mitigate the risk and then evaluate and document whether further remediation is required and technically feasible as part of the exception approval process.
191. Northern Indiana believes a remediation plan should seek to eliminate the exception to the extent possible, but complete elimination may not be possible in all cases. Northern Indiana states that the Commission should consider the development and implementation of a remediation plan to eliminate the exception to the extent possible. Tampa Electric submits that it is unreasonable to require a remediation plan in every case. Sometimes there is no technology that would permit compliance with the letter of the CIP Reliability Standard.
192. With some minor refinements discussed below, the Commission adopts the CIP NOPR proposal for a
193. We also agree with Northern Indiana that in some instances remediation can be required only to the extent possible. For example, in some cases it may never be possible to enclose certain critical cyber assets within a six-sided physical boundary as required under CIP-006-1. However, such cases need to be sufficiently justified, the mitigation strategies must be ongoing and effective, and the justification must be subject to periodic review. We also are mindful that accelerated replacement of equipment can be economically wasteful where security is not otherwise compromised. We thus agree with National Grid that where mitigation measures are as or more effective than compliance, and in the case of minor technical or administrative requirements, replacement of certain assets before the end of their useful lives can be wasteful and inefficient. We also agree with SPP that remediation might not be necessary where compensating measures are equally effective in reducing risk. However, such cases must be subject to clear criteria and periodic review and, where necessary, updates.
194. However, in adopting this approach, we do not intend to suggest that it would never be necessary to replace equipment before the end of its useful life to achieve cyber security goals. Where equipment is near the end of its useful life or if insufficient mitigation measures are available, the equipment should be replaced. However, such situations must be dealt with on a case-by-case basis. We emphasize that responsible entities must protect assets that are critical to the reliable operation of the Bulk-Power System.
195. This section discusses the Commission's directions with regard to approval of a technical feasibility exception, the third component of our framework for allowing technical feasibility exceptions. As described above, the CIP NOPR proposed that NERC develop a requirement that a responsible entity relying on the technical feasibility exception must obtain written approval of a remediation plan by a senior manager.
196. California Commission states that approval of technical feasibility exceptions by the ERO and the relevant Regional Entity is critical because it prevents attempts to manipulate the system and induces responsible action.
197. National Grid supports providing Regional Entities with notice of technical feasibility exceptions and audits of exceptions by Regional Entities. It states that a central clearinghouse that catalogs all technical feasibility exceptions would be helpful because of the interdependencies among the Bulk-Power System assets. This clearinghouse could verify whether reliance on exceptions (or the associated mitigation measures) adequately maintains reliability and does not create reliability issues for neighboring systems. ISO-NE states that reporting exceptions to Regional Entities would be useful in identifying CIP Reliability Standards and Requirements with frequent implementation issues that call for modifications.
198. In contrast, ISO/RTO Council, EEI and others do not believe that reporting and approval of technical feasibility exceptions is appropriate.
199. ReliabilityFirst argues that a responsible entity's senior manager must already approve any exceptions, making reporting and approval unnecessary, and it will be very difficult for the ERO or Regional Entity staff to review a responsible entity's exceptions effectively and assess them realistically. SERC-CIPC recommends that the requirement to authorize and document exceptions remain with the entity's designated senior manager.
200. ISO/RTO Council argues that granting the Regional Entities authority to adjudicate exceptions along with the ability to apply sanctions for non-compliance creates a conflict of interest. Auditors should be independent, and an assessor should not be involved with review and approval of policy exceptions. ISO/RTO Council argues that instead of requiring that exceptions be reported and justified, the Commission should consider directing the ERO to detail the type of justifications and considerations that must be documented when invoking a technical feasibility exemption. Responsible entities would then be required to incorporate them into their analysis of possible exemptions.
201. EEI, OGE and SoCal Edison question how the ERO and Regional Entities would determine what is technically feasible for a particular model of equipment in a specific context. If there is to be external review and approval, there should be an appeals process, and that would delay implementation of future revisions to the CIP Reliability Standards. Alliant, EEI and Tampa Electric believe that NERC should require that decisions on technically feasible be subject to audits
202. Northern Indiana seeks clarification of the information that will be needed to justify an exception. It suggests that, similar to the Commission's proposed approach regarding self-certification, a responsible entity should have the opportunity to consult with the ERO and Regional Entities. Northern Indiana also advocates the waiver of monetary penalties during this time as well as within the timeframe of any remediation plan.
203. APPA/LPPC state that the Commission should clarify that when a Regional Entity or the ERO rejects a technical feasibility exception request, the responsible entity may rely on the exception until it has been ruled upon. In addition, the organization should be allowed a reasonable time to come into compliance.
204. Entergy states that there is no indication that the benefits of reporting exceptions would outweigh the detriments, but if further reporting is required, it recommends a single annual report from each registered entity that includes a summary description of the exceptions and actions taken or to be taken. The ERO could use this report to satisfy its annual reporting requirement.
205. A number of other commenters emphasize the sensitivity of information about technical feasibility exceptions. SPP states that an annual report must contain information that qualifies as Critical Energy Infrastructure Information (CEII) to be of any value. SERC-CIPC also recommends CEII treatment for this information. SPP is concerned that if the report is not treated as CEII, sensitive data could be inadvertently made public. To protect against disclosure, SPP proposes that the ERO could make exception documentation available for Commission staff inspection in the ERO offices as a possible alternative to a report. National Grid states that information about exceptions should be subject to adequate information protection controls to avoid disclosure and misuse.
206. Duke opposes an annual report by the ERO to the Commission because, even if it does not contain CEII, it will compromise security by publicly identifying problem areas for the industry and the mitigation measures being employed. If a report must be submitted, there must be stringent and enforceable confidentiality measures to prevent inadvertent or unauthorized disclosure. OGE believes reporting and approval for all exceptions is contrary to the purpose of the CIP Reliability Standards because information on exceptions sent to the ERO or Regional Entity could indicate weaknesses in security that could be compromised and exposed. These same concerns lead Xcel to urge that Regional Entities develop confidentiality protocols for such communications.
207. ISO-NE states that detailed technical descriptions of exceptions should not be passed to the Regional Entities or the ERO because the information would be potential vulnerability information that the responsible entity should protect as critical cyber asset information under CIP-003-1, Requirement R4. Tampa Electric states that, if the Commission decides to require ERO or Regional Entity review, it should also prescribe controls to ensure the confidentiality and security of the information under review.
208. Although not commenting specifically on reporting of technical feasibility issues, Bonneville notes that under the Freedom of Information Act (FOIA), release of information to an external party generally waives any privileges against disclosure with respect to subsequent requests to the federal agency for that same information. Bonneville is concerned that submission of critical asset information to the Regional Entity, particularly the vulnerability-related rationales for including and excluding various facilities on the critical asset list, may act as such a waiver.
209. For the reasons discussed below, the Commission concludes that technical feasibility exceptions should be reported and justified and subject to approval by the ERO or the relevant Regional Entity. The Commission thus adopts its CIP NOPR proposal that use and implementation of technical feasibility exceptions must be governed by a clear set of criteria. However, because we are persuaded by the commenters, we have modified certain elements of our original proposal, as discussed below.
210. Most objections to the CIP NOPR proposal regarding the review and approval of technical feasibility exceptions are not objections in principle but rather focus on practical issues of implementation, such as limited ERO and Regional Entity resources and sensitivity of the information in question. To the extent that objections in principle have been raised, we disagree. Thus, we disagree with ReliabilityFirst's argument that senior manager approval of exceptions is unnecessary because of the responsibilities already assigned to the senior manager by CIP-003-1. These technical feasibility exceptions implicate matters that go beyond the purview of individual responsible entities and must be subject to review and approval by those with a wider-area view and general responsibility for system reliability. We also disagree with the ISO/RTO Council that the Commission should simply direct the ERO to detail the type of justifications and considerations that must be documented when invoking a technical feasibility exemption. While such guidance could be useful, it cannot substitute for reporting, review, and approval, which is necessary to address concerns that extend beyond the reach of an individual responsible entity.
211. With regard to the senior management approval, we continue to believe that internal approval is an important component of an overall framework of accountability with regard to use of the technical feasibility exception. Therefore, we adopt this aspect of our CIP NIPR proposal and direct the ERO to include approval of the mitigation and remediation steps by the senior manager (identified pursuant to CIP-003-1) in the course of developing this framework of accountability.
212. However, the practical considerations pointed out by a number of the comments have convinced us to adopt an approach to the issue of external oversight different from the one originally proposed. We agree, in particular, with those commenters who argue that pre-approval could tax ERO and Regional Entity resources, delay implementation, and possibly create undue risks that sensitive information will be disclosed.
213. The Commission agrees with National Grid that Regional Entities should, in the first instance, receive and catalogue notices of technical feasibility exceptions that are claimed. Such notices must include estimates of the degree to which mitigation measures achieve the goals set by a CIP Reliability Standard and be in sufficient detail to allow verification of whether reliance on exceptions (or the associated mitigation measures) adequately maintains reliability and does not create reliability issues for neighboring systems. Initial submission of notices should be provided by responsible entities at least by the “Compliant” stage of implementation in order to allow Regional Entities to plan for
214. The Commission also agrees with National Grid, EEI and others that actual evaluation and approval of technical feasibility exceptions should be performed in the first instance in the audit process. This would allow assessment of exceptions within their specific context and thus facilitate greater understanding in evaluating individual exceptions, as well as related mitigation steps and remediation plans. This also would increase the amount of sensitive information that remains on-site and reduces the risk of improper disclosure. In addition, it will allow the ERO and Regional Entities, informed by the initial notices discussed above, to include personnel in audit teams with sufficient expertise to judge the need for a technical feasibility exception and the sufficiency of preferred mitigation measures.
215. Given the significance of technical feasibility exceptions, the Commission believes that initial audits of technical feasibility exceptions should be expedited, i.e., performed earlier than otherwise, including moving the audit to an earlier year. Also, in general, responsible entities claiming such exceptions should receive higher priority when determining which entities to audit, and the more exceptions an entity has, the higher the priority for audit should be. Further, NERC may provide an appeals process for the review of technical feasibility exceptions, if it determines that this is appropriate.
216. However, the Commission notes that the audit process is a Regional Entity and ERO process, and audit team findings regarding exceptions are subject to Regional Entity and ERO review. The Commission believes that the audit report should form the basis for ERO or Regional Entity approval of individual exceptions. Approval thus represents a determination on compliance with the applicable CIP Reliability Standards, and we disagree with the ISO/RTO Council that approval of technical feasibility exceptions raises any conflict of interest or due process concerns. The proposed procedures raise no special issues in this respect.
217. We agree with EEI and others that approvals and potential appeals should not be allowed to delay implementation, but we believe our revised proposal resolves this problem. We also agree with APPA/LPPC that responsible entities should be able to rely on a technical feasibility exception prior to formal approval. However, we disagree with Northern Indiana that penalties should be waived within the time when an approved remediation plan is being implemented, as proper implementation of the plan itself constitutes a necessary element of compliance.
218. In summary, on the issues pertaining to external approval of a responsible entity's use of the technical feasibility exception, rather than a pre-approval process, we direct the ERO to design and conduct an approval process through the Regional Entities and the compliance audit process. This process should require the ERO or a Regional Entity to approve any technical feasibility exception, taking into account whether the technical feasibility exception is needed and whether the mitigation and remediation steps are adequate to the circumstance.
219. We agree with comments emphasizing the importance of protecting sensitive information relating to technical feasibility exceptions. We agree with SPP and others that CEII treatment should be available for any such information. In response to Bonneville, we agree that a governmental entity subject to FOIA requirements should not be required to submit sensitive information about critical assets or critical cyber assets that could be deemed a waiver of FOIA protection that is otherwise available. Nonetheless, a governmental entity's decision to rely on a technical feasibility exception should also be subject to appropriate oversight and accountability. Thus, we direct NERC, in developing the accountability structure for the technical feasibility exception, to include appropriate provisions to assure that governmental entities that are subject to Reliability Standards as users, owners or operators of the Bulk-Power System can safeguard sensitive information.
220. As stated in the CIP NOPR, the Commission believes that it is important that the ERO, Regional Entities and the Commission understand the circumstances and manner in which responsible entities invoke the technical feasibility exception.
221. While we agree with commenters that the compilation of data for the annual report must not compromise the security of the Bulk-Power System, we disagree that this is a reason not to require the report. Rather, as we indicated in the CIP NOPR, the report should not provide a level of detail that divulges CEII data. Rather, the report should contain aggregated data with sufficient detail for the Commission to understand the frequency with which specific provisions are being invoked as well as high level data regarding mitigation and remediation plans over time and by region. Further, we direct the ERO to control and protect the data analysis to the extent necessary to ensure that sensitive information is not jeopardized by the act of submitting the report to the Commission.
222. In conclusion, pursuant to section 215(d)(5) of the FPA, we direct the ERO to develop a set of criteria to provide accountability when a responsible entity relies on the technical feasibility exceptions in specific Requirements of the CIP Reliability Standards. As discussed above, structural elements of this framework include mitigation steps, a remediation plan, a timeline for eliminating use of the technical feasibility exception unless appropriate justification otherwise is provided, regular review of whether it continues to be necessary to invoke the exception, internal approval by the senior manager, wide-area approval through the ERO's audit process, and cooperation with the ERO to provide the Commission with high-level, wide-area analysis regarding the effects the technical feasibility exception on the reliability of the Bulk-Power System. We direct the ERO to develop appropriate modifications, as discussed above.
223. In the CIP NOPR, the Commission stated that it expects NERC
224. Congressional Representatives filed comments expressing their support for the Commission's efforts to require NERC to develop modifications to the CIP Reliability Standards. However, they believe that Bulk-Power System reliability will be better protected by cyber security standards that incorporate the security measures set forth in NIST Special Publication (SP) 800-53 as applied to industrial control systems. Congressional Representatives state that NIST research prepared a technical report comparing the proposed CIP Reliability Standards with SP 800-53. This technical report found that an organization conforming to the baseline set of security controls in SP 800-53 will also comply with the management, operational and technical security requirements of the CIP Reliability Standards, though the converse may not be true. The technical report concluded that the CIP Reliability Standards are both “inadequate for protecting critical national infrastructure,” and “inadequate for all electric energy systems when the impact of regional and national power outages is considered.”
225. Further, Congressional Representatives point out that federal government-owned elements of the Bulk-Power System must comply with both CIP Reliability Standards and NIST SP 800-53, while privately owned elements must comply only with the former. They express concern that “inconsistent regulatory structures create weak links and potential vulnerabilities in the entire system.”
226. NIST itself compliments the Commission for proposing a derivative of the CIP Reliability Standards that is an improvement over the original NERC CIP Reliability Standards. However, according to NIST, the CIP NOPR proposal still falls short of meeting the federal mandatory minimum security measures set forth in NIST Special Publication (SP) 800-53 as applied to industrial control systems. In NIST's view, the CIP Reliability Standards, if modified pursuant to the proposals in the CIP NOPR, will leave information systems that support private sector bulk electric power systems less protected than comparable federal information systems. NIST suggests that the Commission consider strengthening the minimum controls currently required by the CIP Reliability Standards.
227. NIST recommends that the Commission adopt the CIP Reliability Standards with the enhancements proposed by the Commission as an interim measure. Additionally, NIST advocates that the Commission prescribe plans for a two to three year transition to cyber security Reliability Standards that are identical to, consistent with, or based on SP 800-53 and related NIST standards and guidelines. NIST argues that this approach would strengthen the CIP Reliability Standards.
228. Although Entergy states that it generally disagrees with the Commission's approach of dictating specific revisions that the ERO must adopt, if the Commission determines that the CIP Reliability Standards require further development, Entergy argues that the Commission should modify its approach to the NIST Framework and require the ERO to consider it as a resource in developing revisions to the CIP Reliability Standards. Entergy argues that the industry needs immediate, clear direction and there already exists guidance that the Commission can rely on to provide such direction. Entergy notes that the NIST “Security Risk Management Framework” has been developed over many years by the U.S. Department of Commerce. The NIST Framework is devoid of conflicts of interest and has been broadly vetted, both domestically and internationally.
229. SDG&E states that, while it welcomes the use of industry standards in NERC CIP compliance, it cautions that NIST standards provide many controls that are considered best practices. It also explains that NIST was developed for government and some NIST standards that work well for government may be cost-prohibitive in the private sector.
230. Bonneville understands the Commission's directive that NERC consider NIST standards in the further development of the CIP Reliability Standards to apply to CIP-003-1. Bonneville suggests that existing guidelines, such as the NIST Special Publications, should be incorporated to the extent practicable. Bonneville argues that creating another set of directives describing how the standards are to be met without incorporating, or at least considering, existing guidelines could create considerable confusion and conflict.
231. Applied Control Solutions urges the immediate adoption of the NIST “Security Risk Management” framework in place of the CIP Reliability Standards. It explains that the NIST framework provides a hierarchical three-tiered set of countermeasure and controls requirement-sets for application as appropriate and related guidance documents. According to Applied Control Solutions, the NIST framework has been broadly vetted, is not onerous, provides guidance on how to address older in-service cyber assets, and allows flexibility for organizations to tune their cyber security programs for their specific operating scenarios. It also contends that NIST addresses the major concerns raised by the Commission regarding the CIP Reliability Standards, for example, by providing additional granularity and requiring compensating measures where technical feasibility becomes an issue. Applied Control Solutions also comments that the ISA-99 standards process has expertise, and NERC should be directed to work with ISA in revising the CIP Reliability Standards.
232. As proposed in the CIP NOPR, the Commission will not at this time direct NERC to incorporate specific provisions of the NIST standards into the CIP Reliability Standards. While commenters provide compelling information that suggests that the NIST standards may provide superior measures for cyber security protection, the Commission is concerned that the immediate adoption of the NIST standards would result in unacceptable delays in having any mandatory and enforceable Reliability Standards that relate to cyber security.
233. The Commission continues to believe—and is further persuaded by the comments—that NERC should monitor the development and implementation of the NIST standards to determine if they contain provisions that will protect the Bulk-Power System better than the CIP Reliability Standards. Moreover, we
234. Reliability Standard CIP-002-1 deals with the identification of critical cyber assets. The NERC Glossary defines “cyber assets” as “programmable electronic devices and communication networks including hardware, software, and data.” It defines “critical cyber assets” as “cyber assets essential to the reliable operation of critical assets.” NERC defines “critical assets” as “facilities, systems, and equipment which, if destroyed, degraded, or otherwise rendered unavailable, would affect the reliability or operability of the Bulk Electric System.”
235. As the first step in identifying critical cyber assets, CIP-002-1 requires each responsible entity to develop a risk-based assessment methodology to use in identifying its critical assets. Requirement R1 specifies certain types of assets that an assessment must consider for critical asset status and also allows the consideration of additional assets that the responsible entity deems appropriate. Requirement R2 requires the responsible entity to develop a list of critical assets based on an annual application of the risk-based assessment methodology. Requirement R3 provides that the responsible entity must use the list of critical assets to develop a list of associated critical cyber assets that are essential to the operation of the critical assets. CIP-002-1 requires an annual re-evaluation and approval by senior management of the lists of critical assets and critical cyber assets.
236. Pursuant to section 215 of the FPA, the Commission approves Standard CIP-002-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA, the Commission directs the ERO to develop modifications to Standard CIP-002-1. The required modifications are discussed below in the following topics regarding CIP-002-1: (1) Need for ERO guidance regarding the risk-based assessment methodology; (2) scope of critical assets and critical cyber assets; (3) internal, management, approval of the risk-based assessment; (4) external review of critical assets identification; and (5) interdependency analysis.
237. Requirement R1 of CIP-002-1 requires each responsible entity to develop a risk-based assessment methodology to identify critical assets. A responsible entity must maintain documentation describing its methodology that includes procedures and evaluation criteria. Requirement R1 identifies specific assets that the methodology must “consider,” including control centers, facilities critical to system restoration and automatic load shedding, and substations and generation resources that support reliable operation of the Bulk-Power System—as well as any other assets that support reliable operations and the responsible entity deems appropriate to include in its assessment.
238. In the CIP NOPR, the Commission expressed concern that responsible entities have enough guidance to devise an assessment methodology that is adequate to identify the types of assets necessary to protect Bulk-Power System reliability.
239. The CIP NOPR also noted that smaller entities may have difficulty in determining whether a particular asset is “critical” since the impact of the asset may be dependent on their connection with a transmission owner or operator. Thus, the Commission proposed that the ERO and Regional Entities provide reasonable technical support to relatively smaller registered entities to assist them in determining whether their assets are critical to the Bulk-Power System.
240. Many commenters, including NERC, agree with the Commission that there is a need for further guidance regarding the risk-based assessment methodology. Other commenters do not oppose the development of general guidance on what would constitute an acceptable risk-based assessment methodology, provided that this guidance does not rule out other approaches. Commenters also identify specific concerns that they believe would benefit from further guidance.
241. While first reiterating that the CIP Reliability Standards contain the appropriate specificity as performance based standards, NERC agrees that it could provide further guidance in the form of a “supplemental guideline” on performing risk-based assessments to be used to determine critical assets. NERC states that its Critical Infrastructure Protection Committee's Risk Assessment Working Group has begun development of such a guideline. NERC asserts that this guideline, when completed, will address the Commission's fundamental concern by providing guidance to responsible entities on how to perform the required risk-based assessments.
242. Numerous commenters agree that additional guidance is needed regarding a risk-based assessment methodology.
243. While EEI opposes any modification to Requirement R1 of CIP-002-1 to provide additional specificity regarding the assessment methodology, it agrees that responsible entities would benefit from “some basic guidance” provided that it is non-prescriptive.
244. A number of commenters identify specific topics that would benefit from further guidance. For example, NRC comments that the risk-based assessment should identify transmission lines, substations and generators that are relied on to operate or shut down nuclear generating stations as critical assets. U.S. Power maintains that additional guidance is needed as to when generating facilities and their related systems will be deemed “critical” to the Bulk Electric System. U.S. Power explains that, given the built-in reserve margin for generation in New England, absent a known local reliability need, any generator in New England could logically assume that none of its individual generating assets would be regarded “critical.” U.S. Power states that without additional guidance as to what the Commission and NERC intend, however, there is no way of knowing if this is an appropriate assumption. Further, it seeks additional guidance regarding blackstart units, noting that a generating unit that has blackstart capability but is not part of a system restoration plan may not be deemed critical to Bulk-Power System reliability.
245. Luminant comments that significant regional differences, such as geography, climate, demographics, electric system structure and demands, affect the identification of critical cyber assets and how the particular asset would be protected.
246. Several commenters agree with the Commission's statement that a risk-based assessment methodology should examine the consequences of the loss of the asset to the Bulk-Power System as well as the consequences if an adversary gains control of the asset. For example, Applied Control Solutions states that a proper risk-based assessment methodology should examine the consequences of the loss or improper operation of the assets to the Bulk-Power System. It also comments that the methodology should define “risk” as a formula (i.e., risk=frequency multiplied by consequence). Because there is insufficient data available to determine frequency, it should be assumed that an event will occur. Luminant also states that the risk-based assessment methodology should focus on the consequences of an outage, not the likelihood of an outage.
247. ISA99 Team suggests that the guidance to be developed by NERC should be written in a manner that assures that a larger portion of critical infrastructure assets, and associated cyber assets are included within the scope of the standards. In this regard, ISA99 Team states that the results of the current requirements, which are based on an unspecified “risk-based” approach, and which place no limits on what constitutes an acceptable risk, may or may not include sufficient assets to provide adequate protection for the bulk power grid. Thus, ISA99 Team argues that a more definitive means of assuring adequate scope needs to be established.
248. A number of entities commented on the Commission's proposal that the ERO and Regional Entities provide reasonable technical support to relatively smaller entities that may have difficulty determining whether a particular asset is critical because, for example, the impact of the facility may be dependent on their connection with a transmission owner or operator. NERC and ReliabilityFirst oppose this proposal, stating that such a “consulting service” would place an undue burden on the ERO and Regional Entities.
249. In contrast, FirstEnergy agrees that NERC should provide guidance to entities without a wide-area view, such as a generation owner or a partial generation owner, on how to approach a risk-based assessment. Likewise, Northern California suggests that NERC establish a process for informal, case-by-case consultations with responsible entities that need assistance in complying with CIP-002-1. In addition, as part of the re-examination of CIP-002-1, Northern California encourages the incorporation of a formalized “feedback loop” to assist the industry in developing policies and procedures.
250. Xcel seeks clarification of CIP-002-1, Requirement R1.2.4, which provides that a risk-based assessment methodology consider “systems and facilities critical to system restoration, including blackstart generators and substations in the electrical path of transmission lines used for initial system restoration.” Xcel asks that either the Commission clarify or direct NERC to clarify the meaning of the phrase “used for initial system restoration” and specify whether it refers to facilities on the primary transmission restoration path or on all potential alternative transmission restoration paths.
251. MidAmerican seeks Commission clarification of the appropriateness of an N minus 1 criterion when applying a risk-based assessment methodology to critical assets. It states that NERC's CIP Reliability Standards require all affected entities to withstand the loss of one element without affecting the reliability of the Bulk-Power System. Yet, MidAmerican notes, the Commission's discussion uses the singular term “asset” in the first sentence when describing what a proper risk-based assessment methodology should examine. MidAmerican is concerned that this implies that a risk-based assessment methodology should be based on the loss of a single critical asset (transformer, line or generating
252. Entergy suggests, as an alternative approach to critical asset identification, that the ERO provide a Design-Basis Threat (DBT)—a profile of the type, composition, and capabilities of an adversary—that would assist the industry as a technical baseline against which to establish the proper designs, controls and processes. Entergy claims that a DBT approach would address many of the Commission's concerns regarding the risk-based methodology. For example, a DBT would focus the appropriate emphasis on the potential consequences from an outage of a critical asset. In addition, a DBT would address the Commission's concern that responsible entities will not have enough guidance in developing a risk-based methodology and not know how to identify a “critical asset.” Entergy contends that a DBT approach would provide the industry with more certainty in implementing the CIP Reliability Standards.
253. The Commission believes that the comments affirm that responsible entities need additional guidance on the development of a risk-based assessment methodology to identify critical assets. While we adopt our CIP NOPR proposal, we recognize that the ERO has already initiated a process to develop such guidance. The CIP NOPR proposed to direct that NERC modify CIP-002-1 to incorporate the guidance. However, we are persuaded by commenters that stress the need for flexibility and the need to take account of the individual circumstances of a responsible entity. Thus, we modify our original proposal and in this Final Order leave to the ERO's discretion whether to incorporate such guidance into the CIP Reliability Standard, develop it as a separate guidance document, or some combination of the two. A responsible entity, however, remains responsible to identify the critical assets on its system.
254. Commenters raise a number of topics that they believe should be addressed in the NERC guidance, such as how to assess whether a generator or a blackstart unit is “critical” to Bulk-Power System reliability, the proper quantification of risk and frequency, facilities that are relied on to operate or shut down nuclear generating stations, and the consequences of asset failure and asset misuse by an adversary. We believe these are all appropriate topics to be addressed and direct the ERO to consider these commenter concerns when developing the guidance.
255. The Commission proposed in the CIP NOPR that the ERO and Regional Entities provide reasonable technical support to relatively smaller entities that may have difficulty determining whether a particular asset is critical because, for example, the impact of the facility may be dependent on their connection with a transmission owner or operator. While we believe that there is a need to assist entities that lack a wide-area view, we are mindful of the ERO's concern that it would place an undue burden on it and the Regional Entities. If the ERO believes that it and the Regional Entities do not have sufficient resources to take on this responsibility, it should designate another type of entity with a wide-area view, such as a reliability coordinator, to provide needed assistance. This approach is consistent with our determination (discussed later in this Final Rule) regarding the external review of critical asset lists. Accordingly, we direct either the ERO or its designees to provide reasonable technical support to assist entities in determining whether their assets are critical to the Bulk-Power System.
256. Regarding MidAmerican's comments on use of the N minus 1 criterion when applying a risk-based assessment methodology to the identification of critical assets, we agree with MidAmerican that an N minus 1 criterion is not an appropriate risk-based assessment methodology for identifying critical assets. While the N minus 1 criterion may be appropriate in transmission planning, use of an N minus 1 criterion for the risk-based assessment in CIP-002-1 would result in the nonsensical result that no substations or generating plants need to be protected from cyber events. A cyber attack can strike multiple assets simultaneously, and a cyber attack can cause damage to an asset for such a time period that other asset outages may occur before the damaged asset can be returned to service. Thus, the fact that the system was developed to withstand the loss of any single asset should not be the basis for not protecting that asset. Also, we note that the definition of “critical assets” is focused on the criticality of the asset, not the likelihood of an outage. Based on this reasoning, in response to U.S. Power, we clarify that a generator should not assume that none of its individual generating assets would be regarded “critical” to the Bulk-Power System.
257. With regard to Xcel's request for clarification regarding the meaning of the phrase “used for initial system restoration,” in CIP-002-1, Requirement R1.2.4, we direct the ERO to consider this clarification in its Reliability Standards development process.
258. As to Entergy's suggestion that the ERO provide a DBT profile of potential adversaries, the ERO should consider this issue in the Reliability Standards development process. Likewise, the ERO should consider Northern California's suggestion that the ERO establish a formal “feedback loop” to assist the industry in developing policies and procedures.
259. In the CIP NOPR, the Commission noted that NERC's definition of “cyber assets” includes “data.” The Commission stated that “marketing or other data essential to the proper operation of a critical asset, and possibly the computer systems that produce or process the data, would be considered critical cyber assets” subject to the CIP Reliability Standards.
260. NERC agrees with the Commission that critical cyber assets include “data,” as specified in the definition. NERC then states that the “data” provision only refers to data associated with the reliable operation of the Bulk-Power System, thereby excluding “marketing and other data” as
261. Numerous other commenters contend that the Commission is mistaken to consider “marketing and other data” as a critical cyber asset. For example, NRECA comments that marketing data seldom performs a reliability-related function. Northeast Utilities states that only data pertaining to design or operating specifications necessary for the operation of cyber assets should be included in the definition of cyber assets. PG&E states that the Commission's proposal to include “marketing and other data” is unnecessary because the CIP Reliability Standards already apply to data that are housed and maintained within critical cyber assets and information about critical cyber assets. PG&E asserts that Requirement R4 of CIP-003-1 specifically protects critical cyber asset information, so no additional modifications are needed.
262. Bonneville requests clarification whether the Commission's reference to marketing data and system data are intended to apply to data and systems related to power transactions to be delivered physically about which data are sent to grid operators (e.g., systems that generate E-tags) or all marketing data and systems even if the transactions are settled financially and never get to physical delivery.
263. MidAmerican agrees with the Commission on the need for additional guidance regarding the definition of “data” as critical cyber assets. It recommends deletion of the term “data” from the NERC definition of a “critical cyber asset” and, instead, its inclusion in the information protection standard. MidAmerican contends that access to data is of secondary importance when compared to access to a physical critical cyber asset and, thus, data should be protected as any other critical asset information would be protected.
264. ISO/RTO Council and Ontario Power argue that, although the computers and other devices that contain data may use a routable protocol or may be dial-up accessible, the data itself does not use a routable protocol, nor is it, in its own right, dial-up accessible. Therefore, they submit that Reliability Standard CIP-002-1 does not require that “data” be considered a critical cyber asset. In addition, ISO/RTO Council argues that, since every responsible entity's definitive list of critical cyber assets is developed pursuant to Reliability Standard CIP-002-1, Requirement R3, the “further qualified” reference in Requirement R3 applies to the use of the term “critical cyber asset” wherever the term is used in the CIP Reliability Standards. ISO/RTO Council believes that including data as a critical cyber asset would go beyond the scope and intent of any of the Reliability Standards.
265. ISO-NE and SPP agree with ISO/RTO Council that data by itself does not meet the definition of a critical cyber asset. ISO-NE states that the Commission is further viewing data as a potential critical asset. ISO-NE agrees with this view in concept, but believes that consideration of reliability data is already intrinsic to the process of evaluating assets to determine their criticality. Such reliability data are “real-time data” and are highly transient as they pass through, and are presented by, such supporting critical cyber assets. Given that protection of critical cyber assets is already addressed, the protection of the data component of a cyber asset during its instance of viability as useful reliability data is satisfied. To address a broader focus of data protection would expand the scope of the current CIP Reliability Standards. Such a focus deserves considerable review and discussion. If the Commission continues to have concern regarding data protection from a broader view, ISO-NE recommends this be considered in a future proceeding.
266. SoCalEdison is concerned that applying the CIP Reliability Standards to data that are essential to the proper operation of a critical asset and including computer systems that produce the data might greatly increase the scope of CIP-002-1 and will have a major impact on the industry's ability to meet the standards requirements schedule. SoCalEdison argues that, if the Commission directs these modifications to the standard, they should be handled through the NERC Reliability Standards development process which should consider any impact to the implementation schedule.
267. OGE also is concerned that a definition of “critical cyber assets” that could include computer systems that produce or process such sensitive data may encompass network servers and devices. If network servers and devices are considered critical cyber assets, OGE argues that additional controls will be necessary to isolate and protect these network servers and devices. These additional controls will provide only a minor increase in protection to the bulk electric system.
268. Idaho Power supports the protection of data that defines location, network topography, device descriptions, and similar information; however, Idaho Power cannot support the position that data originating or used in an Energy Management System, for instance, should be treated as “critical” after the fact. In Idaho Power's view, the actual data, upon transfer to data historian servers, fails to meet any definition of “critical.”
269. Juniper recommends that other enterprise databases, such as human resources data, be considered part of the critical assets. Juniper states that its concern applies to any data that can enable a hacker to gain access to cyber assets. Juniper comments that any essential data that could allow an attacker to weaken or defeat any cyber or physical security must be considered a critical cyber asset.
270. As discussed above, commenters that address the subject uniformly oppose the CIP NOPR statement that “marketing or other data essential to the proper operation of a critical asset, and possibly the computer systems that produce or process the data, would be considered critical cyber assets” subject to the CIP Reliability Standards. These commenters contend that marketing data typically does not qualify as a critical cyber asset and the Commission's proposal is beyond the current scope of the CIP Reliability Standards. Moreover, several commenters suggest that some data and support systems may fit the definition of
271. The Commission remains concerned that, while not all marketing data or other data may be considered a critical cyber asset essential to the proper operation of a critical asset, there may be times where it is properly classified as such. For example, if a critical asset is configured such that it cannot operate and support the
272. Based on the range of comments received on this topic, the Commission is convinced that the consideration and designation of various types of data as a critical asset or critical cyber asset pursuant to CIP-002-1 is an area that could benefit from greater clarity and guidance from the ERO. Accordingly, the Commission directs the ERO, in developing the guidance discussed above regarding the identification of critical assets, to consider the designation of various types of data as a critical asset or critical cyber asset. In doing so, the ERO should consider Juniper's comments. Further, the Commission directs the ERO to develop guidance on the steps that would be required to apply the CIP Reliability Standards to such data and to consider whether this also covers the computer systems that produce the data.
273. The Commission also agrees with ISO-NE that experience in the implementation of the CIP Reliability Standards may indicate a need to further address this topic in a future proceeding.
274. In the CIP NOPR, the Commission expressed concern that sufficient rigor is applied in examining whether control systems are determined to be critical assets.
275. NERC and ReliabilityFirst comment that the Commission appears to have incorrectly concluded that “control systems” are critical assets. They explain that, in context, the control center, substations or power plant could be a critical asset. The “control system,” however, would be a critical cyber asset.
276. SPP concurs with the Commission's assertion that consideration of misuse of control systems should be part of the risk-based assessment. Compromise and misuse of a cyber asset often pose greater risks to the reliability of the Bulk-Power System than an induced total failure of the cyber asset. SPP comments that both insider and external threats should be considered as part of the risk-based assessment. In contrast, Entergy opposes the Commission's proposal to require an evaluation of the misuse of control systems.
277. Applied Control Solutions comments that there should be a formally accepted method for identifying critical cyber assets, explaining that existing methods are often reliability-based, not cyber-based, resulting in entities reporting too few assets.
278. ISA99 Team objects to the exclusion of communications links from CIP-002-1 and non-routable protocols from critical cyber assets, arguing that both are key elements of associated control systems, essential to proper operation of the critical cyber assets, and have been shown to be vulnerable—by testing and experience. In contrast, Energy Producers notes that CIP-002-1 as proposed by NERC provides that a critical cyber asset must have either routable protocols or a dial-up connection. Energy Producers states that this is a useful, objective criterion which will assist in the unambiguous identification of such assets and therefore should be retained.
279. The Commission accepts the explanation of the ERO and ReliabilityFirst that a control system could be a critical cyber asset, but not a critical asset.
280. The Commission has two concerns regarding the misuse of facilities, and clarifies those concerns here. First, Requirement R1.2.1 requires responsible entities to consider control centers and backup control centers as potential critical assets. In determining whether those control centers should be critical assets, we believe that responsible entities should examine the impact on reliability if the control centers are unavailable, due for example to power or communications failures, or denial of service attacks. Responsible entities should also examine the impact that misuse of those control centers could have on the electric facilities they control and what the combined impact of those electric facilities could be on the reliability of the Bulk-Power System. The Commission recognizes that, when these matters are taken into account, it is difficult to envision a scenario in which a reliability coordinator, transmission operator or transmission owner control center or backup control center would not properly be identified as a critical asset.
281. Second, the Commission is concerned about the misuse of a control system that controls more than one asset. The assets could be multiple generating units, multiple transmission breakers, or perhaps even multiple substations. All of the controlled assets could be taken out of service simultaneously due to a failure or misuse of the control system. Individually, perhaps none of the controlled assets would be considered as a critical asset. However, with a simultaneous outage due to the single point of control, the controlled assets might affect the reliability or operability of the Bulk-Power System and, therefore, should be considered as critical assets. In that case, the common control system should be considered a critical cyber asset.
282. Therefore, consistent with the discussion above, the Commission directs the ERO, through the Reliability Standards development process, to specifically require the consideration of misuse of control centers and control systems in the determination of critical assets. The clarification of our concern over misuse of control systems addresses Entergy's comment on this issue as well.
283. The Commission concurs with SPP that both insider and external threats should be considered as part of a risk-based assessment.
284. We share Applied Control Solutions' concern that too few assets may be identified as critical cyber assets. However, there is no evidence that will be the case, and there is no formally accepted method for identifying critical cyber assets before us at this time. Therefore, we decline to direct that such a method be incorporated into the CIP Reliability
285. As to the conflicting comments of ISA99 Team and Energy Producers, Requirement R2 of CIP-002-1 provides that a critical cyber asset must either have routable protocols or dial-up access. Energy Producers argues that Requirement R2 should be retained, while ISA99 Team argues that devices that use non-routable protocols should also be considered as possible critical cyber assets. We do not find sufficient justification to remove this provision at this time. However, we direct the ERO to consider the comment from ISA99 Team. We also do not find sufficient justification to order the inclusion of communication links in CIP-002-1 at this time.
286. In the CIP NOPR, at P 115, the Commission expressed concern that all critical assets be identified. To further this goal, the Commission interpreted the phrase, “[t]he risk-based assessment shall consider the following assets * * *” in Requirement R1.2 to mean that a responsible entity must be able to show why, based on the risk-based methodology, specific assets were chosen or not chosen. The Commission proposed to direct that the ERO modify Requirement R1.2 to make this obligation explicit.
287. Most commenters addressing the subject oppose the Commission's proposal.
288. To clarify, the Commission did not propose to direct that the ERO develop a requirement for responsible entities to document why each specific asset was identified or not identified as “critical.” Rather, the Commission's intent was that a responsible entity must be able to explain such determinations, for example upon inquiry by an auditor, to confirm compliance with the Reliability Standard. Nonetheless, we are persuaded by the commenters that the documentation of a responsible entity's risk-based assessment methodology pursuant to Requirement R1.1 and the results of its annual application of the methodology pursuant to Requirement R2 should suffice to explain a responsible entity's asset determinations. Accordingly, the Commission will not direct the ERO to develop a modification to address this concern. However, if experience shows that responsible entities are failing to consider in their assessments specific types of assets that the Commission, ERO or others believe should be included in an assessment and therefore not in compliance with the Reliability Standard, there may be a need to revisit this matter in the future.
289. Requirement R4 of CIP-002-1 requires that a senior manager “or delegate(s)” must approve annually the list of critical assets and critical cyber assets. In the CIP NOPR, the Commission proposed to direct that the ERO develop a modification to CIP-002-1 to include a requirement that a senior manager annually review and approve the risk-based assessment methodology.
290. Alliant, APPA/LPPC, Congressional Representatives, EEI, KCPL and Luminant agree with the Commission that it is important that there is internal oversight of the responsible entity's activities. EEI adds that, although senior manager review of the risk-based assessment methodology is implicit in the current CIP Reliability Standards, such a provision should be made explicit through the Reliability Standards development process to establish the “clear authority” recommended by the Blackout Report. Luminant adds that such a provision would provide a degree of certainty for a responsible entity's senior management to approve the risk-based assessment methodology the responsible entity adopts. KCPL also supports NERC's development of an “explicit” requirement that senior management review and approve a responsible entity's risk-based assessment methodology.
291. METC-ITC believe that the Commission can further strengthen the CIP Reliability Standards by raising the apparent level of responsibility of CIP compliance to a corporate officer level, replacing “senior manager” with “officer” in such instances throughout the CIP Reliability Standards. In contrast, Northern Indiana claims that senior management might not be the most knowledgeable about cyber security issues and urges the Commission to continue to allow a responsible entity to delegate this review to knowledgeable personnel.
292. ISO/RTO Council argues that the requirement for internal oversight already is an implicit requirement under the CIP Reliability Standards. In ISO/RTO Council's view, it is abundantly clear that the senior manager is fully accountable for both the thoroughness of the methodology used to establish the critical asset list as well as the completeness of the list itself.
293. Bonneville seeks clarification whether the intent of the Commission's proposal is to make senior managers personally accountable for a responsible entity's violation of the CIP Reliability Standards so that the senior manager is subject to civil penalties. Bonneville comments that, if this is the intended purpose or result, then the extent of such personal liability must be made clear so that affected senior managers can take necessary precautions, such as obtaining additional insurance coverage. NRECA raises similar concerns regarding a senior manager's penalty liability.
294. The Commission adopts its CIP NOPR proposal and directs the ERO to develop, pursuant to its Reliability Standards development process, a modification to CIP-002-1 to explicitly require that a senior manager annually review and approve the risk-based assessment methodology. This determination is consistent with the Blackout Report's recommendation to establish clear authority and ownership for physical and cyber security. Further, regardless of whether the current Requirements implicitly require senior manager review of the assessment methodology, we believe the matter is too important to rely on inference. Accordingly, the Commission directs the ERO to develop a modification to CIP-002-1 to explicitly require that a senior manager annually review and approve the risk-based assessment methodology.
295. With regard to Northern Indiana's concerns, we are not directing a revision to the current language of Requirement R4 which provides for “the senior manager or delegate(s)'s approval” of the list of critical assets and list of critical cyber assets. As we understand the provision, the senior manager still retains ultimate responsibility for the determinations of his or her delegate(s). Otherwise, senior management could avoid responsibility by ‘delegating downward.’
296. With regard to METC-ITC's comment, the ERO should consider in its Reliability Standards development process the suggestion that the CIP Reliability Standards require oversight by a corporate officer (or the equivalent, since some entities do not have corporate officers) rather than by a “senior manager.”
297. In response to comments by Bonneville and NRECA, the Commission clarifies that we do not intend that an individual employee of a user, owner or operator of the Bulk-Power System will be subject to a penalty pursuant to section 215 of the FPA because a responsible entity violates a CIP Reliability Standard. This matter is addressed in more detail in our discussion of CIP-003-1.
298. The CIP NOPR emphasized that the responsibility for identifying critical assets should be placed on the individual responsible entity as the asset owner or operator, and not shifted to Regional Entities or another organization.
299. Several commenters, including ISO/RTO Council, EEI, FirstEnergy, National Grid and Northeast Utilities, agree with the Commission that responsibility for identifying critical assets should not be placed on the Regional Entities or any organization other than the categories of applicable entities currently identified in CIP-002-1. They believe that this responsibility rightfully rests with the asset owner or operator, and the Regional Entities would be overburdened by such a task.
300. In contrast, AMP Ohio advocates the revision of CIP-002-1 to make Regional Entities responsible for the identification of critical assets because they have an area-wide view of the grid—as opposed to small generation owners, generation operators and load serving entities that have a limited view of the Bulk-Power System. AMP Ohio also argues that making small generation owners, generation operators and load serving entities responsible for asset identification would place a burden on these small entities that they are ill-positioned to bear. AMP Ohio explains that it is not proposing that responsible entities abdicate responsibility but, rather, suggests that the Regional Entity take the first step to identify critical assets. The asset owner or operator, as a responsible entity, must then ensure that the critical cyber assets associated with the critical asset are identified and protected. AMP Ohio suggests that, if responsible entities remain responsible for identifying assets, the CIP Reliability Standard should include a safe harbor provision for good faith compliance, even if subsequent events demonstrate that critical assets may have been overlooked.
301. SPP and ReliabilityFirst suggest a modification to CIP-002-1 that would allow an entity to rely on the assessment of another entity with interest in the matter. For example, a merchant generator may through a legitimate assessment determine that its plant is not critical whereas the balancing authority's assessment indicates that it is. They suggest that in such a situation the merchant generator would accept the risk-based assessment of the balancing authority as a substitute for performing its own assessment with limited data.
302. While some commenters agree with the Commission that there is a need for external review and approval of a responsible entity's critical asset list, others believe that such a requirement is unnecessary.
303. Arkansas Electric, Juniper, MidAmerican, National Grid, Ontario IESO, and U.S. Power agree with the Commission that a process for regional review of an entity's critical asset list by either the ERO or the Regional Entity would be beneficial. According to Arkansas Electric, this would provide an entity with the opportunity for a review of its critical asset list prior to a full CIP audit. Arkansas Electric is concerned that, without such a review, entities could be subject to sanctions based on a critical asset list later deemed deficient by an auditor. MidAmerican finds that a regional perspective could add consistency to the critical asset determination. U.S. Power maintains that, in organized markets where a generator does not typically possess a “regional perspective” to objectively determine the criticality of an individual asset, external review could be helpful in assuring that a regionally consistent approach is followed; and that such determinations are based on the most relevant, available information.
304. FirstEnergy agrees with the Commission that a formal or systematic approach to external oversight of the identification of critical assets would
305. National Grid comments that it would support the development of an appropriate mechanism for Regional Entities to collection documentation of each responsible entity's assessment methodology and list of critical assets. However, National Grid would not support a requirement for Regional Entity pre-approval of the methodology or list because the Regional Entity lacks the necessary expertise and resources. Similarly, Northern Indiana supports external review, particularly where lists of cyber security assets will not be shared and responsible entities must determine their asset lists based on mutual distrust. However, Northern Indiana opposes requiring approval of a responsible entity's list of critical assets by the entity conducting the external review. It also opposes granting Regional Entities or reliability coordinators the ability to supplement a critical asset list. This concern would be removed, however, if the regional entity approved the risk-based assessment methodology, rather than the list of critical assets.
306. In contrast, NERC and others oppose modifying CIP-002-1 to require external review and approval of critical asset lists.
307. Alliant objects to external approval of a critical asset list because the ERO auditing regime provides a “wide-area view” and external approval would require an appeals process that would delay implementation without accruing reasonable benefits. Duke claims that the ERO's guidance document should result in adequate consistency in the development of critical asset lists and suggests that any external review should be optional. Southern contends that a responsible entity is generally in the best position to determine which assets are critical to the Bulk-Power System and, if needed, industry experience can be shared through existing forums and through the voluntary exchange of information. Puget Sound and others propose that industry forums could be used to promote a wide-area view in developing critical asset lists. Idaho Power insists that regional concerns should be addressed before an entity develops its critical asset list.
308. Many of the commenters that oppose an external review and approval process believe that the Commission's objectives can be accomplished through a Regional Entity audit process.
309. Among the commenters that support the need for external oversight, some prefer that an organization other than a Regional Entity be made responsible for external oversight. For example, ISO/RTO Council believes that the reliability coordinator is in the best position to provide such oversight because it has a wide-area view that is focused on grid operation. ISO/RTO Council believes that Regional Entities need to remain independent to enforce the CIP Reliability Standards and should not be involved in CIP Reliability Standard implementation; and likewise, considers that transmission planners are not sufficiently focused on the operational aspects of the grid where cyber security is most critical. Further, ISO/RTO Council suggests that reliability coordinator oversight be limited to a review of the methodologies used to identify critical assets, since reliability coordinators have no special expertise in identifying critical
310. By contrast, Ontario IESO, Reliant, ReliabilityFirst and SPP advocate that reliability coordinators, not Regional Entities, should provide oversight of critical asset identification. Ontario IESO and SPP believe that the reliability coordinators are most suited for this task because they are directly involved in the daily activities of ensuring Bulk-Power System reliability. They comment that the reliability coordinators currently perform a wide-area function that includes studying power system dynamics and interrelationship of assets as well as coordination among neighboring systems. Reliant urges that the Commission require the reliability coordinator to play a major role in the external review of critical asset lists because it possesses a broad array of operating and system data.
311. Ontario IESO comments that, because Regional Entities perform a critical CIP Reliability Standards development and compliance role, Regional Entity approval of an entity's critical asset list creates a conflict of interest in the situation where a Regional Entity is required to investigate and enforce non-compliance of a CIP Reliability Standard. The Regional Entity may have approved the critical asset list and thus may be reluctant to subsequently find a deficiency in the list discovered during the course of a compliance investigation. Ontario IESO also respectfully suggests that Regional Entities lack the technical expertise and intimate knowledge of their members' power system equipment and behaviors to provide the necessary oversight in the determination of critical asset lists.
312. Ontario IESO suggests that, in the event an asset owner and the reliability coordinator disagree as to whether an asset should be listed as critical, the latter should prevail. APPA/LPPC ask that the Commission direct NERC to develop written procedures for a responsible entity to challenge an external, third-party decision to alter a responsible entity's list of critical assets. APPA/LPPC argue that, regardless of the reviewer, an appellate process akin to the process described in Rule 410 of the NERC Rules of Procedure, providing for appeals to the Commission, is needed. EEI and Alliant also believe that an appeal process would be needed if regional oversight occurs.
313. Many of the commenters that oppose an external review and approval process are concerned that an external review process will create new issues regarding the protection of sensitive information that inevitably is included
314. EEI and Manitoba Hydro express concern that off-site, third party review of a critical asset list may conflict with an entity's responsibility to protect information such as a critical asset list in CIP-003-1, Requirement R4.1. EEI urges that the Final Rule clarify that this information should only be divulged in on-the-premise audits.
315. CEA is also concerned that the Commission's proposal to include a mechanism for the external review and approval of critical assets lists would involve the submission of sensitive information. CEA and Manitoba Hydro maintain that some Canadian utilities are prohibited from sharing security information with U.S. authorities. In addition, some utilities regard sharing sensitive security information externally or with a foreign entity as a security risk. Currently, sensitive information is kept on site and shared with external audit teams during visits and the information remains on-site following the audit. The Commission's proposed changes would require sensitive material to be shared on a regular basis and stored externally and perhaps in a foreign jurisdiction. Given the impact on Canadian utilities from such changes to the CIP Reliability Standards, CEA requests that the Commission exercise caution with respect to this issue.
316. Xcel asks, in a situation where an entity's risk-based assessment identifies a critical asset owned by another entity, how should this information properly be communicated while maintaining confidentiality? Xcel recommends that the Regional Entities develop confidentiality protocols to address such situations.
317. SDG&E requests clarification that information associated with the CIP Reliability Standards will be treated with confidentiality. Tampa Electric and SoCal Edison also urge that steps be taken to protect confidentiality if information is released to accomplish external reviews. SoCal Edison is concerned with the risks associated with storing critical information in a common place.
318. Bonneville agrees with the Commission's goal of providing a mechanism for the external review and approval of responsible entities' critical asset lists based on a regional perspective; however, it is concerned that the Commission's proposal could result in FOIA concerns for Bonneville and other federal entities. Under FOIA, the release of information to an external party generally waives any privileges against disclosure with respect to subsequent requests to the federal agency for that same information. Bonneville is concerned that submission of critical asset information to the Regional Entity, particularly disclosure of the vulnerability-related rationales for including and documentation of why it chose to exclude particular facilities from inclusion on the critical asset list, may act as such a waiver. In addition, Bonneville notes that external reviewers of critical federal security information may need to obtain federal security clearances before federal entities can allow such review.
319. The Commission affirms its CIP NOPR determination that responsibility for identifying critical assets should not be shifted to the Regional Entity or another organization instead of the applicable responsible entities identified in the current CIP Reliability Standards. As we stated in the CIP NOPR,
320. We will not allow a “safe harbor” for good faith compliance as requested by AMP Ohio. We do not believe that blanket waivers from an enforcement action are appropriate in this context and have previously denied other requests for safe harbors from enforcement.
321. SPP and ReliabilityFirst suggest modifying CIP-002-1 to allow an entity to rely upon the assessment of another entity with interest in the matter. We believe that this is a worthwhile suggestion for the ERO to pursue and the ERO should consider this proposal in the Reliability Standards development process. We note that, even without such a provision, an entity such as a small generator operator is not foreclosed from consulting with a balancing authority or other appropriate entity with a wide-area view of the transmission system.
322. The Commission adopts its CIP NOPR proposal to direct that the ERO develop through its Reliability Standards development process a mechanism for external review and approval of critical asset lists. The Commission finds that an external review of critical assets by an appropriate organization is needed to assure that such lists are considered from a wide-area view (i.e., from a regional perspective) and to identify trends in critical asset identification. Further, while we recognize that individual circumstances may likely vary, an external review will provide an appropriate level of consistency.
323. The Commission disagrees with the suggestion of Luminant and others that external review should be voluntary. The identification of critical assets pursuant to CIP-002-1 is crucial to cyber security protection because this determination controls whether a responsible entity must comply with the remaining CIP requirements in CIP-003-1 through CIP-009-1. External review will help ensure that responsible entities have an accurate and complete list of critical assets, which will in turn allow them to be appropriately protected to further the security of the nation's Bulk-Power System. Allowing external review as a voluntary measure is not adequate to ensure that responsible entities are prepared to address cyber vulnerabilities and cyber threats. Based on the same reasoning, we reject the suggestion of Northern Indiana and others that the external review should only address the assessment methodology, and not critical asset lists.
324. The Commission also disagrees with commenters who insist that the external review can be performed pursuant to the ERO's and Regional Entity's current compliance and enforcement programs, and the audit process in particular. While the Commission decided earlier in the Final Rule to rely on the ERO and regional audit processes to examine exceptions
325. The Commission agrees with Ontario IESO that in a dispute between a responsible entity and the external reviewer over whether to identify an additional asset as critical, the external reviewer should prevail. (However, an external reviewer's role should be limited to determining if additional assets should be added, and should not include making recommendations to remove an asset from the list of critical assets.) We recognize, however, that there may be a legitimate reason for a responsible entity to dispute such a determination, possibly through an appeal. We leave it to the ERO to determine the need for such an appeal mechanism and, if appropriate, the development of appropriate procedures (or reliance on appeal procedures currently provided in the NERC Rules of Procedure). While the ERO may determine that an appeals process is a necessary aspect of this program, we do not believe that the burden of such appeals outweighs the benefits of the external review of critical asset lists.
326. The Commission in the CIP NOPR proposed that the Regional Entities be responsible for the external review of critical asset lists, and also expressed a willingness to consider a review process that allows for the participation of other organizations such as reliability coordinators and transmission planners. As indicated above, a number of commenters question whether the Regional Entities have the expertise or resources to conduct the reviews. Rather, there was considerable support for reliability coordinators conducting the external review because of their technical expertise, their wide-area view and their role of coordinating among neighboring systems.
327. The Commission believes that the Regional Entities must have a role in the external review to assure that there is sufficient accountability in the process. Further, a Regional Entity role is necessary because the Regional Entities and ERO are ultimately responsible for ensuring compliance with Reliability Standards. For example, if the ERO determines that an appeals process is needed, this process cannot rest with an active owner or operator of the Bulk-Power System such as a reliability coordinator. Moreover, the ERO and the Commission have oversight authority of the Regional Entities' programs and procedures pursuant to section 215 of the FPA.
328. Beyond the direction that the Regional Entities maintain a role in the external review process to assure that there is sufficient accountability, we leave to the ERO to determine whether the Regional Entities have, or can timely develop, the resources to conduct the external reviews.
329. Based on the above discussion, the Commission directs the ERO, using its Reliability Standards development process, to develop a process of external review and approval of critical asset lists based on a regional perspective.
330. The Commission agrees with commenters that critical asset lists contain sensitive information that needs to be protected from public dissemination. The Commission, however, does not believe that this concern is a persuasive rationale for not having an external review mechanism. Rather, adequate safeguards need to be developed to assure that the information contained in critical asset lists are not released during the external review process. While Requirement R4 of CIP-003-1 obligates a responsible entity to “implement and document a program to identify, classify, and protect information associated with Critical Cyber Assets,” the Commission does not view this as inherently conflicting with an external review process that has adequate safeguards to prevent the release of sensitive information.
331. In developing an appropriate external review mechanism, the ERO should include features for the controlled delivery of critical assets to the entity performing the external review. Likewise, the ERO should identify minimum safeguards that the external reviewer must deploy to protect sensitive information from disclosure. We agree with commenters' concern that the external reviewer should not become a “central repository” for critical asset lists, and this information should be returned to the responsible entity once the review is complete. The ERO should develop any other safeguards that it believes to be appropriate to protect the disclosure of sensitive information during the external review process.
332. CEA and Manitoba Hydro comment that some Canadian utilities are prohibited from sharing security information with U.S. authorities. They also note that some Canadian utilities regard sharing sensitive security information externally or with a foreign entity as a security risk. In response, the Commission's Final Rule only addresses the obligations of users, owners and operators of the Bulk-Power System in the United States (excluding Hawaii and Alaska). Accordingly, the Commission's directives regarding the development of an external review mechanism applies only to entities subject to the Commission's jurisdiction pursuant to section 215 of the FPA. Whether a similar review process is appropriate or lawful in other jurisdictions is beyond the scope of this Final Rule.
333. Bonneville comments that external review could result in FOIA concerns for Bonneville and other federal entities. It also cautions that external reviewers of critical federal security information may need federal security clearances before being allowed access to classified information. In response to Bonneville, we agree that a governmental entity subject to FOIA requirements should not be required to share sensitive information about
334. Further, if a governmental entity has classified material regarding its critical assets, this information may not be disclosed except in accordance with controlling laws and regulations. The ERO's external review process must explicitly recognize this limitation.
335. In the CIP NOPR, the Commission noted that, while CIP-002-1 pertains to the identification of assets critical to Bulk-Power System reliability, broader interdependency issues with other infrastructures cannot be ignored.
336. APPA/LPPC and other commenters support the Commission's proposed determination that the scope of reliability regulation is properly limited to assets critical to the Bulk-Power System, and does not extend to the management of assets that may be important to the operation of other (even if presumably critical) non-electric assets. MidAmerican comments that the expansion of CIP Reliability Standards beyond Bulk-Power System reliability should be approached with caution and only after the compliance effort is complete for the current CIP Reliability Standards. Luminant agrees with the Commission that issues pertaining to system interdependency are complicated and more appropriately addressed in a separate proceeding after the Commission completes its action approving the current NERC CIP Reliability Standards.
337. By contrast, Applied Control Solutions suggests that interdependencies should be included in risk-based assessments, as they can have direct (e.g., electronic connections between electric entities and major customers) and indirect impacts (e.g., loss of major fuel sources) on Bulk-Power System reliability.
338. Likewise, the Congressional Representatives find fault in the CIP Reliability Standards for failing to address interdependencies with other critical infrastructures. The Congressional Representatives state that the Bulk-Power System is an enormous, interconnected network that is both redundant and resilient, making the sole focus on “reliability” and “operability” of the grid as a whole inappropriate. They explain that every critical infrastructure in the country is dependent on the Bulk-Power System, including chemical plants, banks, refineries and military installations. Thus, according to the Congressional Representatives, “focusing on assets relative to the functioning of the grid misses the importance of each individual asset to the functions of our society.”
339. Related, the Congressional Representatives are critical of NERC's definition of critical assets as “facilities, systems, and equipment that would affect the reliability and operability” of the Bulk-Power System. The Congressional Representatives explain that this definition fails to understand the importance of individual elements of the Bulk-Power System that are essential to the delivery of power to the nation's critical infrastructure. They state that generation units serving individual communities, individual substations, telecommunication equipment and distribution assets are critical to the safety and security of the U.S., yet are excluded under CIP-002-1.
340. The Commission is sensitive to the concerns raised by the Congressional Representatives regarding the severe impact that a cyber attack on assets not critical to the Bulk-Power System could still have on the public. The Commission, however, believes that its authority under section 215 of the FPA does not extend to other infrastructure. Section 215 of the FPA authorizes the Commission to approve Reliability Standards that “provide for the reliable operation of the bulk-power system,” which the statute defines as the facilities and control systems necessary for operation of an interconnected electric energy transmission network and the electric energy needed to maintain transmission system reliability. In addition, section 215(a)(1) specifically excludes from the definition of Bulk-Power System “facilities used in the local distribution of electric energy.” Moreover, given the complexities surrounding this issue and the aggressive timeline that will be necessary merely to meet the more modest task of developing and implementing cyber security standards capable of protecting the reliability of the Bulk-Power System, we will follow the approach that we described in the CIP NOPR of approving CIP Reliability Standards designed to safeguard the reliability of the Bulk-Power System.
341. Although the Commission will not direct modifications to the scope of critical assets to be identified under CIP-002-1, for the reasons discussed above, the Commission agrees with commenters regarding the importance of considering interdependencies with other critical infrastructures. The Commission believes that to meaningfully address interdependencies with other critical infrastructures, it is important to coordinate with the stakeholders of these other infrastructures as well as with other government agencies and organizations. Thus, we affirm our CIP NOPR approach that “[w]hile broader interdependency issues cannot be ignored, the Commission intends to revisit this matter through future proceedings and with other agencies. This work will help inform the electric sector and this Commission about the need for future Reliability Standards, especially when the interdependent infrastructures affect generating capabilities, such as through fuel transportation.”
342. Reliability Standard CIP-003-1 seeks to ensure that each responsible entity has minimum security management controls in place to protect the critical cyber assets identified pursuant to CIP-002-1. To achieve this goal, a responsible entity must develop a cyber security policy that represents management's commitment and ability
343. CIP-003-1, in addition, requires a responsible entity to implement an information protection program to identify, classify, and protect sensitive information concerning critical cyber assets, as well as an access control program to designate who may have access to such information. Finally, a responsible entity must establish a “change control and configuration management” program to oversee changes made to the hardware or software of critical cyber assets.
344. The Commission approves Reliability Standard CIP-003-1 as mandatory and enforceable. In addition, we direct the ERO to develop modifications to this Reliability Standard through its standards development process and to take other actions. These actions pertain to (1) the adequacy of policy guidance; (2) discretion to grant exceptions; (3) leadership; (4) access authorization; (5) change control and configuration management; and (6) interconnected networks.
345. Requirement R1 of Reliability Standard CIP-003-1 directs a responsible entity to “document and implement a cyber security policy that represents management's commitment and ability to secure its critical cyber assets.” The only guidance that is given with regard to the nature and scope of the cyber security policy is that it should address “the Requirements in CIP-002-1 through CIP-009-1, including the provisions for emergency situations.”
346. The Commission proposed in the NOPR that the ERO modify CIP-003-1 to provide additional guidance for the topics and processes that the required cyber security policy should address to ensure that a responsible entity reasonably protects its critical cyber assets.
347. NERC and other commenters contend that the Commission should not direct the ERO to modify CIP-003-1 to provide additional guidance for the topics and processes that the required cyber security policy should address.
348. ISO/RTO Council opposes the Commission proposal and expresses concern that if a responsible entity's security policies go beyond the specific Requirements of the Reliability Standards, it could be penalized for failure to implement the policies fully. ISO/RTO Council also objects to reporting any steps that exceed what the CIP Reliability Standards require to any third party. It argues that it would be wasteful to require development of one set of plans, policies and standards to meet what is explicitly required by the Reliability Standards and another that is applicable to other assets such as market systems. ISO/RTO Council requests that the Commission clarify that monitoring for non-compliance will pertain to the specific Requirement of the Reliability Standards, not requirements expressed in corporate policies relevant to security.
349. In contrast, SoCal Edison believes that it is appropriate to include guidance in CIP-003-1 on important systems that have not yet been addressed such as data and communications networks, but that guidance on topics such as power supplies, heating, and other equipment is too detailed for a corporate level policy. APPA/LPPC agrees that security policies will address issues that are not currently reflected in the CIP Reliability Standards but that are important for control system security. Further, APPA/LPPC state that the nature and scope of a responsible entity's cyber security management policy generally should be left to the entity's discretion.
350. ReliabilityFirst and SPP comment that an entity's overall organizational security policies should address protection of supporting infrastructure and appropriately define a defense in depth posture. However, they are concerned that, by including such infrastructure in the scope of the CIP Reliability Standards, an audit could determine that the devices supporting the network throughout the entity should be considered either critical cyber assets or electronic security perimeter access points and thus become subject to all of the Requirements of the CIP Reliability Standards. Their concern is the possibility of increasing the scope of the electronic security perimeter to include the entity's entire communications network and all assets connected thereto.
351. Other commenters raise concerns whether specific issues should be addressed in this guidance. Idaho Power disagrees with the Commission's proposal to address the protection of support systems (
352. Tampa Electric notes that cyber assets associated with communications networks and data communication links between distinct electric security perimeters are exempt under the CIP Reliability Standards. It urges that this exemption be maintained and that further consideration of the exemption's merit should be addressed only in the Reliability Standards development process. Likewise, National Grid and MidAmerican oppose expanding the CIP Reliability Standards to cover communications and data networks beyond those directly involved in the security of control systems.
353. APPA/LPPC agree that it is reasonable for responsible entities to be responsible for the communications systems they own and operate. However, they cannot be expected to oversee the operations of commercial communication carriers. APPA/LPPC state the Commission should recognize that it has no authority to compel commercial communication carriers to comply with the CIP Reliability Standards and that responsible entities cannot compel them to comply.
354. ReliabilityFirst and SPP are concerned that environmental systems would become subject, at a minimum, to the requirements of CIP-006-1 (Physical Security). Environmental systems are often not fully enclosed within a physical security perimeter as defined by the Reliability Standard and it is impractical in some instances to do so. ReliabilityFirst states that, besides expanding the scope of the Reliability Standards to encompass issues that either have no bearing on Bulk-Power System reliability, or are specifically excluded from the CIP Reliability Standards, the Commission's proposal improperly deals with “how” a responsible entity is to address a Requirement.
355. The Commission believes that responsible entities would benefit from additional guidance regarding the topics and processes to address in the cyber security policy required pursuant to CIP-003-1. While commenters support the need for guidance, many are concerned about providing such guidance through a modification of the Reliability Standard. We are persuaded by these commenters. Accordingly, the Commission directs the ERO to provide additional guidance for the topics and processes that the required cyber security policy should address. However, we will not dictate the form of such guidance. For example, the ERO could develop a guidance document or white paper that would be referenced in the Reliability Standard. On the other hand, if it is determined in the course of the Reliability Standards development process that specific guidance is important enough to be incorporated directly into a Requirement, this option is not foreclosed. The entities remain responsible, however, to comply with the cyber security policy pursuant to CIP-003-1.
356. In response to ISO/RTO Council, Ontario Power and other commenters, the Commission's intent in the CIP NOPR—as well as the Final Rule—is not to expand the scope of the CIP Reliability Standards. Requirement R1 of CIP-003-1 requires a responsible entity to document and implement a cyber security policy “that represents management's commitment and ability to secure its Critical Cyber Assets.” The Requirement then states that the policy, “at a minimum,” must address the Requirements in CIP-002-1 through CIP-009-1. The Commission believes that there are other topics, besides those addressed in the Requirements of the CIP Reliability Standards, which are relevant to securing critical cyber assets. The Commission identified examples of such topics in the CIP NOPR. Thus, the Commission, in directing the ERO to develop guidance on additional topics relevant to securing critical cyber assets, is not expanding the scope of the CIP Reliability Standards.
357. Nor do we believe, as suggested by Idaho Power, that the proposed topics for guidance are better addressed by revisions to other Reliability Standards. Again, the guidance is in the context of securing critical cyber assets and is best addressed in the CIP Reliability Standards or a supporting guidance document.
358. In response to SoCal Edison, we disagree that guidance on topics such as power supplies, heating, and other equipment is too detailed for a corporate level policy. These topics are potentially relevant to securing critical cyber assets and, therefore, appropriate topics for guidance.
359. ISO/RTO Council, Ontario Power and other commenters raise concerns regarding potential civil penalty liability if a responsible entity addresses the additional guidance topics in its cyber security policy. The Commission does not believe that the inclusion of additional topics in the cyber security policy will increase a responsible entity's penalty liability. We provide our views regarding the enforcement of cyber security policies below in addressing exceptions to such policies. In particular, we state there that our concern is that a good policy exists and that it is implemented through the exercise of sound reasoning. Consistent with the discussion in the following section, we do not believe that an entity's decision to not follow its cyber security policy in a particular situation should trigger a penalty, as long as no Reliability Standard Requirement (other than Requirement R1 in CIP-003-1) is violated as a result. We do require that the reasoning be documented to ensure that the responsible entity is indeed implementing the security policy as required by Requirement R1 of CIP-003-1.
360. We agree with APPA/LPPC that responsible entities cannot be expected to oversee the operations of commercial communications carriers. However, this is an example of precisely why more guidance would be useful. Since responsible entities cannot oversee commercial communications carriers, it is important that they consider what they can do to guard against potential threats from that quarter.
361. Requirement R3 of CIP-003-1 provides that a responsible entity must document as an exception each instance where it cannot conform to its security policy developed pursuant to Requirement R1. Exceptions need senior manager approval. The documentation must include “an explanation as to why the exception is necessary and any compensating measures, or a statement accepting risk.” An exception to the cyber security policy must be documented within 30 days of senior management approval. An authorized exception must be reviewed and approved annually to ensure that the exception is still required and valid.
362. The Commission expressed concern in the CIP NOPR that Requirement R2 allows a responsible entity too much latitude in excusing itself from compliance with its cyber security policy.
363. Further, the Commission distinguished between situations where a responsible entity excepts itself from its cyber security policy and where it excepts itself from specific Requirements of the CIP Reliability Standards based on technical feasibility and stated that exceptions from a policy provision do not also excuse compliance with a Requirement. In that regard, the Commission proposed that the ERO develop modifications to clarify that the exceptions mentioned in Requirements R2.3 and R3 of CIP-003-1 do not except responsible entities from the Requirements of the CIP Reliability Standards.
364. While NERC and ReliabilityFirst do not comment specifically on Regional Entity review of exceptions to a responsible entity's cyber security policy, their general comment is that the Commission should rely on NERC's existing oversight structure is applicable here.
365. EEI and other commenters oppose requiring responsible entities to submit documentation of exceptions to the cyber security policy to Regional Entities. EEI disagrees with the Commission's assertion that CIP-003-1
366. Entergy disagrees that responsible entities should be required to submit documentation of exceptions periodically to their Regional Entity. Entergy believes that a proper security policy will track what the Reliability Standards require. The Commission, the ERO, and Regional Entities should not be concerned with policy exceptions but rather only with whether the Requirements of the CIP Reliability Standards are being met. Entergy also argues that requiring documentation of exceptions could cause internal policies to be written less rigorously to avoid the burden of excessive documentation.
367. CEA and Manitoba Hydro are concerned that periodic submission of documents on cyber security policy exceptions to Regional Entities may allow the release of highly sensitive information. Manitoba Hydro states that such documentation would contain details about existing critical cyber assets and their security weaknesses that would threaten both security and reliability if it were released inadvertently into the wrong hands. SoCal Edison suggests that it is more appropriate for responsible entities to house all justifications for policy exceptions internally and have them reviewed during an audit. Bonneville is concerned that the practice could be deemed a waiver of FOIA protections. Bonneville also is concerned that external reviewers may be required first to obtain required federal security clearances before accessing the information.
368. MidAmerican believes that the reporting of exceptions will indicate a weak spot in a responsible entity's cyber security policy and a secure method of handling these exceptions would need to be established.
369. Several commenters address the Commission's proposal to clarify that the exceptions mentioned in Requirements R2.3 and R3 of CIP-003-1 do not except responsible entities from the Requirements of the CIP Reliability Standards. EEI opposes the Commission's proposal for the same reasons described above. MidAmerican comments that it has not interpreted Requirements R2.3 and R3 as the ability to avoid compliance.
370. Related, SPP states that a responsible entity cannot exempt itself from a Requirement of a CIP Reliability Standard. Once a policy is in place to comply with these Requirements, the only recourse in cases of technical infeasibility or other valid reason is to document an exception to the security policy. SPP maintains that the Commission's proposal for reporting and approval of technical feasibility exceptions would, if adopted, extend to exceptions to the required security policy if the exception would make the responsible entity incapable of complying fully with a Requirement of the CIP Reliability Standards.
371. Northern Indiana requests clarification of the information that would be required to justify an exception and suggests that it match the level of information required in self-certifications. It suggests that a responsible entity would benefit from consultation when attempting to justify an exception and that monetary penalties should be waived during this time as well as within the timeframe of any remediation plan. Northern Indiana also contends that security policy exceptions which do not affect compliance with the Reliability Standards need not be documented. Some policies may be stricter than the Reliability Standards, and responsible entities should not be required to submit documentation of exceptions that are consistent with the Reliability Standards Requirements.
372. The Commission continues to believe that it is important that there be ERO and Regional Entity oversight of exceptions from required security policies, however, the Commission agrees with commenters such as EEI and PG&E that this oversight is best accomplished through the existing Regional Entity oversight and audit process.
373. Requirement R1 of CIP-003-1 requires the development and implementation of a security policy. Requirement R3 provides that a responsible entity must document exceptions to its policy with documentation and senior management approval. The Commission is concerned that, if exceptions mount, there would come a point where the exceptions rather than the rule prevail. In such a situation, it is questionable whether the responsible entity is actually implementing a security policy. We therefore believe that the Regional Entities should perform an oversight role in providing accountability of a responsible entity that excepts itself from compliance with the provisions of its cyber security policy. Further, we believe that such oversight would impose a limited additional burden on a responsible entity because Requirement R3 currently requires documentation of exceptions.
374. That being said, the Commission agrees with EEI and others that Regional Entity review of exceptions to a responsible entity's cyber security policy is best accomplished pursuant to the existing Regional Entity audit process where all the relevant facts and circumstances can be considered. Further, review of exceptions to a cyber security policy in the audit process should effectively address commenter concerns regarding disclosure of sensitive information by keeping that data on site.
375. As we discuss elsewhere in the Final Rule, we agree with Bonneville regarding the need to preserve a governmental entity's FOIA protections and address security clearance concerns. The ERO should address these concerns through consultation with relevant governmental entities.
376. Further, the Commission adopts its CIP NOPR proposal and directs the ERO to clarify that the exceptions mentioned in Requirements R2.3 and R3 of CIP-003-1 do not except responsible entities from the Requirements of the CIP Reliability Standards. In response to EEI, we believe that this clarification is needed because, for example, it is important that a responsible entity understand that exceptions that
377. The Requirement to develop and implement a security policy differs from many other Requirements in that it is a means to the end of implementing those Requirements. Our concern that exceptions be documented and justified is primarily a concern that there be reasoned decision-making, consistency, and subsequent effectiveness in implementing the policy. We thus disagree with Northern Indiana that security policy exceptions which do not affect compliance with the Reliability Standards need not be documented. Further, in response to Entergy, as stated elsewhere in this Final Rule, our concern is that a good policy exists and that it is implemented through the exercise of sound reasoning. We do not believe that an entity's decision to not follow its cyber security policy in a particular situation should trigger a penalty, as long as no Reliability Standard Requirement (other than Requirement R1 in CIP-003-1) is violated as a result. We do require that the reasoning be documented to ensure that the responsible entity is indeed implementing the security policy as required by Requirement R1 of CIP-003-1.
378. In response to Northern Indiana's request for clarification of the information that would be required to justify an exception, we leave it to the ERO to provide guidance on the level of information that it considers appropriate, consistent with our discussion above.
379. Requirement R2 of CIP-003-1 requires that a senior manager be assigned overall responsibility for implementation of the CIP Reliability Standards. In the CIP NOPR, the Commission interpreted this Requirement to require the designation of a single manager who has direct and comprehensive responsibility and accountability for implementation and ongoing compliance with the CIP Reliability Standards.
380. Bonneville states that the Commission should clarify whether its intent is to make the senior manager personally accountable for violations of the CIP Reliability Standards, i.e., subject to civil penalties for violations, so that necessary action can be taken to protect the manager, such as acquiring additional personal insurance coverage. Similarly, NRECA asks the Commission to confirm that the senior manager responsible for CIP Reliability Standards compliance is not, by virtue of his position, subject to civil penalties pursuant to section 215 of FPA.
381. The Commission adopts its CIP NOPR interpretation that Requirement R2 of CIP-003-1 requires the designation of a single manager who has direct and comprehensive responsibility and accountability for implementation and ongoing compliance with the CIP Reliability Standards. The Commission's intent is to ensure that there is a clear line of authority and that cyber security functions are given the prominence they deserve. The Commission agrees with commenters that the senior manager, by virtue of his or her position, is not a user, owner or operator of the Bulk-Power System that is personally subject to civil penalties pursuant to section 215 of FPA.
382. Requirement R5 of CIP-003-1 directs the responsible entity to implement a program for managing access to protected critical cyber asset information and requires, among other things, that the list of personnel responsible for authorizing access to protected information be verified at least annually.
383. The Commission explained in the CIP NOPR that CIP-007-1, Requirement R5 (access implementation), CIP-004-1, Requirement R4 (access revocation), and CIP-003-1, Requirement R5 (access review and approval) each contain provisions on access to information, and it took the position that these various provisions are not interlinked as clearly as they should be. The Commission noted that Recommendation 44 of the Blackout Report stresses the need to prevent inappropriate disclosure of information. Thus, the CIP NOPR proposed to direct that the ERO modify Reliability Standards CIP-003-1, CIP-004-1, and/or CIP-007-1, to ensure that when access to protected information is revoked, it is done so promptly.
384. CPUC agrees with the Commission's proposal on clarifying that a revocation of access to protected information should be accomplished promptly, but it maintains that that the term “promptly” is too subjective. It would be more appropriate to specify a definite time interval for revoking access. FirstEnergy agrees with the Commission's proposal and states that in all cases of access authorization under the CIP Reliability Standards, responsible entities should revoke an employee's access to critical cyber assets within 24 hours in cases of termination for cause and within seven days for other personnel no longer needing such access. MidAmerican takes a similar position.
385. Northern Indiana states that while a responsible entity may remove an employee's or vendor's access to its critical cyber assets and systems, it cannot eliminate all possible access to information. A responsible entity cannot enter the employee's home to remove or destroy information that the employee, particularly the vendor's employee, may have maintained in his home because in the course of his employment he wanted ready reference to such information. A responsible entity may make a reasonable request that information be returned, but immediate return may not occur.
386. The Commission adopts its CIP NOPR proposal and directs the ERO to develop modifications to Reliability Standards CIP-003-1, CIP-004-1, and/or CIP-007-1, to ensure and make clear that, when access to protected information is revoked, it is done so promptly. In general, the Commission agrees with commenters and believes that access to protected information should cease as soon as possible but not later than 24 hours from the time of termination for cause.
387. In response to Northern Indiana, while we acknowledge that responsible entities are not authorized to enter private homes, we believe that an appropriate cyber security policy will ensure that such information is present in an employee's home only for legitimate reasons specified in the policy and should require the return of all information upon request.
388. Requirement R6 of CIP-003-1 requires a responsible entity to establish a process of “change control and configuration management” for adding,
389. The Commission noted in the CIP NOPR that Requirement R6 does not address accidental consequences or malicious actions by individuals where commercial vendors test and certify that the electronic security patches they provide will not adversely affect other electronic systems already in place.
390. Entergy, ISO/RTO Council, Northern Indiana and PG&E oppose the Commission's proposed modifications to Requirement R6 of CIP-003-1. Entergy argues that the Commission's concern will be addressed by CIP-007-1 when implemented by information security professionals and changes to CIP-003-1 are unnecessary and burdensome. Entergy and BPA also believe that the NIST Security Risk Management Framework offers further comprehensive controls. Northern Indiana points out that assets and systems targeted by the proposal include software as well as hardware.
391. MidAmerican believes that Requirement R6 is sufficient as written and clearly outlines the process of review, testing and approval, and is adequate for monitoring of change control and configuration management. Idaho Power is concerned about the current availability of technology to assist in detecting accidental and malicious modifications. It asks whether the Commission is concerned with unauthorized changes, unintended changes or both. Idaho Power opposes additional changes and states that it can reduce the risk of unauthorized changes significantly, but it cannot eliminate them entirely. Idaho Power believes that there will be adequate protection against unintended changes where there are appropriate test plans, trained and qualified personnel, and a regimented change management process.
392. ISO/RTO Council states that it does not understand what the Commission meant by “detection and monitoring controls” and suggests that it consider the phrase “verification that unintended changes have not been made.” ISO/RTO Council objects to testing the functionality of changes made to live production systems. It agrees that verification of manually initiated changes is appropriate, and responsible entities should also be required to monitor and determine whether unintended changes have been made to devices in the production environment and to investigate and remediate any unintended changes. According to ISO/RTO Council, it is not always possible to confirm definitively or safely that applying a tested and approved change on a production device has had the intended effect, especially where the modification is rarely triggered or where testing could adversely affect reliability. ISO/RTO Council prefers a requirement to verify that changes have been made on the intended devices, to monitor for unintended or unplanned changes, and to investigate and remediate any exceptions that are discovered.
393. Further, ISO/RTO Council states some changes are intentionally initiated automatically using pre-approved means, such as automated virus signature updates. These changes can be unpredictable and can occur multiple times per day. ISO/RTO Council agrees these changes need to be verified, but states it is impractical and unnecessary to verify each change as it happens and suggests periodic verification that the necessary updates, or their cumulative equivalent, have been effectuated.
394. PG&E argues that technical problems could cause downtime of critical assets if this requirement is imposed. Any requirements for detection and monitoring controls for unintended changes must allow for controls that do not require considerable downtime for the critical cyber assets.
395. Puget Sound argues that the CIP Reliability Standards should expressly recognize that change control and configuration management processes for critical cyber assets cannot ensure 100 percent integrity for those assets when making changes. The CIP Reliability Standards also should recognize that test environments can mimic portions of the production environment but cannot capture all of the actual interactions among critical cyber assets.
396. ReliabilityFirst and SPP state that changes should be properly tested prior to implementation, although it may not always be feasible to test a change in an offline environment. They believe that a strict interpretation of the Commission proposal would be impossible to implement, as it would require a comprehensive regression test, including failure testing, to be performed on the entire environment. Even that might not detect an unintended consequence of the change and could conceivably result in an expectation to report an issue of non-compliance. Regression testing is appropriately reserved for significant changes, such as version upgrades or new applications, but not all changes. They state that appropriate mitigation measures exist for reducing the risk of unintended consequences resulting from changes.
397. Based upon the comments received the Commission is altering its position on how best to address the apparent deficiencies of Requirement R6 in CIP-003-1. The Commission directs the ERO to develop modifications to Requirement R6 of CIP-003-1 to provide an express acknowledgment of the need for the change control and configuration management process to consider accidental consequences and malicious actions along with intentional changes. The Commission believes that these considerations are significant aspects of change control and configuration management that deserve express acknowledgement in the Reliability Standard. While we agree with Entergy that the NIST Security Risk Management Framework offers valuable guidance on how to deal with these matters, our concern here is that the potential problems alluded to be explicitly acknowledged. Our proposal does not speak to how these problems should be addressed. We do not believe that the changes will have burdensome consequences, but we also note that addressing any unnecessary burdens can be dealt with in the Reliability Standards development process.
398. We agree with ISO/RTO Council that the phrase “verification that unintended changes have not been made” captures the core issue. Our concern is that some form of verification is performed to detect when unauthorized changes have been made and to identify those changes, as well as ensuring that the proper alerts are issued.
399. Many of the comments address practical issues involved in addressing accidental consequences and malicious actions, and we recognize that such issues exist. We, thus, agree with Puget Sound that change control and
400. In response to ReliablityFirst and SPP, we understand that comprehensive regression testing is not necessary for every change regardless of how insignificant. We also agree with ISO/RTO Council that it can be impractical and unnecessary to verify every intentional automatic change as it occurs. We believe that our revised directive to the ERO addresses these concerns.
401. The Commission proposed in the CIP NOPR to direct the ERO to modify Reliability Standard CIP-003-1 to provide direction on the issues and concerns that a mutual distrust posture must address to protect a control system from the “outside world.”
402. FirstEnergy agrees with the intent of the Commission's proposal that there be more direction on what constitutes a mutual distrust posture, but it argues that the need for uniform processes should be balanced against the need for flexibility in individual cases. FirstEnergy argues that each entity may have a unique architecture that requires a unique protection scheme. In addition, a common security method could cause a vulnerability of its own, in that one successful cyber attack could compromise all security systems if there are similarities across all systems.
403. ISO-NE agrees that the mutual distrust principle is a useful consideration when determining when to protect cyber assets and in designing a secure system architecture, but it disagrees that it should be used as a measurable requirement. ISO-NE thus asks the Commission to omit any direction to the ERO to address the concept of mutual distrust.
404. Northern Indiana comments that the Commission's proposal on mutual distrust is unnecessary because the issue is addressed in Reliability Standards CIP-005-1 and CIP-007-1. It argues that if the Commission's proposal on mutual distrust were applied in unqualified terms, it would have to sever the Midwest ISO's communication link to the Northern Indiana control system. Northern Indiana states that it trusts the Midwest ISO in its role as the reliability coordinator over the Northern Indiana electric system and thus argues that the Commission should exempt reliability coordinators. If the Commission does not exempt reliability coordinators, Northern Indiana respectfully requests that the Commission clarify and refine the definition of the term mutual distrust.
405. Entergy argues that the Commission needs to direct the ERO to define the term mutual distrust in CIP-003-1 to foreclose ambiguities in application and enforcement. Entergy notes that NIST has many documents in its SP800 Series that provide excellent treatment of the issues and variables involved in the concept of mutual distrust and that complement the NIST Security Risk Management Framework. The Commission could direct the ERO to consider this guidance. Entergy argues that the broad wording of the Commission's proposal extends beyond the scope of the Reliability Standards. It also argues that the Commission's proposal would direct the ERO to specify what the end result must be rather than permitting the Reliability Standards process to establish the optimum solution.
406. MidAmerican submits that the terms mutual distrust and outside world require clarification to facilitate compliance. MidAmerican recommends that the Commission ensure that the guidelines to be developed have no impact on either performance or reliability. EMS/SCADA systems are tuned for and certified by their vendor at specific communication rates. The introduction of delays due to additional security layers to communications and data exchange may impact reliability.
407. The Commission proposed in the CIP NOPR that the ERO provide direction, i.e., guidance, regarding the issues and concerns that a mutual distrust posture must address in order to protect a responsible entity's control system from the outside world. The Commission noted that a mutual distrust posture requires each responsible entity that has identified critical cyber assets to protect itself and not trust any communication crossing an electronic security perimeter, regardless of where that communication originates.
408. The Commission agrees with FirstEnergy on the importance of flexibility in developing a mutual distrust posture, but does not see a conflict between the need for flexibility and what it is proposing, which is simply more guidance. More guidance will allow responsible entities to implement measures adapted to their specific situations more consistently and effectively. Additional guidance need not be included in a specific Requirement, but could be in the form of examples. We will leave it to the Reliability Standards development process and the ERO to decide whether some or all of the guidance can be contained in separate guidance documents referenced in the Reliability Standard. In response to Entergy, the Commission is not directing that the ERO establish a specific end result. Our concern is simply that responsible entities have guidance on how to achieve an appropriate result in individual cases, which can vary on a case-by-case basis. We disagree that providing useful guidance affects the scope of the Reliability Standards.
409. We agree with Entergy that NIST provides much guidance, but we disagree that it is necessary to define the term mutual distrust. Our proposal is that there be guidance on certain issues and concerns, and we therefore do not believe that a formal definition advances that goal. In response to MidAmerican, we believe that clarification of the terms mutual distrust and outside world, as well as ensuring that any guidelines developed do not harm performance or reliability, are matters that the ERO should consider in the Reliability Standards development process.
410. We disagree with Northern Indiana that Reliability Standards CIP-005-1 and CIP-007-1 address the matters of concern to us. Northern Indiana does not explain how these Reliability Standards provide guidance of the type we have described. We also
411. We disagree with ISO-NE that guidance on mutual distrust is unnecessary because responsible entities either are compliant or they are not, mutual distrust not withstanding. We do not see how responsible entities can fully understand the compliance issues they face without some understanding of how mutual distrust is applied in a modern security environment. Mutual distrust helps explain where an entity's responsibilities begin and end and what assumptions it can make about factors outside its control when it performs its risk-based assessment.
412. The Commission therefore directs the ERO to provide guidance, regarding the issues and concerns that a mutual distrust posture must address in order to protect a responsible entity's control system from the outside world.
413. Standard CIP-004-1 requires that personnel having authorized cyber access or unescorted physical access to critical cyber assets must have an appropriate level of personnel risk assessment, training and security awareness. Responsible entities must develop and implement a security awareness program that addresses concerns related to cyber security; a cyber security training program for affected personnel that addresses policies, access controls, procedures for the proper use of critical cyber assets, physical and electronic access to critical cyber assets, proper handling of asset information, and recovery methods after a cyber security incident; and a personnel risk assessment program for all personnel having access to critical cyber assets.
414. As discussed further below, the Commission approves Standard CIP-004-1 as mandatory and enforceable. In addition, we direct the ERO to develop modifications to this CIP Reliability Standard. The Commission also requires the ERO to clarify and provide guidance on other matters. The required modifications are discussed below in the following topic areas of concern regarding CIP-004-1: (1) Training; (2) personnel risk assessments; (3) cyber and physical access; and (4) jointly owned facilities.
415. The requirements for ongoing awareness reinforcement in sound security practices specified in Requirement R1 and for training specified in Requirement R2 apply to all personnel, contractors, and service vendors who have authorized cyber access or unescorted physical access to critical cyber assets. Requirement R2.1 allows such personnel to have access to critical cyber assets for up to 90 days prior to receiving any cyber security training.
416. In the CIP NOPR,
417. In addition, the Commission proposed to direct the ERO to modify CIP-004-1 to clarify that the cyber security training programs required by Requirement R2 are intended to encompass training on the networking hardware and software and other issues of electronic interconnectivity supporting the operation and control of the critical cyber assets. The CIP NOPR stated that CIP-004-1 should clearly state that cyber security training concerning a critical cyber asset should encompass the electronic environment in which the asset is situated and the attendant vulnerabilities. To clarify that point, we proposed that the ERO consider adding a provision similar to that in Requirement R1.4 of CIP-005-1, which specifically subjects any non-critical cyber asset within a defined electronic security perimeter to the CIP Reliability Standard.
418. Further, the Commission proposed to direct that the ERO increase the guidance in the CIP Reliability Standard as to the scope and quality of training, including examples of areas where the inclusion of guidance can be considered, as follows: control of electronic devices (such as laptop computers); the appropriate audiences for the training; delivery methods; and updates of training materials. The CIP NOPR stated that the awareness and training programs, addressed separately by Requirements R1 and R2, complement each other and work in tandem. The Commission also stated its expectation that the ERO consider relevant aspects of certain NIST Special Publications, as well as other relevant models, to improve CIP-004-1 and prevent a lowest common denominator result.
419. Entergy recommends that the Commission modify its direction to the ERO regarding access to critical cyber assets for newly-hired personnel to provide access to critical cyber assets for newly-hired personnel if they are accompanied by qualified escorts. Entergy insists that individuals without training should be allowed to be escorted by a trained individual to access a critical cyber asset and, if similar required training has been received by an unescorted individual at another industry facility, that training should be allowed to be credited at the current facility. SDG&E recommends that new employees be allowed escorted access to critical cyber assets, even in non-emergency situations, since training is not always coincident with a hiring date.
420. Entergy disagrees with the proposal to direct the ERO to require responsible entities to identify core training elements. On the other hand, FirstEnergy and SoCal Edison agree with the Commission's proposal that NERC should require the development of core training elements. They state that additional guidance in this area would be helpful preparation for responsible entities to operate in emergency and other contingency
421. Entergy contends that specific discussion of the many forms of training needed is beyond the current scope of the CIP Reliability Standards. Entergy argues that, if specificity is needed, the Commission should refer to materials issued by other federal agencies, including the Defense Information Systems Agency. Mr. Brown argues that the level of detail the Commission is proposing to be added to the training portion of the CIP Reliability Standards would be more appropriately and efficiently developed through some process other than that of Reliability Standards development process.
422. MidAmerican believes that CIP-004-1, Requirement R2 is adequate as proposed and that specific job-related training requirements are more properly managed by the entity performing or contracting the work. MidAmerican submits that the entity performing the work is best suited to determine the scope and delivery method of job-specific training. MidAmerican believes additional clarification of acceptable awareness and training programs is necessary for compliance purposes, should the Commission's call for increased guidance be adopted.
423. In response to the Commission's proposal that training encompass network and interconnectivity aspects, many commenters suggest that training should be tailored to match up with the trainee's duties, experience, or “need to know.” FirstEnergy suggests that CIP-004-1 should include a provision that would direct a responsible entity to establish access categories based on security roles because access categories based on job responsibilities would ensure that the level or frequency of exposure to critical cyber assets will be considered. For example, a systems analyst would need access to certain critical cyber assets on a frequent basis and at a level that allows file manipulation, while a system user would need access to the data output of the systems during working hours and not necessarily file manipulation access. Those with access to critical cyber assets should have training specific to the critical cyber asset and those without such access should have general awareness training.
424. Likewise, National Grid argues that, while a general understanding of networking hardware and software and interconnectivity is important, the focus of the training should be geared toward understanding cyber security policies and each trainee's role in response and recovery plans. National Grid believes that not every employee requires IT training and that training should match an employee's required skill set.
425. FirstEnergy agrees that CIP-004-1 should address training regarding access to the cyber assets themselves and the networking hardware and software linking them, but it also asks the Commission to clarify that only those personnel that have access to both the critical cyber assets and the networking hardware and software should have training on both. FirstEnergy argues that it would be overly burdensome and serve no purpose to do otherwise and, conversely, it serves no purpose to train personnel on the networking hardware and software security methods, if those personnel have access only to the critical cyber asset itself. Training personnel on security measures of equipment for which they have no access can create a potential weakness in the security measures for such equipment.
426. ISO-NE argues that requirements for training relating to networking hardware and software and other issues of electronic interconnectivity supporting the operation and control of the critical cyber assets are a business management decision and should be omitted from the Final Rule. ISO-NE argues that the decision to determine the level of skill training necessary for an individual, based on that employee's functional task requirements and coordinated career goals, is a business decision beyond the scope of security training for access controls, monitoring, and incident response.
427. Similarly, Northern Indiana contends that CIP-004-1 should not specify who should be trained, what the training should include, or how frequently training should occur. Northern Indiana argues that the responsible entity must be given flexibility to differentiate between those aspects of networked systems potentially affecting critical control systems and those that should be included in critical cyber asset training. Northern Indiana argues that the focus should be on the applications, policies and procedures that relate to the critical control systems and other critical cyber assets.
428. ISO/RTO Council and ISO-NE argue that training that addresses vulnerabilities is not appropriate for all individuals with access to critical cyber assets and, therefore, they disagree with the statement in the CIP NOPR that “CIP-004-1 should leave no doubt that cyber security training concerning a critical cyber asset should encompass the electronic environment in which the asset is situated and the attendant vulnerabilities.” Information about vulnerabilities associated with critical cyber assets and/or their security perimeters is highly sensitive. Such information should be known only to those with direct responsibility to administer the secure operation of the critical cyber assets and their security perimeters.
429. ReliabilityFirst is concerned that the ERO not lose sight of the fact that Requirement R2.2 requires specific training “appropriate to personnel roles and responsibilities” as it develops the additional guidance proposed by the Commission. ReliabilityFirst argues that it is inappropriate, for example, to train an operator in the dispatch operations center on firewalls and networking devices. Training for personnel with electronic or unescorted physical access to systems within the electronic security perimeter should be appropriate to the trainee's scope of access. The goal of the training is not to make operational personnel into network specialists, but to train them on the policies and procedures implemented by the responsible entity to protect their critical cyber assets.
430. In response to the Commission's question regarding what, if any, modifications to CIP-004-1 should be made to address the concern that security trainers be adequately trained themselves, SoCal Edison believes that the Commission should require the ERO to have a program to have qualified trainers in order to determine the adequacy of training. To ensure quality and consistency, this implies that all trainers would have to be qualified by the ERO prior to training. Any vendor training tools (
431. The Commission adopts the CIP NOPR's proposal and directs the ERO to develop a modification to CIP-004-1 that would require affected personnel to receive required training before obtaining access to critical cyber assets (rather than within 90 days of access
432. The Commission notes that commenters did not provide specific reasons why employees should be granted access prior to training, but focused on the nature and scope of our proposed exceptions. Entergy and SDG&E recommend that newly-hired employees be allowed access to critical cyber assets if they are accompanied by qualified escorts. We note that a qualified escort would have to possess enough expertise regarding the critical cyber asset to ensure that the actions of the newly-hired employee or vendor did not harm the integrity of the critical cyber asset or the reliability of the Bulk-Power System. However, if the escort is sufficiently qualified, we believe such escorted access could be permitted before a newly-hired employee is trained.
433. Based on the concerns of commenters, the Commission modifies its CIP NOPR proposal that the ERO identify core training elements to ensure that essential training elements will not go unheeded in emergencies and in other compelling situations. While the Commission continues to believe that the identification of core training elements is useful, this issue would benefit from further vetting within the Reliability Standards development process. Thus, we direct the ERO to consider, in developing modifications to CIP-004-1, whether identification of core training elements would be beneficial and, if so, develop an appropriate modification to the Reliability Standard. If the Reliability Standard development process determines not to identify core requirements, the ERO should provide an explanation of this decision. In reply to commenters, we clarify that by using the term core training our concern is for a responsible entity to pre-plan what information and training is necessary for personnel temporarily called in to help in an emergency—not that the actual scope of such training needs to be articulated in the Reliability Standard and applicable to all responsible entities in all circumstances. It is important that responsible entities have plans for introducing the personnel called in to assist in such situations. We expect that core training would be different for different responsible entities.
434. The Commission adopts the CIP NOPR's proposal to direct the ERO to modify Requirement R2 of CIP-004-1 to clarify that cyber security training programs are intended to encompass training on the networking hardware and software and other issues of electronic interconnectivity supporting the operation and control of critical cyber assets. CIP-004-1 should leave no doubt that cyber security training concerning a critical cyber asset should encompass the electronic environment in which the asset is situated and the attendant vulnerabilities. We note that, according to Requirement R1.4 of CIP-005-1, all cyber assets within an electronic security perimeter are to be protected, not just the critical cyber assets. In reply to commenters, we clarify that our proposal discussion on this topic was not intended to suggest that personnel have training that is not appropriate for an employee's duties, functions, experience, or access level. We agree with commenters that information concerning vulnerabilities should be revealed on a need to know basis and not universally. However, any employee with access to an area where his or her actions, or carelessness, could put critical assets at risk, should receive the necessary training to assure that the employee understands how his or her actions or inactions could, even inadvertently, affect cyber security.
435. Consistent with the CIP NOPR, the Commission directs the ERO to determine what, if any, modifications to CIP-004-1 should be made to assure that security trainers are adequately trained themselves. Commenters provided minimal input on this proposal and, consistent with the CIP NOPR, we believe that whether a modification is appropriate to address this issue is better determined in the first instance through the ERO's Reliability Standards development process. The ERO should consider the comments of SoCal Edison with regard to what role and steps should be taken by the ERO to ensure quality and consistency of trainers.
436. Requirement R3 of CIP-004-1 requires each responsible entity to have a documented personnel risk assessment program. It also requires that a personnel risk assessment, including a criminal background check, be conducted within 30 days after a person receives cyber access or unescorted physical access to critical cyber assets. The wording of Requirement R3 would allow access to critical cyber assets while an investigation is still underway, and even before an investigation has started.
437. In the CIP NOPR, the Commission stated that allowing applicable personnel, including vendors, to access critical cyber assets prior to the completion of their personnel risk assessment increases the vulnerability of, and risk to, these assets.
438. California Commission and MidAmerican support the Commission's proposal to require that a personnel risk assessment be performed before access is granted except in emergency situations for the reasons articulated in the CIP NOPR. California Commission stresses that the personal risk assessment must be conducted before a person obtains access to critical cyber assets, because, if access is granted before a person clears a risk assessment, Requirement R3 is rendered useless. California Commission states that the point is to keep unwanted persons away from critical cyber assets, not to grant them access for a brief period of time and then bar them from access if they do not pass the risk assessment.
439. ReliabilityFirst and SPP do not believe that the CIP Reliability
440. FirstEnergy agrees with the Commission that newly hired employees or vendors with no previous relationship to the responsible entity should not have access to critical equipment while undergoing the personnel risk assessment. The 30-day window may be appropriate for employees and vendors with which the responsible entity has had a working relationship, such as employees transferring to another position or contractors that are returning from a reassignment. In contrast, SoCal Edison maintains that 30 days is not adequate time to update personnel risk assessments during initial implementation on all current personnel that would require an updated personnel risk assessment. It believes that the 30 days would be adequate if such a timeframe begins when personnel risk assessment certification paperwork is provided for each individual.
441. APPA/LPPC note that they do not object to the requirement in CIP-004-1 R3.1 that “[t]he responsible entity shall ensure that each assessment conducted include, at least, [a] seven-year criminal check” on employees with access to critical cyber assets. However, they seek clarification that responsible entities have discretion in reviewing the results of criminal background checks to determine, on a case-by-case basis, whether any crime identified in the background check would disqualify an individual from obtaining access to critical cyber assets.
442. SDG&E comments that Requirement R3 may require refinement on various issues regarding the personnel risk assessment requirements, including whether state and local law should be pre-empted to permit industry-wide protocols for periodic background and criminal checks on existing employees. SDG&E asks the Commission to clarify that an entity may comply with Requirement R3 by using its existing pre-employment background check procedures for current employees, at seven year intervals, provided that such procedures encompass the required social security verification and criminal background checks. SDG&E argues that, otherwise, applicable state and local laws could prohibit an entity from conducting such periodic checks.
443. The Commission adopts with modifications the proposal to direct the ERO to modify Requirement R3 of CIP-004-1 to provide that newly-hired personnel and vendors should not have access to critical cyber assets prior to the satisfactory completion of a personnel risk assessment, except in specified circumstances such as an emergency. We also direct the ERO to identify the parameters of such exceptional circumstances through the Reliability Standards development process. FirstEnergy and California Commission agree with the Commission's proposals.
444. ReliabilityFirst and SPP believe that it would be appropriate to handle emergency access via a short-term exception to the security policy. We note that such access would not be only an exception to the security policy, but an exception to a CIP Reliability Standard Requirement. Therefore, such exceptions would have to comply with the conditions of a technical feasibility exception that we have specified elsewhere in this Final Rule. The Commission believes that a workable solution is for the Reliability Standards development process to identify emergency circumstances that would warrant allowing access to critical cyber assets. However, if a responsible entity experienced a situation outside of those circumstances that it believed warranted access to critical cyber assets, the responsible entity could treat the situation as a technical feasibility exception and follow the conditions set out by the Commission. With this approach, we believe that in most cases it will be unnecessary to go through the administrative burden of a technical feasibility exception.
445. SoCal Edison expresses concern that the 30 days allowed in CIP-004-1 for completion of the personnel risk assessment may not be enough time to process all existing employees with access. We note that there is no reason why such assessments cannot be completed well before responsible entities are to be auditably compliant with this provision. The ERO should consider SoCal Edison's issue in the Reliability Standards development process.
446. APPA/LPPC seek clarification regarding discretion in reviewing results of personnel risk assessments and in coming to conclusions regarding the subject employees. SDG&E seeks refinements on various issues, including an industry-wide protocol for periodic background and criminal checks, and the use of pre-employment background check procedures for current employees. The ERO should consider these issues when developing modifications to CIP-004-1 pursuant to the Reliability Standards development process.
447. Requirement R4 of CIP-004-1 directs the responsible entity to maintain list(s) of personnel with authorized cyber or authorized unescorted physical access to critical cyber assets. The lists do not serve to deny personnel access from critical cyber assets prior to completion of a personnel risk assessment, although Requirement R4.2 requires that both cyber and physical access to critical cyber assets be revoked within 24 hours for personnel terminated for cause and within seven calendar days for personnel who no longer require such access.
448. The Commission stated in the CIP NOPR that timely system updates to access rights are important because access to critical cyber assets by employees, contractors, or vendors represents a gap in security when such access is no longer needed. We proposed to direct the ERO to develop modifications to CIP-004-1 to require immediate revocation of access privileges when an employee, contractor, or vendor no longer performs a function that requires authorized physical or electronic access to a critical cyber asset for any reason (including disciplinary action, transfer, retirement or termination). Further, we proposed to direct the ERO to modify Requirement R4 to make clear that unescorted physical access should be denied to individuals that are not identified on the authorization list.
449. Numerous commenters responded to the CIP NOPR proposal to require immediate revocation of access to critical cyber assets when an employee, contractor or vendor no longer performs a function that required authorized physical or electronic access to a critical cyber asset for any reason. California Commission agrees with the requirements of CIP-004-1, and states that access controls should be updated upon termination or transfer of
450. MidAmerican supports the proposal, but believes that the timelines provided in Requirement R4.2 are clearly defined and appropriate for the risk associated with removal of access. ReliabilityFirst and SPP agree with the Commission that access should be revoked as quickly as possible upon termination or reassignment, but believe the use of the term “immediate” is subjective and could lead to conflicting interpretations. According to ReliabilityFirst, one entity might interpret the requirement as allowing a reasonable amount of time, perhaps an hour, to revoke access once the termination or reassignment has occurred and notifications made, while another entity might interpret it as needing to terminate access prior to the moment of termination or reassignment, perhaps coincident with the employee being notified of his or her termination.
451. SoCal Edison and Entergy believe that it will be difficult to comply with the immediate revocation of access requirement. For example, SoCal Edison states that meeting the proposed change would be dependent upon direct communication from a manager initiating the termination actions, and SoCal Edison believes it is appropriate to allow 24 hours to revoke access privileges. FirstEnergy similarly argues that an organization will not be aware in advance of personnel that are transferred in short order to address an immediate need or personnel that are dismissed or fired on the spot for misconduct. Entergy asserts that the systems and equipment currently in use across the industry simply cannot operate in the type of networked computing environment necessary to revoke all access immediately. For example, a responsible entity may have a magnetic strip physical access control at a substation perimeter, but if the controller is not networked back to a central access control system, meeting the immediacy requirement would not be possible. The industry will need time and adequate grounds to justify modernization of capabilities for rate relief in order to implement such a proposal.
452. First Energy and Idaho Power suggest that the Commission should soften its position on immediate revocation and propose that the Commission require access to critical cyber assets to be revoked as soon as practicable. They suggest allowing either 24 hours or one business day for revocations. Ontario Power notes that some activities can be performed quickly, but others will take time.
453. ReliabilityFirst argues that, from a risk perspective, it is more time-critical to terminate access when an employee is involuntarily terminated or reassigned due to disciplinary action. ReliabilityFirst argues that an employee who voluntarily terminates or changes positions normally does so on good terms with the employer. In addition, both ReliabilityFirst and SPP maintain that, while an entity should be cognizant of planned terminations and reassignments within the company, the entity has no such insight into a vendor or contractor. The entity must rely upon a timely notification from the vendor or contractor, especially when the services are provided remotely as opposed to on-site. In addition, ReliabilityFirst reasons that primary access needs to be terminated as quickly as possible, with secondary access not as time-critical. Primary access would include the physical access, VPN access, and domain account, and terminating that access will effectively quarantine the terminated employee while remaining access is disabled. ReliabilityFirst and SPP recommend that, in lieu of the term “immediate,” a reasonable and measurable time frame already exists and has been defined within the CIP Reliability Standard itself.
454. Similarly, ISO-NE argues that personnel transfers can at times require a protracted, transitional process, where there is good business reason for the individual to retain access privileges after the formal transfer date. Most often this would be where continued back-up support is appropriate while the individual's replacement is being identified, or a personal risk assessment is conducted, and/or is trained and becomes familiar with new job responsibilities.
455. ISO-NE and Northern Indiana oppose requiring revocation of access when an employee is facing disciplinary action. ISO-NE argues that not all disciplinary action should arbitrarily warrant revocation of access privileges. Northern Indiana argues that, notwithstanding the disciplinary action, such an employee might still be responsible for performing tasks that require access. Northern Indiana argues that Requirement R4.2 should be left intact and the timeline for revocation should remain 24 hours for personnel terminated for cause and within seven calendar days for personnel who no longer require access to critical control systems and other critical cyber assets. ISO-NE requests management discretionary power in determining when revocation is warranted.
456. Various commenters raise concerns about the timelines associated with the Commission's proposal to deny unescorted physical access to individuals not identified on the authorization list. For example, Northern Indiana is concerned that absolute compliance with this requirement would be very difficult to achieve and record within the time specified.
457. EEI objects to the immediate revocation of access privileges proposal if the Commission is proposing to require responsible entities to perform immediate updating of their authorization lists. EEI argues that these changes are not needed, because, at the time any individual is terminated for any reason, the manager collects items such as badges, keys, tokens used for electronic entrance and other methods of access, thus denying the individual access to facilities where critical cyber assets are kept. Access control systems are updated using an efficient overnight batch process. EEI asserts that converting to immediate updates for all situations (including low-risk situations such as individuals transferring or retiring) would require significant expense with minimal improvement in security.
458. Duke and others
459. PG&E argues that CIP-004-1 already provides sufficient controls and need not be revised. PG&E argues that CIP-004-1 ensures that individuals who are terminated or who no longer require such access lose their access in a timely manner, but argues that there should be no requirement for immediate updating of authorization lists. In this regard, PG&E argues that, although having the means to identify individuals with valid access rights is important, if the individual has been disabled from access to relevant systems and physical areas, a slight delay in updating the list would not significantly compromise security and thus there is no need to require the impractical task of
460. The Commission adopts the CIP NOPR proposal to direct the ERO to develop modifications to CIP-004-1 to require immediate revocation of access privileges when an employee, contractor or vendor no longer performs a function that requires physical or electronic access to a critical cyber asset for any reason (including disciplinary action, transfer, retirement, or termination).
461. As a general matter, the Commission believes that revoking access when an employee no longer needs it, either because of a change in job or the end of employment, must be immediate. As noted in the CIP NOPR, most organizations will know in advance the timing of personnel actions and can arrange ahead of time for access revocation to be concurrent with any disciplinary action, transfer, retirement or termination. Revocation of access is usually a matter of assuring that a particular employee's credentials no longer permit physical or electronic access. We understand that outlying elements may require some brief lag before denial of access is effective, in which case, the circumstances justifying such lag must be documented for audit purposes.
462. FirstEnergy comments that the term “immediate” should be clarified and be interpreted as “as soon as possible” but not later than 24 hours to take care of on-the-spot dismissals. Others also comment about various circumstances where advance or coincident preparations for revocation to access cannot be made. We continue to believe that most dismissals can be anticipated in advance and believe that revocation should be immediate upon the employee's notification of any personnel action requiring revocation of access. However, the ERO may define what circumstances justify an exception that is other than immediate and determine what is the fastest revocation possible.
463. We acknowledge that not all disciplinary actions warrant revocation of access privileges. In addition, certain personnel transfers can require a protracted transitional process that warrants retention of access privileges after the formal transfer date. There may be operational reasons that justify retention of access privileges after an employee transfers, but the default procedure should be to cancel access privileges at transfer and to document any exceptions to that policy for audit purposes.
464. We also adopt our proposal to direct the ERO to modify Requirement R4 to make clear that unescorted physical access should be denied to individuals that are not identified on the authorization list, with clarification. Our concern, in calling for this adjustment, is that the current language in the CIP Reliability Standard does not describe the purpose of the required list of personnel with authorized access; rather, it merely states that such a list must be made, reviewed, and updated. Similar to our expectations expressed earlier regarding implementation of required plans and policies, we believe that the expectation that access not be granted to personnel not on the authorized list should be made clear in the Reliability Standard.
465. In the CIP NOPR, the Commission addressed concerns raised with regard to the application of and compliance responsibility for the CIP Reliability Standards, especially on access issues, when facilities governed by existing joint use or joint ownership agreements are involved.
466. In the CIP NOPR, the Commission stated that joint owners of critical cyber assets are equally as subject to the CIP Reliability Standards as are other responsible entities.
467. With regard to joint use arrangements, the Commission stated the principle that the owner of a critical cyber asset is responsible under the CIP Reliability Standards for ensuring that all persons having access to the critical cyber asset meet the requirements of the CIP Reliability Standards, much as the owner is responsible to ensure that vendor personnel have the required levels of security training, awareness and background checks.
468. The Commission proposed to require the ERO to consider further clarifying CIP-004-1 to address the “joint use” concerns expressed by APPA/LPPC while developing any modifications to the CIP Reliability Standards.
469. APPA/LPPC support the Commission's proposal to direct the ERO to address the joint use concerns.
470. Northern Indiana is concerned that the Commission's proposal means that a responsible entity must perform risk assessments of the other owner's personnel so that such personnel may access a facility that the responsible entity has identified as a critical cyber asset. Northern Indiana argues that such a broad application of the CIP Reliability Standards was never intended and requests that the Commission clarify this point. Northern Indiana sees a conflict with respect to sharing information with other entities that jointly own or jointly use transmission facilities if it is required to maintain a mutual distrust posture. Northern Indiana urges the Commission to provide for flexibility when applying the CIP Reliability Standards to such jointly owned facilities.
471. SPP believes that jointly operated assets may require contractual agreements to assign responsibility and liability for compliance with the CIP Reliability Standards, similar to the Commission's concern with respect to out-sourced service providers in the CIP NOPR. It is unclear to SPP whether the Commission's recommendations adequately cover the situation where each party is uniquely responsible for a subset of the requirements of the CIP Reliability Standards. For example, one entity may place critical cyber assets within a facility managed by a second entity. The second entity would be fully responsible for the physical security requirements of CIP-006-1, while the first entity would be fully responsible for the system management requirements of CIP-007-1 only for their own assets. A contractual agreement between the two entities should be in place to codify the second entity's physical security responsibilities and, as with out-sourced services, to absolve the first entity of any responsibility for CIP-006-1
472. NRECA is concerned that the Commission's joint use proposal would cause problems for small entities. NRECA also raises concerns about how disputes regarding joint use facilities will be addressed.
473. The Commission adopts its proposals in the CIP NOPR with a clarification. As a general matter, all joint owners of a critical cyber asset are responsible to protect that asset under the CIP Reliability Standards. The owners of joint use facilities which have been designated as critical cyber assets are responsible to see that contractual obligations include provisions that allow the responsible entity to comply with the CIP Reliability Standards. This is similar to a responsible entity's obligations regarding vendors with access to critical cyber assets.
474. Regarding Northern Indiana's comments, we do not believe that this Requirement obligates one joint owner of a critical cyber asset to perform risk assessments of another owner's personnel. Each such owner is responsible for performing assessments of its own personnel.
475. The ERO should consider the suggestions raised by Northern Indiana, SPP and NRECA in the Reliability Standards development process.
476. Therefore, we direct the ERO to modify CIP-004-1, and other CIP Reliability Standards as appropriate, through the Reliability Standards development process to address critical cyber assets that are jointly owned or jointly used, consistent with the Commission's determinations above.
477. NERC's proposed Standard CIP-005-1 requires identification and protection of the electronic security perimeters inside which all critical cyber assets are located, as well as all access points. The electronic security perimeters are to encompass all the critical cyber assets that are identified using the methodology required by Standard CIP-002-1. Multiple electronic security perimeters may be required; for example, one may be needed around a control room while another may be established around a substation. For any electronic security perimeter established, the responsible entity must develop mechanisms to control and monitor electronic access to all electronic access points and, further, it must assess the electronic security perimeter's cyber vulnerability and test every electronic access point at least annually.
478. The Commission approves Standard CIP-005-1 as mandatory and enforceable. In addition, we direct the ERO to develop modifications to this CIP Reliability Standard. The Commission also requires the ERO to clarify and provide guidance on other matters. The required modifications are discussed below in the following topic areas of concern regarding CIP-005-1: (1) Adequacy of electronic security perimeters; (2) protecting access points and controls; (3) monitoring access logs; and (4) vulnerability assessments.
479. Requirement R1 of CIP-005-1 requires each responsible entity to identify electronic security perimeters and ensure that every critical cyber asset resides within one.
480. In the CIP NOPR, the Commission stated that, while the electronic security perimeter constitutes a first line of defense, the effectiveness of any one defensive measure is often dependent on the quality of active human maintenance, and that there is no one perfect defensive measure that will guarantee the protection of the Bulk-Power System. The Commission proposed to direct the ERO to develop a requirement that a responsible entity implement a defensive security approach including two or more defensive measures in a defense in depth posture when constructing an electronic security perimeter.
481. Many commenters, including Manitoba, NERC, NRECA, Ontario Power and ReliabilityFirst, maintain that CIP-005-1 is adequate as drafted and they oppose the Commission's proposal to require a defense in depth strategy.
482. NERC and ReliabilityFirst argue that the defense in depth provisions recommended by the Commission make sense in a control center environment, because additional layers of electronic security and physical security can be readily implemented, and they are prudent due to the centralized function performed at a control center. However, they question the direct impact to the reliability of the Bulk-Power System from implementing multiple defensive actions in a substation or generating plant environment. NRECA believes that the CIP NOPR contemplates imposing excessive defense in depth requirements, particularly in environments where the additional depth will not yield a significant benefit, but will impose costs. NRECA states that a better course would be for the Commission to defer to the ERO's technical expertise as to the application of defense in depth, rather than dictate a specific outcome.
483. NERC, Idaho Power and ReliabilityFirst further explain that the use of multiple electronic security perimeter devices (i.e., firewalls) obtained from different vendors, creating rings of protection using different methods, is an accepted mainstream information technology approach. The expected result is that a failure of one device only appears on one of the two perimeters, thereby allowing the other perimeter to provide the desired protection. For small numbers of zones, which protect relatively large numbers of assets (e.g., a single zone containing all of the corporate servers), this makes implementation and economic sense.
484. However, NERC states that the use of multiple electronic security perimeter devices comes at a cost to performance and reliability. According to NERC, each “hop” through a perimeter device introduces a delay in the transmission of the data. In a traditional information technology environment, this may be tolerable, or may be mitigated through the use of higher-speed networks. In a control system environment, NERC states that neither option may be acceptable or available. Additional equipment takes up space in equipment racks, and uses additional power and cooling, which in
485. Ontario Power argues, similarly, that while the multiple layers of security required by a defense in depth strategy may be feasible in some situations, it is impractical or impossible in others and should be excluded from the Final Rule.
486. APPA/LPPC and Northern Indiana state that CIP-005-1 provides the needed degree of flexibility to accommodate very diverse physical and electronic situations.
487. Arkansas Electric, Duke and Northern Indiana state that there is a point at which having multiple defense layers would not be cost-effective. Arkansas Electric and Duke maintain that the CIP Reliability Standards as a whole prescribe a sufficient defense-in-depth strategy. In addition to electronic security controls, Arkansas Electric notes that the Reliability Standards also require physical security controls, access-control, authentication, and intrusion detection at the perimeter. The CIP Reliability Standard also requires a general “hardening” of the security of the critical cyber assets. Furthermore, policy and procedural controls are required. Adding security controls for the sake of redundancy adds unnecessary cost, complexity and administrative burden to the system. Further, Duke argues that responsible entities must establish sufficient electronic and physical security perimeters, which in some situations could require multiple layers that other situations do not warrant.
488. Manitoba maintains that providing one monitored and alarmed electronic security measure provides a sufficient and balanced security measure when implemented in conjunction with required physical security measures. The proposed additional security measure may require other security installations within the proposed implementation timeframe for CIP Reliability Standards that could delay implementation of the more important requirement to establish an electronic perimeter for all critical cyber assets.
489. SDG&E and Entergy raise concerns with the Commission's comments regarding the placement of security measures in front of systems. SDG&E cautions against giving such “in front” measures a high priority over those placed inside the system. SDG&E comments that consideration of both measures is necessary to make informed defense in depth decisions. Alternatively, it agrees with NERC that the Commission should omit the requirements for a defense in depth approach in the Final Rule. Entergy also disagrees with the Commission's proposal to place measures “in front of” systems as opposed to “inside” systems. It argues that data/control centers and field sites are two very different matters and that two-factor authentication is more challenging in the field, where most equipment being remotely accessed simply cannot be upgraded or retro-fitted to affect this technological approach.
490. APPA/LPPC argue that, if the Commission continues to direct the ERO to require two or more defensive measures, then it should clarify whether or not the second security measure must be on a par with the first security measure. NERC and APPA/LPPC maintain that an inflexible rule calling for redundant electronic security in all cases poses some very practical problems in a variety of settings. APPA/LPPC believe that, given sufficient flexibility by the Commission, these issues can be worked out in the Reliability Standards development process.
491. In FPL Group's view, the NERC approach of allowing responsible entities to develop strategies appropriate for their environment to protect their critical cyber assets is preferable to the CIP NOPR proposal. FPL Group characterizes the CIP NOPR proposal as a “one size fits all” approach that could fail to take into account site-specific realities. It is concerned that the CIP NOPR approach mandates form over function and logic by placing too much emphasis on uniformity and ignoring a site's specific environment.
492. In contrast, Juniper and ISA99 Team argue that multiple layers are essential for defense in depth and that the Reliability Standard must provide guidance on devices that may be considered to be a layer of defense. ISA99 Team argues that single peripheral layers of defense are not adequate to protect control networks. More significantly, ISA99 Team argues, the very nature of the CIP Reliability Standards provides defense in depth for many of the control system components. For example, not only are perimeters identified and established, and defended with access controls, but anti-virus and other defensive measures are applied to components within the perimeters. ISA99 Team argues that this defense in depth is consistent with guidance provided in most references and standards today.
493. In addition, ISA99 Team disagrees that legacy control systems can be excused from defense in depth requirements. ISA99 Team argues that it is unacceptable to leave critical control systems components, like distributed control systems controllers, remote terminal units for supervisory control and data acquisition systems, programmable logic controllers and intelligent electronic devices, without additional protection similar to that commonly used for basic personal computers used in business system networks every day. And this protection can be provided by various means, including further segmentation and isolation of those components from the other parts of the control networks. It does mean additional hardware and does require great caution, but it can be done effectively and should be required for our critical power infrastructure.
494. Juniper comments that, unless wireless access can be limited to a physical boundary, any wireless enabled device must be considered as outside the perimeter and must authenticate to gain access and encrypt its communications. Jamming of RF signals even with spread-spectrum is a real concern. An attack does not have to jam all transmission. It can cause disruption by corrupting data. If this can cause loss of data for even a short duration, that might be enough to perpetrate other incursions without raising alarms.
495. Northern Indiana and Xcel ask the Commission to clarify or direct the ERO to clarify the phrase “single access point at the dial up device” in CIP-005-1, Requirement R1.2. Xcel asks whether this refers to the initiating device, the device at the point of termination, or both. Northern Indiana would not modify CIP-005-1, but urges that any modifications to Requirement R2 should
496. The Commission adopts the CIP NOPR's proposal to direct the ERO to develop a requirement that each responsible entity must implement a defensive security approach including two or more defensive measures in a defense in depth posture when constructing an electronic security perimeter. However, in light of the comments received, the Commission understands that there may be instances in which certain facilities cannot implement defense in depth or where such an approach would harm reliability rather than enhance it. For that reason, the Commission believes that it is appropriate to allow the ERO and the Regional Entities to grant exceptions based on the technical feasibility of implementing defense in depth, consistent with the Commission's determination on technical feasibility above. However, the responsible entity should implement electronic defense in depth measures or justify why it is not doing so pursuant to our discussion of technical feasibility exceptions.
497. As stated in the CIP NOPR, the Commission recognizes that there is a point at which having multiple defense layers would not be cost effective. However, we continue to believe that the effectiveness of any one defense measure is often dependent on the quality of active human maintenance, and there is no one perfect defense measure that will guarantee the protection of the Bulk-Power System. The Commission does not agree with Manitoba that providing one monitored and alarmed electronic security measure provides a sufficient and balanced security measure when implemented in conjunction with required physical security measures. A single electronic device is too easy to bypass and a physical security measure cannot thwart an electronic cyber attack. Therefore, we believe it is in the public interest to require that a responsible entity must implement two or more distinct security measures when constructing an electronic security perimeter.
498. Many of the commenters' concerns with regard to the impact on performance and reliability will be alleviated by allowing Regional Entities to grant justified exceptions based on technical feasibility. For example, an exception might be granted if an entity can demonstrate that implementing any defense in depth mechanism would create a delay in the transmission of the data that is not tolerable on the system and cannot be mitigated. In addition, the Commission does not think that there will be a problem with respect to a delay in data transmission. If this is a problem for older or distant equipment, the responsible entity can claim a technical feasibility exception. Newer equipment should operate at sufficiently high speeds that multiple hops will not affect data transmission. In fact, some vendor companies claim that their devices will actually increase transmission speeds due to compression and other techniques.
499. Further, an exception might be granted until equipment is available for a given protocol or toolset used in a specific control system environment. However, the fact that additional equipment may take up space or use additional power and cooling alone does not warrant reversing the Commission proposal.
500. The Commission agrees with the ERO that requiring two or more defensive measures may increase the chance of equipment failure. But, the ERO has not provided the Commission with an adequate explanation of why the availability of the entire system would decrease with two or more defensive measures. Defensive measures can often be formatted so that if they fail, they do so in a fail-safe mode that still allows operation. Therefore, system availability would not decrease.
501. In response to SDG&E and Entergy, in stating that the placement of security measures in front of systems provides a layer of protection for those systems, the Commission was not giving priority to “in front” measures. In fact, the Commission acknowledged in the CIP NOPR that defense in depth measures are generally integrated within and constitute part of a system or program. In commenting that defense in depth measures may also be effectively placed in front of a system, the Commission intended only to acknowledge that there are multiple ways to implement a defense in depth strategy. The Commission is not mandating any specific mechanism to be the second security measure. We are also not requiring uniformity of security measures, only that each responsible entity have at least two security measures unless it is not technically feasible to do so. The revised CIP Reliability Standard should allow enough flexibility for a responsible entity to take into account each site's specific environment. The Commission believes that this, in conjunction with the allowance of technical feasibility exceptions, alleviates FPL Group's concern that the Commission's proposal is a “one size fits all” approach.
502. In response to APPA/LPPC, the Commission clarifies that it does not intend to create an inflexible rule calling for redundant electronic security in all cases. While the Commission directs that a responsible entity must implement two or more distinct security measures when constructing an electronic security perimeter, the specific requirements should be developed in the Reliability Standards development process. This would include whether or not the second security measure must be “on par” with the first. The Commission also directs the ERO to consider, based on the content of the modified CIP-005-1, whether further guidance on this defense in depth topic should be developed in a reference document outside of the Reliability Standards.
503. In response to Manitoba's concern that the proposed additional security measure could delay implementation of the more important requirement of an electronic perimeter for all critical cyber assets, the Commission notes that this Final Rule approves the Reliability Standard as filed by the ERO. The Commission is directing the ERO to revise the Reliability Standard to require two or more defensive measures. Until that Reliability Standard is developed by the ERO and approved by the Commission, responsible entities in the United States will not be required to implement two or more defensive measures.
504. The ERO should consider in the Reliability Standards development process Northern Indiana's and Xcel's concerns regarding the phrase “single access point at the dial up device.”
505. Requirement R2 of CIP-005-1 requires a responsible entity to implement organizational processes and technical and procedural mechanisms for control of electronic access at all electronic access points to the electronic security perimeter. Requirement R2.4 requires “strong procedural and technical controls” at enabled external access points “to ensure authenticity of the accessing party, where technically feasible.”
506. The Commission indicated that requiring “strong” controls does not provide sufficient guidance toward ensuring authenticity of the accessing party, and proposed to direct the ERO to modify Requirement R2.4 of CIP-
507. Consistent with our discussion of technical feasibility, we did not propose to direct the ERO to remove the technical feasibility language from Requirement R2.4 of CIP-005-1. However, we proposed that Regional Entities review the application of “technical feasibility” as the basis for allowing a responsible entity an exception to full compliance with a Requirement.
508. The Commission also clarified the specific conditions and accountability measures needed to be granted an exception based on technical feasibility.
509. SoCal Edison and MidAmerican agree with the Commission that Requirement R2.4 needs to be clarified. ISO-NE raises a concern regarding the phrasing of “ `strong controls' * * * such as digital certificates and two-factor authentication.” ISO-NE asks that the Commission ensure that “use of either digital certificates or two-factor authentication” constitutes an acceptable example for strong authentication. Entergy generally agrees with the Commission's proposal to direct the ERO to modify this CIP Reliability Standard in accordance with the Blackout Report. In Entergy's view, well-constructed passwords should be satisfactory as long as password management best practices are employed, such as configuring equipment to `drop calls' after presentation of three successive incorrect passwords.
510. Juniper also argues that several CIP Reliability Standards require the use of encryption. Juniper recommends that specific NIST or Federal Information Processing Standards (FIPS) encryption standards be mentioned as minimum requirements for compliance as weak encryption mechanisms can be easily reverse engineered.
511. The Commission adopts the CIP NOPR's proposal to direct the ERO to identify examples of specific verification technologies that would satisfy Requirement R2.4, while also allowing compliance pursuant to other technically equivalent measures or technologies. In response to commenters, in discussing digital certificates and two-factor authentication, the Commission was providing examples of strong authentication, not limiting authentication to those options. The Commission is not prescribing the specific methods as an exclusive solution pursuant to Requirement R2.4. The ERO can propose an alternative solution that it believes is equally effective and efficient. If the ERO believes it would be helpful to responsible entities, additional guidance beyond the examples that are eventually included in Requirement R2 can be given in a separate reference document. Since we are directing the ERO to provide guidance on what constitutes strong authentication, it is not necessary for the Commission to respond to ISO-NE's request that digital certifications or two-factor authentication are acceptable methods of authentication. In identifying examples or categories of specific verification technologies that would satisfy Requirement R2.4, the ERO should take into account the specific comments raised in this proceeding. Similarly, while encryption is one method to accomplish two-factor authentication, and is an effective process for ensuring authenticity of the accessing party, for some facilities, we leave it to the ERO in the Reliability Standards development process to evaluate whether and how to address the use of encryption. In the alternative, the ERO may identify verification technologies or categories of verification technologies in a reference document.
512. Requirement R3 of CIP-005-1 requires responsible entities to implement electronic or manual processes for monitoring and logging access at access points to the electronic security perimeter at all times. Further, where technically feasible, the security monitoring process must detect and alert for attempts at or actual unauthorized access. Where such alerts are not technically feasible, Requirement R3.2 requires a responsible entity to review access logs at least every 90 calendar days.
513. The Commission stated that regular manual review of logs is beneficial because, while automated review systems provide a reasonable daily check and a convenient screening for obvious system breaches, periodic manual review provides the opportunity to recognize an unanticipated form of malicious activity and improve automated detection settings. The Commission stated that frequent reviews of access logs are necessary to detect breaches that automated alerts do not detect and, moreover, where automated alerts are not used, frequent monitoring takes on even greater importance.
514. The Commission recognized that accessibility of an access log may affect the review interval. We stated, for instance, that readily available logs, such as those from within a control room setting, should be reviewed at least weekly. Those logs that are not readily available, such as those located at a remote substation, are less accessible and therefore can be read less frequently. We stressed, however, that any attempt to differentiate the required frequency of review of these logs must be balanced against the criticality of the facilities; it is not acceptable to dismiss a critical facility from timely review simply because it is remote.
515. The Commission proposed to direct the ERO to develop a bifurcated review requirement of access logs at electronic access points in which readily available logs are reviewed more frequently than every 90 days. The Commission stated that such review should be performed at least weekly. As part of developing this bifurcated review requirement, the Commission proposed to direct the ERO to include in the Reliability Standard guidance on how a responsible entity should designate individual assets as “readily accessible” or “not readily accessible,” consistent with our discussion above.
516. EEI and Tampa Electric maintain that the proposal to revise the log review requirements in CIP-005-1 is overly prescriptive.
517. Entergy, MidAmerican, Northern Indiana, PG&E, ReliabilityFirst, SPP and Tampa Electric do not agree with the Commission that a weekly review of access logs at electronic access points is necessary. A weekly review would place an undue burden on the industry without a clear direct benefit to improved security given the proposed level of increased frequency. Entergy argues that the Commission should
518. Tampa Electric argues that weekly manual reviews of substantial data are too burdensome especially when an entity is capable of performing electronic reviews. Along the same lines, Idaho Power argues that the proposed bifurcated review process may be extremely difficult to perform without technological advances in products. Idaho Power agrees that a review must occur; however, without technology to assist, it argues that implementation will be difficult.
519. ISO-NE comments that automated log monitoring to detect and alert on any unauthorized or suspicious events is sufficient, and that manual review of logs should only be required in situations where automated monitoring and alerting tools are not technically feasible. However, ISO-NE does suggest that review of automated alerts should be frequent. ISO-NE maintains that its perspective is supported by evaluations that it conducted against a subset of cyber assets similar to those that would be used to maintain an electronic security perimeter and those that would be found inside an electronic security perimeter. ISO-NE found that the logs generated by its testing were voluminous and any effort to routinely manually review logs would be futile and burdensome. In ISO-NE's view, other than during a forensic investigation in response to an automated alert, any expectation of useful manual review on a routine basis is not reasonable.
520. ReliabilityFirst and SPP disagree that a regular manual review of logs is always beneficial. For example, a weekly manual review of logs in a control room setting may be impossible. In a control center environment, the electronic security perimeter firewalls may log several million events per day. The outer network perimeter firewalls will typically log an even greater number of events per day. Servers and workstations may record hundreds to thousands of events per day across the system, security, and wide variety of application logs. The only way to monitor and analyze the logs is through the use of automation.
521. While MidAmerican supports frequent review, it maintains that the review intervals should be designed to accomplish the detection and improvement objectives discussed in the CIP NOPR. MidAmerican submits that basing review intervals on accessibility of records will not optimally achieve this objective and would be unduly burdensome for responsible entities and should be reconsidered. MidAmerican would support a frequency of 30 days for electronically generated access logs and a 45-day review frequency for manually generated logs.
522. SPP believes that a periodic review of the log correlation and analysis engine's rules should be conducted to ensure the automated analysis is properly alerting on pertinent events. This may require a manual examination of the raw log files. A weekly review is excessive—a quarterly review may be more appropriate, as would a review upon a significant change to the access controls.
523. By contrast, Juniper argues that logs should be reviewed daily, stating that there are correlation tools that can prioritize events automatically and reduce the effort required to go through all logs manually. Juniper argues that the requirement for reporting within an hour of an incident seems to be at odds with not requiring frequent review of the logs.
524. MidAmerican maintains that the term “bifurcated review” is inadequately defined. MidAmerican recommends that the Commission add specific language addressing the use of a combination of automated and manual review of logs to satisfy this requirement. Likewise, the terms applying to whether the logs are “readily available,” “readily accessible” and “not readily accessible” need clarification to facilitate compliance. Northern Indiana also requests that the Commission clarify the scope of the reviews and what is meant by the term “readily accessible.”
525. The Commission adopts the CIP NOPR proposal to require the ERO to modify CIP-005-1 to require logs to be reviewed more frequently than 90 days, but clarifies its direction in several respects. At this time, the Commission does not believe that it is necessary to require responsible entities to review logs daily, as requested by Juniper.
526. The Commission agrees with MidAmerican that the review intervals should be designed to accomplish the detection and improvement objectives discussed in the CIP NOPR. Requirement R3 of CIP-005-1 does not currently require a responsible entity to manually review logs if it has alerts. However, the Commission continues to believe that, while automated review systems provide a reasonable day-to-day check of the system and a convenient screening for obvious system breaches, periodic manual review provides the opportunity to recognize an unanticipated form of malicious activity and improve automated detection settings. Further, manual review is beneficial to judge the effectiveness of protection measures, such as firewall settings. If a firewall setting is incorrect or ineffective, an automated review system may not identify a cyber security intrusion. For those entities without automated log review and alerts, it is even more important to perform a manual review because this will be the only review of the logs. The Commission believes allowing 90 days to pass without a log review is unacceptable. In that time, an incident could have occurred undetected or an attacker could have gained access to a critical system and extended that access throughout the enterprise with the targeted entity being unaware that the security of their systems had been compromised. For this reason, the Commission directs the ERO to modify CIP-005-1 through the Reliability Standards development process to require manual review of those logs without alerts in shorter than 90-day increments. The Commission continues to believe that, in general, logs should be reviewed at least weekly, but leaves it to the Reliability Standards development process to determine the appropriate frequency. In addition, the Commission directs the ERO to modify CIP-005-1 to require some manual review of logs, consistent with our discussion of log sampling below, to improve automated detection settings, even if alerts are employed on the logs.
527. In response to MidAmerican's concern about the term “bifurcated review,” the Commission intent was that certain assets, deemed readily accessible, would be reviewed at least weekly while other assets would continue to be reviewed every 90 days. However, the Commission will not adopt this direction from the CIP NOPR. We leave it to the Reliability Standards development process to decide whether different timeframes are appropriate for logs that are readily accessible and not readily accessible. If different review timeframes are adopted, the ERO should provide guidance as to what constitutes a readily accessible log and a log that is not readily accessible. The ERO may also delineate different timeframes for manual review for other reasons, but must clearly define how to determine in
528. Finally, the Commission also agrees with commenters that a full review of logs could be burdensome. Therefore, the Commission clarifies its direction with regard to reviewing logs. In directing manual log review, the Commission does not require that every log be reviewed in its entirety. Instead, the ERO could provide, through the Reliability Standards development process, clarification that a responsible entity should perform the manual review of a sampling of log entries or sorted or filtered logs. The Commission recognizes that the manner in which a responsible entity determines what sample to review may not be the same for all locations. Therefore, the revised Reliability Standard does not need to prescribe a single method for producing the log sampling. However, any requirements for creating this sample review could be detailed in its cyber security policy so that it can be audited. The Reliability Standards development process should decide the degree to which the revised CIP-005-1 describes acceptable log sampling. The ERO could also provide additional guidance on creating the sampling of log entries, which could be in a reference document. The final review process, however, must be rigorous enough to enable the responsible entity to detect intrusions by attackers.
529. Requirement R4 of CIP-005-1 requires a responsible entity to “perform a cyber vulnerability assessment of the electronic access points to [an] electronic security perimeter at least annually.” The minimum criteria provided do not specify whether a live vulnerability assessment is required, as opposed to a paper assessment.
530. In the CIP NOPR, the Commission stated that annual vulnerability assessments are sufficient when no modifications are made, but that when the electronic security perimeter or another measure in a defense in depth strategy is modified, it is not acceptable to wait a year to test modifications.
531. The Commission also proposed to direct the ERO to modify Requirement R4 to require live vulnerability assessments at least once every three years, with annual paper assessments allowable in the intervening years. The Commission stated that, if such live vulnerability assessments are not “technically feasible,” then a responsible entity may apply to be excused from full compliance to the Regional Entity, fully documenting the necessary interim actions, milestone schedule, and mitigation plan.
532. Northern California and PG&E support live, not paper, vulnerability assessments of the electronic security perimeter, subject to exceptions where necessary. PG&E qualifies its support, explaining that technical infeasibility is not the only valid reason for not performing a live vulnerability assessment.
533. NERC, ReliabilityFirst, Northern Indiana, SDG&E and Ontario Power address their concerns about live testing issues generally, across Requirements that span several of the CIP Reliability Standards. They argue that the Commission should omit the requirements to include “live vulnerability testing” requirements in the Final Rule.
534. NERC and ReliabilityFirst believe that “active” vulnerability assessments of test systems are beneficial to understanding potential attacks. However, NERC finds it problematic to require test environments for all possible instances of electronic security perimeters and critical cyber assets. While most modern control centers contain such environments, they are rare for substation and generating plant environments, and the required resources could not be justified simply to perform active vulnerability tests once every three years.
535. NERC and ReliabilityFirst argue that, while test systems are required for testing of patches and software updates, these are not required to exactly match or mirror the operational system. For example, if a substation consists of many intelligent electronic devices, but only a few different models of intelligent electronic devices, then the test environment for patches and updates need only have one of each model in order to test updates. Depending on the vendor implementation, a single intelligent electronic device representative of all of the intelligent electronic devices may be sufficient for this purpose. This environment is suitable to test for software vulnerabilities, even though it is not a “full” or “complete” replication of the real environment, because it represents the essential equipment to perform the test. NERC states that it could support performing active tests in such an environment, provided the responsible entity could document and demonstrate that the test environment and the tests performed do, in fact, map to all the implemented components of the live environment.
536. NERC therefore requests that the Commission decline to include its proposed requirements for live vulnerability testing in the Final Rule. Rather, NERC proposes replacing live vulnerability testing with “active vulnerability assessments of test systems.”
537. Northern Indiana argues that the current Reliability Standard allows the flexibility of performing live or paper vulnerability assessments as appropriate.
538. Juniper argues that, in addition to the paper assessment, creation of a “sandbox” environment that is fairly representative of the physical plant must be mandatory. Semi-annual penetration test of such a sandbox is essential.
539. MidAmerican believes that conducting a vulnerability assessment of the electronic access points as part of, or contemporaneously with, any modifications to the electronic security perimeter or defense in depth strategy on a three-year cycle would be an extremely burdensome task. It suggests the following: (1) A baseline audit; (2) an assessment during the change control process of the vulnerability implications; and (3) a periodic review based upon the assessment.
540. Several commenters state that the Commission's proposal to require a vulnerability assessment when any “modification” of the electronic security perimeter or defense in depth strategy is made is too broad.
541. The Commission notes that the concerns expressed by some commenters of triggering an unknown vulnerability during a live test is one reason why some form of live or active testing is necessary. A responsible entity cannot protect its system from exploitation of vulnerabilities that it does not know about. However, in light of the comments received, the Commission will not adopt its proposal as set out in the CIP NOPR regarding live vulnerability assessments in Requirement R4 of CIP-005-1. Instead, we adopt the ERO's proposal to provide for active vulnerability assessments rather than full live vulnerability assessments. Further, as discussed below, we clarify that an interim vulnerability assessment will only need to be performed if a responsible entity makes a significant modification to the electronic security perimeter.
542. The Commission's goal in proposing live vulnerability testing is to provide a level of confidence that the Bulk-Power System has a certain level of resistance to attack. We understand the concerns raised by commenters that live vulnerability testing could, at this time, diminish reliability. While the Commission's goal is to require full live vulnerability testing on the entire Bulk-Power System at some point, we understand that this may not be possible at this time. As suggested by FirstEnergy, industry may need time to gain experience in this area before it can conduct full live vulnerability testing. Therefore, the Commission adopts the ERO's recommendation of requiring active vulnerability assessments of test systems.
543. The Commission agrees with the ERO that test systems do not need to exactly match or mirror the operational system. However, to perform active vulnerability assessments, the responsible entities should be required to create a representative system, i.e., one that replicates the actual system as closely as possible. The active vulnerability assessment should be carried out on this representative system. In doing so, a responsible entity must document the differences between the operational and representative system for the auditors. As part of this documentation, the responsible entity should also document how test results on the representative system might differ from the operational system, and how the responsible entity accounts for such differences in operating the system. Our goal is to ensure that each responsible entity understands the differences between its representative system and the operational system and how those differences might affect its test results. The entities remain responsible, however, to ensure that the testing systems are adequate to model the production systems and to document and account for the differences between the two.
544. Further, the Commission agrees with commenters that requiring each responsible entity to perform a vulnerability assessment of the electronic access points when any modification is made to the electronic security perimeter or defense in depth strategy is too broad. Instead, the Commission directs the ERO to revise the Reliability Standard so that annual vulnerability assessments are sufficient, unless a significant change is made to the electronic security perimeter or defense in depth measure, rather than with every modification. To be clear, the Commission is not requiring the Reliability Standard to use the terminology that a “significant change” is made to the electronic security perimeter or defense in depth strategy. Rather, we are directing the ERO to determine, through the Reliability Standards development process, what would constitute a modification that would require an active vulnerability assessment. For example, we would anticipate that updating an attack signature file on the electronic access point would not require an active vulnerability assessment, but replacing the devices that comprise the electronic access point would require an active vulnerability assessment.
545. Given our changes to the Commission proposal, and based upon the comments, the Commission does not believe performing an active vulnerability assessment once every three years will pose too great a burden on company personnel. The burden above that is required by the Reliability Standard as proposed by the ERO is justified by the insights that will be gained from the active assessments.
546. At this time, the Commission does not believe it is necessary to require twice a year penetration tests by responsible entities, as requested by Juniper. We believe that the combination of annual testing and active vulnerability assessments is sufficient for the Reliable Operation of the Bulk-Power System.
547. In sum, we direct the ERO to modify Requirement R4 to require these representative active vulnerability assessments at least once every three years, with subsequent annual paper assessments in the intervening years. The ERO should develop the details of how to determine what constitutes a representative system and what modifications require an active vulnerability assessment in the Reliability Standards development process. The revised Reliability Standard should contain the essential
548. Reliability Standard CIP-006-1 addresses the physical security of the critical cyber assets identified in Reliability Standard CIP-002-1. In particular, CIP-006-1 requires a responsible entity to create and maintain a physical security plan that ensures that all cyber assets within an electronic security perimeter also reside within an identified physical security perimeter.
549. Reliability Standard CIP-006-1 also addresses operational and procedural controls to manage physical access at all access points to the physical security perimeter at all times by the use of alarm systems and/or human observation or video monitoring. The Reliability Standard also requires that the logging of physical access must occur at all times, and the information logged must be sufficient to uniquely identify individuals crossing the perimeter. Finally, the Reliability Standard requires responsible entities to test and maintain all physical security mechanisms on a three-year cycle.
550. In the CIP NOPR, the Commission proposed to approve Reliability Standard CIP-006-1 as mandatory and enforceable. In addition, we proposed to direct the ERO to develop modifications to this Reliability Standard. Further, the Commission also proposed to require the ERO to consider various other matters of clarification, guidance, and modification. In our discussion below, we address the following topic areas regarding CIP-006-1: (1) Physical security plan; (2) physical access controls and monitoring physical access; and (3) maintenance and testing.
551. Requirement R1.1 of CIP-006-1 addresses processes that a responsible entity must include in its physical security plan to ensure that all cyber assets within an electronic security perimeter also reside within an identified physical security perimeter. The CIP Assessment noted that Requirement R1.1 anticipates that there may be instances where a completely enclosed border cannot be established and that, in such instances, the responsible entity shall deploy and document “alternative measures” to control physical access to the critical cyber assets. It cautioned, however, that Requirement R1.1 does not provide guidance on how an alternative measure should be identified or determined to be adequate.
552. In the CIP NOPR, the Commission stated that the phrase “alternative measures” as referenced in Requirement R1.1 should be interpreted to be an exception to the Requirement, and that our discussion of technical feasibility exceptions should apply to Requirement R1.1. We noted that, under this Requirement, the responsible entity is required to deploy and document alternative measures if a completely enclosed six-wall border cannot be established to control physical access to the critical cyber assets. However, we observed that the Requirements did not provide guidance on how an alternative measure should be identified or determined to be adequate. Therefore, the Commission proposed to direct the ERO to treat the allowance of alternative measures as interim actions developed and implemented as part of a mitigation plan under a technical feasibility exception.
553. NERC, APPA/LPPC, OGE, SoCal Edison and SDG&E disagree with the Commission's proposal to treat the allowance of alternative measures as interim actions developed and implemented as part of a mitigation plan under a technical feasibility exception.
554. MidAmerican generally supports the proposal to treat an alternative measure to a six-walled perimeter as an exception and mitigated under a technical feasibility exception for the reasons articulated in the CIP NOPR. However, MidAmerican recommends that the Commission consider the alternative measures to be implemented when a six-wall border cannot be established, where appropriately equivalent, as the mitigation solution and not an interim action. The merits of the alternative measures can be evaluated at the time of an audit.
555. NERC, APPA/LPPC, Arizona Public Service, and Consumers maintain that, where the equipment cannot be contained within a six-wall border, alternative measures should be permitted on a permanent basis. NERC argues that the Commission's proposal implies that by treating these alternative measures as interim actions with required mitigation plans, the responsible entity could overcome the physical or safety-related obstacles to achieving the completely enclosed physical boundary. NERC believes this is impractical, if not impossible. APPA/LPPC assert that the configuration or layout of a specific cyber asset simply may not lend itself to a complete physical perimeter, and alternative means of protection (including electronic protections) may be entirely adequate, given the level of security risk posed by the asset and the nature of the alternative form of protection. In some cases, NERC states that there is no possibility of mitigation. The responsible entity does not choose not to completely enclose the asset—it is a physical limitation which cannot be overcome. In cases where the physical or safety limitations do not exist, the responsible entity is expected to comply with the Requirements, and not use alternative measures. In cases where the physical limitations cannot be overcome, NERC argues that the responsible entity cannot ignore the Requirement, but must implement an alternative. NERC also argues that this alternative is expected to be a permanent solution, not an interim measure.
556. Arizona Public Service agrees with NERC that the Commission should omit this proposal from the Final Rule and supports remanding this provision to NERC to modify R1.1 to permit the use of alternative measures on a permanent basis under requirements, developed through the NERC Reliability Standards development process, which could include documenting and justifying the need for the alternative measure and describing the alternative measures implemented.
557. Georgia Operators states that the industry will continue to struggle for years to agree on a clear definition of
558. While APPA/LPPC maintain that alternative measures should be documented by the Regional Entity, Northern Indiana argues that, if a responsible entity establishes or has established adequate alternative measures, then the responsible entity should not need to document or otherwise justify the alternative measure. Northern Indiana requests that, if the Commission does require NERC to modify Requirement R1 in the Final Rule, it clarify what is meant by alternative measures.
559. We are persuaded by commenters that there may be instances in which the physical or safety-related obstacles to achieving a completely enclosed physical boundary cannot be overcome. In such instances, we agree with commenters that it would be inappropriate to treat the alternative measures under this CIP Reliability Standard as interim actions under the technical feasibility exception, as the exception was proposed in the CIP NOPR. However, the Commission has revised its determination with respect to the technical feasibility exception to address concerns such as those raised by commenters on Requirement R1.1 of CIP-006-1. The Commission believes that allowing a technical feasibility exception to Requirement R1.1 of CIP-006-1, with the changes discussed in the Technical Feasibility section of this Final Rule, should address commenters' concerns. Specifically, the Commission acknowledges that some circumstances merit reliance on mitigation strategies that are ongoing and effective, so long as they are justified and reviewed periodically. This should alleviate the concern of commenters that the Commission is not allowing exceptions to Requirement R1.1 on a long-term basis.
560. Therefore, the Commission directs the ERO to treat any alternative measures for Requirement R1.1 of CIP-006-1 as a technical feasibility exception to Requirement R1.1, subject to the conditions on technical feasibility exceptions.
561. Requirement R2 of the CIP Reliability Standard requires the use of at least one of four listed physical access control methods, but does not require or suggest that the method(s) employed to control physical access consider the characteristics of the access point at issue and the criticality of the asset being protected. Requirement R3 requires monitoring at each access point to the physical security perimeter, including alarm systems and/or human monitoring. For both Requirement R2 and Requirement R3, a responsible entity can choose whether to implement single or multiple access control methods and monitoring devices.
562. The CIP NOPR suggested that a responsible entity must, at a minimum, implement two or more different security procedures when establishing a physical security perimeter. It stated that use of a minimum of two different security procedures would, for example, enable continuous security protection when one of the security protection measures is undergoing maintenance and provides redundant security protection in the event that one of the measures is breached. Therefore, while the Commission recognized that there is a point at which implementing multiple layers of defense becomes an unreasonable burden to responsible entities, the Commission nevertheless proposed to direct the ERO to modify this CIP Reliability Standard to state that a responsible entity must, at a minimum, implement two or more different security procedures when establishing a physical security perimeter around critical cyber assets.
563. While California Commission finds the Requirements of CIP-006-1 to be sound and succinct, it also finds the proposal in the CIP NOPR to require two or more security procedures to be sound policy. It adds that defense in depth strategy should be used in such situations, because multiple security procedures make it harder for a potential attacker to penetrate the system. FirstEnergy finds the Commission's proposal to require a minimum of two different security procedures is appropriate where technically feasible. However, it notes that a variety of different security procedures could satisfy this requirement. For example, the minimum of two different security procedures could be met by having two doors each with one security device or one door with two security devices.
564. Within a substation, NERC and ReliabilityFirst argue that there is no practical way to implement a second physical perimeter without jeopardizing the reliability of the substation itself. If the “outer” perimeter is outside the building, NERC and ReliabilityFirst see space problems with adding the mandated physical security perimeter (e.g., monitoring, logging, access control, personnel management, and training) on the border fence, noting that, in most substations, physical space around the control building is at a premium, and implementing an additional perimeter is problematic.
565. NERC and ReliabilityFirst raise similar concerns with requiring two physical security controls as they do with respect to electronic security controls in CIP-005-1. They further argue that, if the control building structure is still expected to be the inner perimeter, then, by necessity, a new perimeter (most likely an additional fence) will need to be built. In space-restricted substations this will likely be impossible. Similarly, if the control building structure is expected to be the outer perimeter, additional construction—whether solid walls or fence-like caging—will need to be constructed inside the control building. In this regard, NERC objects to a requirement to retrofit existing installed equipment to require additional construction or cabinet installation required due to the distributed nature of the equipment. NERC considers it counterintuitive to require that these new constructions be built as “cabinets within cabinets” or “rooms within rooms,” contending that this kind of construction or implementation is burdensome without real benefit.
566. APPA/LPPC, Idaho Power, Northern Indiana, OGE and Tampa Electric do not believe that it is appropriate to categorically require two different security procedures when establishing a physical security perimeter. APPA/LPPC are concerned that the Commission's proposal to do so could necessitate needless and expensive redundancy. Since Requirements R2 and R3 are already designed to be redundant (controlled access is backed up by monitoring), APPA/LPPC assert the Commission's proposal would appear to require a total of four measures. If the Commission meant that four separate and distinct security measures are necessary to comply with Requirements R2 and R3,
567. Entergy argues that the term “security procedures” in CIP-006-1 is confusing and that the Commission should direct NERC to define the term. Entergy argues that the terms physical security “measures” or “barriers” in the context of perimeters would improve clarity, whereas the term “procedures” better applies to access control management (R2) and monitoring (R3).
568. Several commenters seek clarification of what the Commission intended in requiring two or more security procedures. For example, SPP interprets the Commission's comment as requiring two independent security procedures at the physical security perimeter access point, as opposed to complementary security controls such as closed-circuit television observation of a secured door. SPP recommends that the Commission clarify that this is its intent, and offers that if a proper defense in depth strategy is used that provides for progressively restricted access or other obstructions to access as one approaches the physical security perimeter, multiple access controls at the physical security perimeter access point are excessive. SPP recommends that a progressive security scheme be acceptable in lieu of implementing multiple access controls at the physical security perimeter access point. SPP further recommends that the Commission clarify its intent as to whether an asset perimeter fence would constitute an acceptable obstruction and achieve the goal of the Commission's proposal. Similarly, MidAmerican requests that the Commission clarify whether the security procedures must be completely independent or may rely on a common component.
569. Arkansas Electric states it is uncertain if the Commission intends the term security procedures to apply to actual methods of implementing physical security (e.g., locks, gates, fences) or to procedural methods (e.g., logging). Arkansas Electric argues that adequate security fencing with a special lock should suffice for a secondary physical security procedure.
570. Idaho Power states that, for example, special locks and key cards would meet the Commission's recommended security procedures; however, they are significantly the same control measure and do nothing to provide defense in depth. While they afford back-up during maintenance, they fall short on defense since one can override the other. If the Commission truly wants to promote defense in depth, Idaho Power states that the chosen options should be required to support one another (e.g., key cards and closed circuit television), and not be just two of the provided four options.
571. Northern Indiana argues that it is unreasonable to put in place two different security measures in remote or field locations. National Grid also argues that two or more different security procedures may not always be needed to accomplish defense in depth.
572. The Commission adopts the CIP NOPR proposal to direct the ERO to modify this CIP Reliability Standard to state that a responsible entity must, at a minimum, implement two or more different security procedures when establishing a physical security perimeter around critical cyber assets. However, similar to our determination in CIP-005-1 regarding defense in depth for electronic security perimeters, in light of the comments received, the Commission understands that there may be instances in which certain facilities cannot implement defense in depth or where such an approach would harm reliability rather than enhance it. For that reason, the Commission believes that it is appropriate to allow the ERO and the Regional Entities to grant exceptions based on the technical feasibility of implementing defense in depth, consistent with the Commission's determination on technical feasibility above. However, the responsible entity should implement physical security perimeter defense in depth measures or justify why it is not doing so pursuant to our discussion of technical feasibility exceptions.
573. As stated in the CIP NOPR, the Commission recognizes that there is a point at which implementing multiple layers of defense becomes an unreasonable burden to responsible entities. However, as more fully detailed in our discussion of defense in depth in CIP-005-1, we continue to believe that the effectiveness of any one defense measure is often dependent on the quality of active human maintenance, and there is no one perfect defense measure that will guarantee the protection of the Bulk-Power System.
574. In response to APPA/LPPC's comments, the Commission does not require two or more different monitoring methods under Requirement R3. We did not propose to modify Requirement R3 and are not doing so in this Final Rule. Further, the Commission did not intend to require two or more physical perimeters, as suggested by NERC and ReliabilityFirst. Rather, the Commission intended only to require the ERO to modify R2 to provide for two or more different and complementary physical assess controls at a physical access point of the perimeter. The Commission believes that this should clarify what it meant by the term “procedures” and sees no need to direct the ERO to define the term, as requested by Entergy.
575. In response to commenters' questions regarding specific physical access controls, the Commission clarifies that it does not intend to create an inflexible rule calling for redundant physical security. While the Commission continues to believe that a responsible entity must implement two or more distinct and complementary physical access controls at a physical access point of the perimeter, the specific requirements should be developed in the Reliability Standards development process when the ERO develops its modifications in response to this Final Rule.
576. Northern Indiana raises a concern about security measures in remote or field locations, but did not provide specific information. The Commission believes that, if it is not possible to implement two or more distinct physical security measures in a remote or field location, a Regional Entity could grant justified exceptions based on technical feasibility.
577. Requirement R6 of CIP-006-1 requires responsible entities to implement maintenance and testing programs of physical security systems on a cycle no longer than three years and retain testing and maintenance records for the same timeframe. In addition, Requirement R6 requires retention of outage records of certain physical security systems for a minimum of one year. In the CIP NOPR,
578. FirstEnergy agrees with the Commission that the frequency of the maintenance and testing programs should be a function of the accessibility of critical cyber assets. The Requirement should specify the form of testing and the frequency of such testing that will be considered adequate. For example, testing the functionality of a system that is part of the work environment and used every day may be excessive, while a more extreme form of testing, such as simulated break-ins may be appropriately applied biennially or triennially. In addition, the CIP Reliability Standards should clarify what is considered readily accessible and what is not. Any testing requirements should consider the specific facilities being tested and allow entities to use their discretion until more experience is gained in this area. Finally, changes to the frequency of the maintenance and testing program cycles should be considered in the Reliability Standards development process.
579. National Grid argues that the testing of critical cyber assets (as opposed to testing of physical security measures for such critical cyber assets) is beyond the scope of the physical security requirements in Reliability Standard CIP-006-1. Thus, it requests that the Commission clarify that the CIP NOPR's reference to the testing of critical cyber assets was inadvertent, and that the Commission was merely proposing testing intervals for physical security measures.
580. Northern Indiana requests that the Final Rule clarify what is intended by a “test.” A test of a card access system, for example, can be the normal operation with the card and the operation with a non-programmed card to determine whether the lock is working. The protocol for physical security system tests are dictated more by the type of equipment to be tested as well as the equipment's application. Northern Indiana states that, like the Commission, it believes in a strong maintenance and testing program. However, Northern Indiana also believes the focus of the Final Rule should be on whether an unauthorized person accesses the physical security system, and not the administrative nature of testing the system. Clarification of what is intended by, or what makes up, an acceptable test will in effect strengthen the Requirement.
581. The Commission adopts the CIP NOPR proposal and directs the ERO to develop a modification to CIP-006-1 to require a responsible entity to test the physical security measures on critical cyber assets more frequently than every three years, but clarifies our direction in several respects. Similar to our action with respect to reviewing logs in CIP-005-1, the Commission will not adopt the proposal to require different testing periods for physical security measures on critical cyber assets that are readily accessible or not readily accessible. Instead, we leave it to the Reliability Standards development process to decide whether different timeframes are appropriate for physical security measures on critical cyber assets that are readily accessible and not readily accessible. Similar to our direction in CIP-005-1, if different review timeframes are adopted, the ERO should provide guidance as to what constitutes a readily accessible facility and a facility that is not readily accessible. The ERO may also delineate different timeframes for testing for other reasons, but must clearly define how to determine in what timeframe the physical security measures on a specific critical cyber asset must be reviewed.
582. In response to Northern Indiana, the Commission does not believe it is necessary at this time to specify what would constitute a test, because each test may be different based on the type of physical security measure employed. Northern Indiana may ask the ERO to provide guidance on this matter.
583. In response to National Grid, we clarify that the CIP NOPR's reference to the testing of critical cyber was inadvertent, and that we proposed testing intervals for physical security measures.
584. The Purpose statement in CIP-007-1 states that it requires responsible entities to define methods, processes and procedures for securing those systems determined to be critical cyber assets, as well as the non-critical cyber assets within the electronic security perimeter(s). This Reliability Standard deals primarily with changes made to the operating production systems and verification that such changes will not inadvertently have adverse effects.
585. The Commission approves Reliability Standard CIP-007-1 as mandatory and enforceable. In addition, we direct the ERO to develop modifications to this Reliability Standard. The required modifications are discussed below in the following topic areas of concern regarding CIP-007-1: (1) Acceptance of risk and technical feasibility; (2) test procedures; (3) malicious software prevention; (4) security status monitoring; (5) disposal or redeployment; (6) cyber vulnerability assessment; and (7) documentation review and maintenance.
586. In the CIP NOPR, the Commission expressed various concerns regarding acceptance of risk and technical feasibility language in CIP-007-1. For example, Requirement R2.3 allows a responsible entity to accept risk rather than take mitigating action where unused ports and services cannot be disabled due to “technical limitations” and Requirement R3.2 allows an acceptance of risk in lieu of mitigating risk exposure through a patching program. Requirement R4 requires the responsible entity to use antivirus software and malicious software prevention tools where technically feasible. Requirement R6 of CIP-007-1 requires responsible entities to ensure that all cyber assets within the electronic security perimeter, as technically feasible, implement automated tools or organizational process controls to monitor system events that are related to cyber security.
587. Requirement R3 of CIP-007-1 requires a responsible entity to establish and document a security patch management program for tracking, evaluating, testing and installing applicable cyber security software patches for all cyber assets within an electronic security perimeter. Among other things, a responsible entity must
588. The Commission proposed to direct the ERO to eliminate the acceptance of risk language from Requirement R3.2.
589. The Commission also proposed to direct the ERO to eliminate the acceptance of risk language from Requirement R2.3. At the same time, the Commission proposed to leave intact the exception for technical limitations in Requirement R2.3. However, the Commission stated that the technical limitations language of Requirement R2.3 raised the same concerns as raised concerning the technical feasibility language. While the Commission acknowledged that an exception for technical limitations might be appropriate, it stated that the language must include the same conditions as discussed in the context of technical feasibility. Accordingly, we proposed that the same conditions and reporting requirements should apply here. Thus, the Commission proposed to direct the ERO to revise Requirement R2 and its subparts to remove the acceptance of risk language and to impose the same conditions and reporting requirements here for “technical limitations” as imposed elsewhere in the CIP NOPR regarding “technical feasibility.”
590. The California Commission agrees with the proposal to remove the phrase “acceptance of risk” from the Reliability Standard. The California Commission also finds the existence of the term “technically feasible” in this Reliability Standard acceptable with the burden of proof on the individual organization to prove the exception. MidAmerican supports the Commission's proposal to eliminate acceptance of risk from Requirement R2.3 and that exceptions for technical limitation may be appropriate but must be treated as an exception the same as technical feasibility issues. However, MidAmerican cautions that the terms “technical limitations” and “technical feasibility” need clarification to facilitate compliance.
591. Juniper maintains that it is not technically feasible to turn off ports. It states that, if a device cannot turn off unused ports, it must be protected with a firewall in front of it. Unused open ports are the most common form of attack since devices can fail in unplanned ways when they receive unexpected traffic. Ideally, device providers must be mandated to provide the list of ports they require to be opened, with a description of the protocol expected on each open port.
592. Commenters also raise concerns about the Commission's treatment of security patches. According to APPA/LPPC, the Commission's proposal to eliminate the acceptance of risk language from CIP-007-1, Requirement R3.2 would appear to prevent responsible entities from exercising any discretion to determine not to implement a security patch on the ground that it posed more risk than justified. Limiting the use of acceptance of risk to instances where adoption of a specific compliance measure is determined by the responsible entity to pose more risk than alternative compliance measures, is appropriate, but eliminating all discretion in this area undermines necessary flexibility. In the alternative, APPA/LPPC argue that the Commission should give responsible entities the discretion to determine whether specific security patches create more vulnerability to the Bulk Power System than they solve. In this regard, APPA/LPPC note that the Commission itself stated in the CIP NOPR that the most up-to-date patches should be used, provided this does not “degrade the system and the patch does not create more vulnerability than the problem it is intended to fix.” Thus, APPA/LPPC argue that, if the Commission proceeds to delete the acceptance of risk language, it should specifically include the disclaimer on patches referenced above.
593. MidAmerican opposes the Commission's proposal to direct NERC to revise the Reliability Standard to remove acceptance of risk from the provisions for security patch management in Requirement R3. MidAmerican believes that the acceptance of risk should remain in the Reliability Standard if accompanied by a mitigation plan and sunset provisions for the exception. By requiring a mitigation plan to reduce the risk and a time frame to come into compliance the standard provides needed flexibility while maintaining the certainty of a committed end-date.
594. Northern Indiana does not support the Commission's proposal that senior management be involved in each and every case because it is not necessary. The Commission should refine its proposal and provide that senior management should be consulted when mitigation is needed, but not in situations not requiring mitigation. Such situations can be appropriately addressed by senior management's delegate.
595. FPL Group states that, the Commission's statement that patch management must be weighed in light of the risks involved, with senior management involved in the decision, acknowledges that a certain level of risk associated with patch management must be taken into account. However, FPL Group states that this analysis is no different than the acceptance of risk language that the Commission rejects. The Commission is essentially stating that by using technical judgment, a responsible entity's senior management can accept the risk associated with not applying security patches in instances where the patches would degrade performance after performing a risk assessment. Therefore, FPL Group recommends directing the ERO Reliability Standards development process to consider the issue related to acceptance of risk and make appropriate modifications, if any, to the Reliability Standards.
596. Juniper states that an inline intrusion prevention system or intrusion detection system that is able to automatically identify and understand the protocols being used on a control network provides a mitigation for conditions where applying patches against known vulnerabilities is not feasible. Hence, in locations where patches cannot be applied such a network device must be required.
597. The Commission affirms its proposals with respect to technical feasibility and acceptance of risk. Therefore, the Commission directs the ERO to eliminate the acceptance of risk language from Requirements R2.3 and R3.2. However, as discussed in the CIP NOPR, this leaves intact the exception for technical limitations in Requirement R2.3, so long as the treatment of Requirement R2.3 conforms to our findings regarding the technical feasibility exceptions.
598. MidAmerican's concerns about clarifying the terms technical limitations and technical feasibility through the Reliability Standards development process are addressed in our findings regarding technical feasibility elsewhere in the Final Rule.
599. In response to Juniper, the Commission does not believe that applying the technical feasibility exception in lieu of acceptance of risk means that a responsible entity would not have to mitigate the risk of not being able to turn off ports. The Commission believes that our discussion of the technical feasibility exception in the Technical Feasibility Exception Remediation and Mitigation section above supplies the obligation to mitigate that Juniper is seeking.
600. With respect to security patch management, the Commission continues to believe that the acceptance of risk language is unacceptable. However, in doing so we do not seek to prevent responsible entities from exercising some level of discretion. The Commission therefore directs the ERO to revise Requirement R3 to remove the acceptance of risk language and to impose the same conditions and reporting requirements as imposed elsewhere in the Final Rule regarding technical feasibility. The Commission believes that this will allow responsible entities the discretion APPA/LPPC seek. Further, this essentially accomplishes the outcome sought by MidAmerican. With respect to the disclaimer requested by APPA/LPPC, the Commission is not convinced to direct such a modification to the Reliability Standard at this time. However, this issue should be examined in the Reliability Standards development process. Given that we are modifying our direction, we do not believe that it is necessary to mandate senior management involvement in these decisions here. While we direct the ERO to modify Requirement R3 of CIP-007-1 to remove the acceptance of risk language, the ERO, through the Reliability Standards development process may choose to allow exceptions to this requirement for technical infeasibility, consistent with the Commission's determination on technical feasibility above. However, the responsible entity should implement the requirements for software patches for all cyber assets within an electronic security perimeter or justify why it is not doing so pursuant to our discussion of technical feasibility exceptions.
601. Requirement R1 of CIP-007-1 requires a responsible entity to ensure that new cyber assets and significant changes to existing cyber assets within the electronic security perimeter do not adversely affect existing cyber security controls. Responsible entities must create, implement, and maintain cyber security test procedures in a manner that minimizes adverse effects on the production system and its operation. They must document that testing is performed in a manner that reflects the production environment and must document test results.
602. The CIP Assessment suggested that Requirement R1.2 should require the responsible entity to document how each significant difference between the production and testing environments is considered and addressed.
603. In the CIP NOPR, the Commission stated that, if a testing environment does not accurately reflect the production environment, testing of systems may not be adequate to judge impacts on reliability. While, ideally, testing should be conducted on a precise duplicate of the production system, the Commission acknowledged that this is not always possible. When it is not, any differences between the test environment and the production system should be documented. Therefore, the Commission proposed to direct the ERO to modify Requirement R1 and its subparts to require documentation of each significant difference between the testing and the production environments, and how each such difference is mitigated or otherwise addressed.
604. FirstEnergy argues that, while it is reasonable for the Commission to require documentation of significant differences between the testing and production environments, the Commission should clarify that it is not expecting that the differences themselves would be mitigated in the test—other than to simply get the test environment as close as possible to the production environment. The Commission should ensure that the documentation required to document the differences will not be burdensome.
605. MidAmerican supports the proposal to document differences between the testing and production environments, but suggests that these differences not be reported for every test version, but only when the production and test environments are established.
606. Northern Indiana maintains that the existence of any significant difference means the test will not reflect the production environment, which would violate Requirement R1.3. Further, Northern Indiana maintains that differences in testing and production environments may be difficult to eliminate or to mitigate. In a simulated test, differences will exist. Northern Indiana maintains that small differences should not require mitigation.
607. Northern Indiana argues that documenting vulnerability test results or the existence of any mitigation or remediation plans would reveal any vulnerability on its system. Tampa Electric contends that this would produce an unnecessary administrative burden. It explains that there are instances when the production system is too large and complex to practically reproduce in a test environment. In this circumstance, according to Tampa Electric, documenting every detail would expend additional resources without producing useful information.
608. ISO-NE and Northern Indiana ask for clarification of the term “significant difference” in the CIP-007-1 proposal. ISO-NE states that the term significant difference is highly subjective and potentially burdensome without actually enhancing an entity's security posture.
609. The Commission has discussed issues related to testing environments in CIP-005-1.
610. Consistent with our action in CIP-005-1, the Commission will not at this time require documentation of each difference between the testing and the production environments and how each such difference is mitigated or otherwise addressed. In using the term mitigation, our goal was to ensure that each responsible entity understands the
611. With respect to MidAmerican's proposal that the differences between the testing and production environments only be reported when the production and test environments are established, the ERO should consider this matter in the Reliability Standards development process. However, the Commission cautions that certain changes to a production or test environment might make the differences between the two greater and directs the ERO to take this into account when developing guidance on when to require updated documentation to ensure that there are no significant gaps between what is tested and what is in production.
612. The Commission understands Northern Indiana's concern that documenting vulnerability test results or any mitigation or remediation plans may reveal system vulnerabilities. The ERO should alleviate this concern by providing for such reports to be reviewed under the confidentiality provisions of its Rules of Procedure.
613. Requirement R4 of CIP-007-1 requires responsible entities to use antivirus and other malicious software prevention tools where technically feasible, and allowing an acceptance of risk option. The Requirement and its subparts do not provide direction on how to implement this type of protection, where it should be deployed, or what care must be taken to implement and test malicious code protection in order to avoid harm to the production system.
614. The Commission proposed to direct the ERO to eliminate the acceptance of risk language from Requirement R4.2, and also attach the same documentation and reporting requirements to the use of technical feasibility in Requirement R4, pertaining to malicious software prevention, as elsewhere. The Commission discussed the issues of defense in depth, technical feasibility, and risk acceptance elsewhere in the CIP NOPR and applied those conclusions here. The Commission further proposed to direct the ERO to modify Requirement R4 to include safeguards against personnel introducing, either maliciously or unintentionally, viruses or malicious software into a cyber asset within the electronic security perimeter through remote access, electronic media, or other means.
615. Consumers argues that requiring antivirus software on every system in the electronic security perimeter that uses a routable protocol would not be warranted. In Consumers' view, requiring such software on a blanket basis would itself lead to reliability problems. Thus, Consumers argues that only those systems that are vulnerable to this type of threat should require protection under this guideline.
616. In this regard, Consumers argues that many operating systems, like the UNIX operating server systems, switches and bridges, may be critical cyber assets. But they are not directly vulnerable to virus attacks and need not be protected by antivirus applications. In corporate environments, UNIX servers do require antivirus and malware protection, since they use hyper text transfer protocol and e-mail services which can make them infected carriers. However, there are no instances in control system environments requiring any such protection.
617. Consumers concedes that network infrastructure devices that are not directly targeted can be affected as collateral damage. But, it argues, some of the critical cyber assets do not have any mechanism for antivirus installation. Finally, Consumers argues that the Commission should promote the idea of perimeter defense, using firewall based content vulnerability security devices to protect the control systems' electronic security perimeter rather than application of antivirus software to every critical cyber asset.
618. MidAmerican asks the Commission to clarify the intent of the proposal that Requirement R4 be modified to include safeguards against personnel introducing, maliciously or unintentionally, viruses or malicious software to a cyber asset. Northern Indiana believes that systems and protections are in place to prevent unintentional actions affecting a cyber asset. It states that there are no safeguards that protect against all malicious or unintentional acts. Juniper recommends that network-based antivirus and intrusion prevention devices be mentioned as minimum requirement for such safeguards against unintentional introduction of malware by authorized personnel.
619. The Commission adopts the CIP NOPR proposal with regard to CIP-007-1, Requirement R4. Issues concerning technical feasibility and acceptance of risk are discussed above.
620. The Commission will not adopt Consumers' recommendation that every system in an electronic security perimeter does not need antivirus software. Critical cyber assets must be protected, regardless of the operating system being used. Consumers has not provided convincing evidence that any specific operating system is not directly vulnerable to virus attacks. Virus technology changes every day. Therefore we believe it is in the public interest to protect all cyber assets within an electronic security perimeter, regardless of the operating system being used. Further, as Consumers admits, any network infrastructure devices that are not directly targeted can be affected as collateral damage.
621. While we agree that no safeguard will protect against all malicious or unintentional acts, this does not mean that systems should not be protected against such acts. In response to MidAmerican, the Commission believes that details regarding how to safeguard systems against personnel introducing, maliciously or unintentionally, viruses or malicious software to a cyber asset are best developed in the Reliability Standards development process. The revised Reliability Standard does not need to prescribe a single method for protecting against the introduction of viruses or malicious software to a cyber asset by personnel. However, how a responsible entity does this should be detailed in its cyber security policy so that it can be audited for compliance with the Reliability Standard. The Reliability Standards development process should decide the degree to which the revised CIP-007-1 describes how an entity should protect against personnel introducing viruses or malicious software to a cyber asset. The ERO could also provide additional guidance in a reference document.
622. Therefore, the Commission directs the ERO to eliminate the acceptance of risk language from Requirement R4.2, and also attach the same documentation and reporting requirements to the use of technical feasibility in Requirement R4, pertaining to malicious software prevention, as elsewhere. The Commission also directs the ERO to modify Requirement R4 to include safeguards against personnel introducing, either maliciously or unintentionally, viruses or malicious software to a cyber asset within the electronic security perimeter through remote access, electronic media, or other means, consistent with our discussion above.
623. Requirement R6 of CIP-007-1 requires responsible entities to ensure that all cyber assets within the electronic security perimeter, as technically feasible, implement automated tools or organizational process controls to monitor system events that are related to cyber security. Among other things, a responsible entity must maintain logs of system events related to cyber security, where technically feasible, to support incident response as required in Reliability Standard CIP-008-1. Logs must be retained for 90 calendar days, and the responsible entity must review logs of system events related to cyber security and maintain records documenting review of logs.
624. In the CIP NOPR, the Commission stated that logs should be reviewed with the frequency necessary to ensure timely identification of a cyber security incident. We noted that this issue of log review touches on Blackout Report Recommendation 35, which addresses network monitoring, and Recommendation 37 which addresses diagnostic capabilities.
625. The Commission also proposed to direct the ERO to revise Requirement R6.4 to clarify that while the retention period for all logs specified in Requirement R6 is 90 days, the retention period for logs mentioned in Requirement R6.3 for the support of incident response as required in CIP-008-1 is the retention period required by CIP-008-1,
626. Similar to the concerns raised with regard to the log review requirement in CIP-005-1, commenters generally oppose the Commission's proposal to include a requirement that logs be reviewed on a weekly basis for readily accessible critical assets and reviewed within the retention period for assets that are not readily accessible. Northern Indiana, FPL Group, Idaho Power, MidAmerican, Entergy and SPP raise the same concerns as they did with respect to CIP-005-1. MidAmerican and Northern Indiana request clarification of the term “readily accessible” to facilitate compliance. Northern Indiana also requests clarification of what is meant by the reference to forensics and how data would be used in forensic investigations.
627. Juniper argues that it is crucial that logs be maintained for at least three years to allow analysis to detect behavioral anomalies and perform forensics in case of a successful attack. It argues that any device that is network enabled in the broadest sense must be considered readily accessible, and its logs ought to be checked at least daily.
628. Requirement R6 of CIP-007-1 does not address the frequency with which logs should be reviewed. Requirement R6.4 requires logs to be retained for 90 calendar days. This allows a situation where logs would only be reviewed 90 days after they are created. The Commission continues to believe that, in general, logs should be reviewed at least weekly and therefore adopts the CIP NOPR proposal to require the ERO to modify CIP-007-1 to require logs to be reviewed more frequently than 90 days, but leaves it to the Reliability Standards development process to determine the appropriate frequency, given our clarification below, similar to our action with respect to CIP-005-1.
629. For the reasons discussed in CIP-005-1, in directing manual log review, the Commission does not require that every log be reviewed in its entirety. Instead, the Commission will allow a manual review of a sampling of log entries or sorted or filtered logs. The Commission recognizes that how a responsible entity determines what sample to review may not be the same for all locations. Therefore, the revised Reliability Standard does not need to prescribe a single method for producing the log sampling. However, how a responsible entity performs this sample review should be detailed in its cyber security policy so that it can be audited to determine compliance with the Reliability Standards. The Reliability Standards development process should decide the degree to which the revised CIP-007-1 describes acceptable log sampling. The ERO could also provide additional guidance on how to create the sampling of log entries, which could be in a reference document. The final review process, however, must be rigorous enough to enable the entity to detect intrusions by attackers.
630. In response to Northern Indiana, the Commission discusses our use of the term forensics in our discussion of CIP-009-1.
631. Requirement R7 of CIP-007-1 requires the responsible entity to establish formal methods, processes and procedures for disposal or redeployment of cyber assets. In the CIP NOPR, the Commission addressed the concern that solely to “erase the data,” as stated several times in Requirement R7, may not be adequate because technology exists that allows retrieval of “erased” data from storage devices, and that effective protection requires discarded or redeployed assets to undergo high
632. Northern Indiana states that the CIP NOPR is unclear what needs to be clarified in Requirement R7. Northern Indiana believes the only way to allow “no opportunity” to access data on storage media is to destroy the media. Northern Indiana states that it takes costly measures to erase data storage tapes and other storage media and follows the requirements of the United States Department of Defense, performing a seven-layer wipe of its storage media. Northern Indiana maintains that, if the clarification sought by the Commission is intended to direct NERC to be more prescriptive about erasure, Northern Indiana states that its cost of compliance will rise because failed disk devices could no longer be returned to manufacturers for replacement without destruction of the drive. Manufacturer warranties will no longer be effective after the storage media is destroyed. Requirement R7 as written is sufficiently broad and can apply to numerous media types. In addition, adherence to Department of Defense requirements should be adequate.
633. The Commission adopts the CIP NOPR proposal to direct the ERO to clarify what it means to prevent unauthorized retrieval of data from a cyber asset prior to discarding it or redeploying it. The Commission notes that there is a difference between redeploying an asset and discarding it. Redeploying an asset within the same responsible entity allows that responsible entity to maintain control over the asset, whereas disposing of an asset places it out of the control of the responsible entity. The Commission believes that, while the seven layer wipe described by Northern Indiana may be sufficient for redeployment because the responsible entity maintains control over the cyber asset, it is not sufficient for disposing of an asset.
634. The Commission disagrees with Northern Indiana that the only way to allow no opportunity to access data on storage media is to destroy the media. As stated in the CIP NOPR, high quality degaussing can adequately protect media from unauthorized access. Northern Indiana has not provided information that convinces the Commission that a cyber asset would have to be destroyed in order to prevent access.
635. Therefore, the Commission directs the ERO to revise Requirement R7 of CIP-007-1 to clarify, consistent with this discussion, what it means to prevent unauthorized retrieval of data.
636. Requirement R8 of CIP-007-1 requires a responsible entity to perform a cyber vulnerability assessment of all cyber assets within the electronic security perimeter at least annually. Requirement R8.4 requires development of an action plan to remediate or mitigate vulnerabilities identified in the assessment, but it does not provide a timeframe for completion of the action plan.
637. In the CIP NOPR, the Commission stated its belief that vulnerability testing is a valuable tool in determining whether actions that were taken to shore up the security posture of the electronic security perimeter and other areas of responsibility are in fact adequate.
638. MidAmerican supports the proposal to require the ERO to provide additional direction surrounding the vulnerability assessments conducted by the responsible entities, and to revise Requirement R8.4 to require an entity-imposed timeline for completion of an action plan, for the reasons articulated in the CIP NOPR.
639. ISO-NE proposes that the Final Rule omit the Commission's proposal because, given the diversity of hardware and software implementation throughout the industry, providing more meaningful direction on “features, functionality, and vulnerabilities” is not feasible. In the view of ISO-NE, no Reliability Standard can evolve fast enough to keep-up with emerging and diverse technologies and newly discovered vulnerabilities. Therefore, ISO-NE requests that the Commission omit this proposal from the Final Rule.
640. FPL Group and NRECA raise the same concerns about cyber vulnerability assessments as they did under CIP-005-1. Further, FPL Group states that, while specific directions may be appropriate with regard to certain Reliability Standards, the intent of this Reliability Standard is to determine whether there are vulnerabilities with regard to a specific system. In FPL Group's view, overly rigid guidance or requirements by the ERO could result in responsible entities failing to properly test for vulnerabilities specific to the entities' environments and systems, thus undermining the intent of the Reliability Standard.
641. SDG&E agrees that a vulnerability assessment should look for and prioritize specific types of vulnerabilities, and provides specific suggestions on such prioritization.
642. Northern Indiana states that the responsible entity should maintain the makeup and depth of any vulnerability or penetration tests it undertakes, and control the associated mitigation timeline it establishes to address the results of the tests. Northern Indiana
643. The Commission adopts its proposal to direct the ERO to provide more direction on what features, functionality, and vulnerabilities the responsible entities should address when conducting the vulnerability assessments, and to revise Requirement R8.4 to require an entity-imposed timeline for completion of the already-required action plan.
644. The Commission agrees with ISO-NE that hardware and software is implemented in diverse ways throughout the industry, but does not believe that this renders providing guidance infeasible. We also agree that overly rigid guidance could result in responsible entities failing to properly test for vulnerabilities specific to the entities' environments and systems. The Commission does not believe that the revised Reliability Standard should be inflexible. It should encourage responsible entities to take into account emerging and diverse technologies and newly discovered vulnerabilities as they emerge. The Commission believes that it is appropriate to leave such guidance to the Reliability Standards development process. Further, we leave it to the ERO's discretion whether to put guidance in the revised Reliability Standard or a reference document.
645. The Commission addressed Northern Indiana's concerns about revealing vulnerability test results in our discussion of CIP-005-1. We believe that the ERO's confidentiality provisions should adequately protect against unwanted disclosure of vulnerability test results.
646. Requirement R9 of CIP-007-1 requires the responsible entity to review, update and maintain all documentation needed to support compliance with the Requirements of CIP-007-1 at least annually. Changes resulting from modifications to the systems or controls must be documented within 90 calendar days of the change.
647. The Commission addressed concerns that the 90-day timeframe for updating documentation appears excessively long, especially given the context that this Reliability Standard establishes a significant line of defense for protecting critical cyber assets and that up-to-date documentation is essential in case of an emergency. The Commission proposed to direct the ERO to modify Requirement R9 to state that the changes resulting from modifications to the system or controls shall be documented within a 30-day time period. We stated our belief that the planning and engineering of system and control modifications require sufficient lead time to enable the documentation of such modifications to take place within a 30-calendar-day timeframe.
648. Northern Indiana, Mr. Brown and MidAmerican object to shortening the time allowed for documentation of modifications to the system or controls from 90 to 30 days. Northern Indiana argues that a 90-day period provides flexibility in finalizing such documentation given the nature and type of facilities and their locations, particularly in light of the potential need for internal reviews and approvals by a number of people or groups of people before a documentation change can be effected. MidAmerican agrees that the proposed time line for required documentation may not be sufficient in all instances, particularly for remote locations that are relatively resource constrained.
649. Mr. Brown objects to the proposal to reduce the filing period from 90 to 30 days for documenting changes resulting from modifications to the system or controls. He argues that, in many organizations that will be impossible, or at least extremely costly in staff time. He argues that this will simply lead to unnecessary, trivial instances of technical noncompliance. Thus, Mr. Brown argues that, while 90 days may be too long, a more appropriate, practical and achievable period would be 60 days.
650. ISO-NE and SDG&E ask when the 30-day period begins. They request that the Final Rule direct the ERO to clarify for both CIP-007-1 and CIP-009-1 that changes resulting from modifications to the systems, controls, and procedures shall be documented within 30 days of final implementation of the modifications. Juniper agrees that the 30-day period should begin after the modifications are in place, i.e., accepted, tested, in production and running.
651. The Commission adopts a modified version of the CIP NOPR proposal. We direct the ERO to revise Requirement R9 to state that the changes resulting from modifications to the system or controls shall be documented quicker than 90 calendar days. The Commission believes that 30 days should provide sufficient time to update any necessary documentation with exceptions granted by the Regional Entity for extraordinary circumstances. The Commission believes that having correct documentation of methods, processes and procedures for securing a responsible entity's system is necessary because if an event occurred before documentation was updated, an operator may not know of a change and could operate the system using out of date information. This puts reliability at risk by not informing operators of a method, process or procedure to secure the system against a known risk. Therefore, the Commission believes that 90 days is too long to allow a responsible entity to have incorrect documentation. Thirty days should be sufficient time to update any necessary documentation.
652. The Commission clarifies that the shorter period should begin upon final implementation of the modifications. The Commission believes that providing that the shorter period begins when the modifications are implemented satisfies Northern Indiana's concern about finalizing documentation and the potential need for internal reviews and approvals. By the time any modification is made, such approvals should already have been granted. Similarly, the Commission believes that MidAmerican's concern about resource constraints relate more to the implementation of a modification, not the documentation of that implementation. Once a modification is developed and implemented, documenting it should not consume significant time or resources.
653. Proposed Reliability Standard CIP-008-1 requires a responsible entity to identify, classify, respond to, and report cyber security incidents related to critical cyber assets. Specifically, Requirement R1 of CIP-008-1 requires responsible entities to develop and maintain an incident response plan that addresses responses to a cyber security incident. The plan should characterize and classify pertinent events as reportable cyber security incidents and provide corresponding response actions. The response actions should include: (1) The roles and responsibilities of the incident response teams; (2) procedures for handling incidents; and (3) associated communication plans. In addition, cyber security incidents must be reported to the Electricity Sector Information Sharing and Analysis
654. The Commission approves Reliability Standard CIP-008-1 as mandatory and enforceable. In addition, we direct the ERO to develop modifications to this Reliability Standard. The required modifications are discussed below in the following topic areas of concern regarding CIP-008-1: (1) Definition of a reportable incident; (2) reporting; and (3) full operational exercises and lessons learned.
655. Requirement R1 of CIP-008-1 makes reference to reportable cyber security incidents, but it does not provide a definition of a “reportable incident.”
656. In the CIP NOPR, the Commission recognized the risk that cyber security incidents may go unreported depending upon a responsible entity's interpretation of a reportable incident.
657. FirstEnergy, MidAmerican, Northern Indiana, ReliabilityFirst and SPP support the Commission's proposal that the ERO should provide guidance on the definition of reportable incident. Each also provides the Commission with input on how the term should be defined.
658. ReliabilityFirst and SPP recommend that NERC, as the operator of the ESISAC, be directed to publish the reporting criteria and thresholds separately from the CIP Reliability Standards and to provide appropriate reporting mechanisms for that purpose. They maintain that this approach would allow the ERO to maintain maximum flexibility in times of emergency. They state that Reliability Standard CIP-008-1 should then be modified to require entities to report incidents, both physical and cyber, that meet the criteria published by the ESISAC. For audit purposes, both SPP and ReliabilityFirst maintain that NERC should be required to maintain a three-year minimum change history for the published criteria and demonstrate that changes to the criteria were proactively announced and disseminated to all entities in a timely manner. By placing the reporting criteria in the CIP Reliability Standard itself, any changes would have to undergo the defined, lengthy Reliability Standards revision process and could impact the timely collection of information essential to the protection of the North America's critical infrastructure.
659. MidAmerican supports the proposal to further define and clarify the definition and reporting requirements for an incident and including a breach that may occur through cyber or physical means in an incident report, when the breach meets the other requirements outlined for an electronic incident. FirstEnergy states that the Commission should require reportable incident to be defined as an incident report for a security breach that may occur through physical means. According to FirstEnergy, a reportable incident determination should consider the totality of circumstances surrounding a physical breach.
660. The Commission adopts the CIP NOPR proposal to direct the ERO to provide guidance regarding what should be included in the term reportable incident. In developing the guidance, the ERO should consider the specific examples provided by commenters, described above. However, we direct the ERO to develop and provide guidance on the term reportable incident. The Commission is not opposed to the suggestion that the ERO create a reference document containing the reporting criteria and thresholds and requiring responsible entities to comply with the reference document in the revised Reliability Standard CIP-008-1, but will allow the ERO to determine the best method to accomplish the goal of better defining reportable incident.
661. Therefore, the Commission directs the ERO to develop a modification to CIP-008-1 to: (1) Include language that takes into account a breach that may occur through cyber or physical means; (2) harmonize, but not necessarily limit, the meaning of the term reportable incident with other reporting mechanisms, such as DOE Form OE 417; (3) recognize that the term should not be triggered by ineffectual and untargeted attacks that proliferate on the internet; and (4) ensure that the guidance language that is developed results in a Reliability Standard that can be audited and enforced.
662. CIP-008-1, Requirement R1.3, requires each responsible entity to establish a process for reporting cyber security incidents to the ESISAC. The responsible entity must ensure that all reportable cyber security incidents are reported to the ESISAC either directly or through an intermediary. ESISAC procedures require the reporting of a cyber incident within one hour of a suspected malicious incident. However, compliance with ESISAC's Indications, Analysis and Warnings Program Standard Operating Procedure is voluntary.
663. In the CIP NOPR, the Commission addressed concerns regarding the importance of responsible
664. The Commission proposed to direct the ERO to modify CIP-008-1 to require each responsible entity to contact appropriate government authorities and industry participants in the event of a cyber security incident as soon as possible, but, in any event, within one hour of the event, even if it is a preliminary report. We left development of the details to the ERO, but stated our view that the reporting timeframe should run from the discovery of the incident by the responsible entity, and not the occurrence of the incident.
665. The Texas PUC states that the Commission's proposal for a one-hour reporting limit is reasonable if there is a uniform reporting form. The Texas PUC states that, if a cyber security attack affects several facilities, the one-hour reporting requirement would provide necessary information to other responsible entities that would allow them to take precautionary measures to protect their systems. Further, a uniform reporting form could be easily submitted to multiple agencies.
666. FirstEnergy maintains that it would be appropriate to include the one-hour time frame for reporting cyber security incidents, but the Reliability Standard should specify that the one-hour time period applies from the time of the discovery of the event, which may include at least a preliminary investigation of the incident by the reporting entity. SDG&E asks for clarification that the one-hour time frame would commence when the responsible entity is made aware of the event, which could be later than actual occurrence.
667. Northern California supports the Commission's recommendation that NERC modify Requirement R1.3 of CIP-008-1 to include a requirement that a cyber security incident be reported after the discovery of the incident. However, both NRECA and ReliabilityFirst state that the appropriate time for response should be addressed through the Reliability Standard development process.
668. In contrast, Entergy, MidAmerican and Northern Indiana object to the one-hour reporting limit. Given the potential penalties involved for non-compliance, Entergy argues that the Commission should require reporting within one hour of discovery of the incident, whether or not the reason or cause is known, unless system restoration takes priority to ensure reliability. If system restoration is a priority, reporting should be performed within four to eight hours depending on the measures required for system restoration. Northern California agrees that the reporting requirement should contain exceptions to ensure entities that are focused on recovery are not punished. According to Northern California, these exceptions should be more than technical feasibility and should allow for the fact that, in a crisis, human beings tend to focus on solving the crisis.
669. Entergy asks the ERO to clarify the relationship between CIP-001-1, which requires the reporting of sabotage events, and CIP-008-1, which requires the reporting of cyber security incidents. Entergy notes that many responsible entities will be required to report an actual or suspected cyber or communication attack that causes major interruptions of electrical systems events to the U.S. Department of Energy on DOE Form OE 417. This report must be submitted within one hour after discovery of an actual attack or six hours after a suspected attack. It is not clear why this report, which may satisfy certain CIP-001-1 requirements, would be submitted under a different timeline than any report required under CIP-008-1. Entergy believes that reporting for cyber security incidents should be coordinated as much as possible. Entergy suggests consideration of consolidating the requirements of CIP-001-1 and CIP-008-1.
670. MidAmerican disagrees with the Commission's contention that a one-hour notification from discovery provides such probative value as to justify the burden involved. On the contrary, MidAmerican submits the more likely result will be to cause far too many false positives from preliminary reports. MidAmerican recommends that the Commission strike a more balanced approach—either extend the window to six to twelve hours from discovery or make it one hour from when it is classified.
671. The California Commission maintains that the term appropriate government authorities should specify the exact authorities in each state. For example, it states that in California, power plants are subject to California Commission jurisdiction. Accordingly, California Commission argues that, for California, the term appropriate government authority should include the California Commission. Similarly, the Texas PUC states that, in Texas, the reports should be sent to NERC, the Texas PUC, the Texas Regional Entity and ERCOT. According to Texas PUC, this would not be unduly burdensome because only minimal changes would be needed to existing cyber security plans.
672. FirstEnergy agrees that there is a need for uniformity for reporting and sharing of physical and cyber security incident information. In this regard, FirstEnergy argues that NERC should adopt the DOE reporting mechanism, DOE Form OE 417, rather than create a new mechanism. On this same topic, Applied Control Solutions comments that NIST, FIPS PUB 200, Minimum Security Requirements for Federal Information and Information Systems, should be used to make this report.
673. The Commission adopts the CIP NOPR proposal to direct the ERO to modify CIP-008-1 to require each responsible entity to contact appropriate government authorities and industry participants in the event of a cyber security incident as soon as possible, but, in any event, within one hour of the event, even if it is a preliminary report. As stated in the CIP NOPR, the reporting timeframe should run from the discovery of the incident by the responsible entity, and not the occurrence of the incident.
674. Most commenters are concerned with the burden placed on a responsible entity to report an incident when system restoration should take precedence. As stated in the CIP NOPR, while the Commission agrees that, in the aftermath of a cyber attack, restoring the system is the utmost priority, we do not believe that sending this short report would be a time consuming distraction, and we judge that its probative value would justify the minimal time spent in making this report. In this respect, the Commission now clarifies that the responsible entity does not need to initially send a full report of the incident. Rather, to report to appropriate government authorities and industry participants within one hour, it would be sufficient to simply communicate a preliminary report, including the time and nature of the incident and whatever
675. With respect to the arguments by California Commission and Texas PUC concerning the term appropriate government authorities, we believe this determination should be made through the Reliability Standards development process.
676. Thus, the Commission directs the ERO to modify CIP-008-1 to require a responsible entity to, at a minimum, notify the ESISAC and appropriate government authorities of a cyber security incident as soon as possible, but, in any event, within one hour of the event, even if it is a preliminary report. The Reliability Standard development process should consider whether the ESISAC could act as an intermediary to promptly notify government authorities for responsible entities. While we expect the modified Reliability Standard to be consistent with our discussion above, we leave development of the details of how to report incidents while not burdening the recovery process to the Reliability Standards development process.
677. With respect to Entergy's question about the relationship between CIP-001-1 and CIP-008-1, the ERO should consider Entergy's concerns in the Reliability Standards development process. However, the Commission notes that, while CIP-001-1 requires the reporting of sabotage events, CIP-008-1 requires the reporting of all cyber security incidents. Not all cyber security incidents will be caused by sabotage, so not all incidents required to be reported under CIP-008-1 will be required to be reported under CIP-001-1.
678. Requirement R1.5 of CIP-008-1 requires the responsible entity to maintain a process to ensure that the cyber security incident response plan is reviewed at least annually. Requirement R1.6 requires a process to ensure that the response plan is tested at least annually, and that such tests can range from a paper drill, a full operational exercise, or the response to an actual incident. CIP-008-1 does not require documentation or reassessment of a plan's adequacy as a result of lessons learned from testing or in response to specific issues.
679. In the CIP NOPR, the Commission addressed questions of whether the annual testing of the incident response plan should require full operational exercises due to the potential for such exercises to uncover unforeseen complications, and whether prospective benefits would balance attendant costs.
680. We recognized that annual testing may be costly and disruptive, but also that periodic operational drills are important because they may reveal weaknesses, vulnerabilities, and opportunity for improvement that a paper drill alone would not identify. The Commission stated its view that a full operational exercise should be performed at least once every three years, and that tabletop exercises are sufficient for the other two years, believing that this arrangement strikes an appropriate balance between the benefits of executing an operational exercise and the associated costs and potential risks of disruptions. Therefore, the Commission proposed to direct the ERO to revise the Reliability Standard to require responsible entities to perform a “full operational exercise” at least once every three years, or to fully document its reason for not conducting an exercise in full operational mode pursuant to the parameters used elsewhere for technical feasibility exceptions. Further, the Commission proposed to direct the ERO to provide guidance on the meaning of the term “full operational exercise.”
681. The Commission stated that industry will benefit from a requirement to document and implement lessons learned from testing or responses to actual cyber security incidents. While such information may be included in the “update” language of Requirement R1.4, we believe that CIP-008-1 would be improved by making a “lessons learned” requirement explicit. Therefore, the Commission proposed to direct the ERO to refine CIP-008-1, Requirement R2 to require responsible entities to maintain documentation of paper drills, full operational drills, and responses to actual incidents, all of which must include lessons learned. The Commission also proposed to direct the ERO to include language to require revisions to the incident response plan to address these lessons learned.
682. MidAmerican supports the Commission's change to a three-year testing cycle, as long as a full operational exercise doesn't require the asset be taken out of service. MidAmerican argues that the risk to reliability by performing a full operational exercise on a live system seems to outweigh the benefits. MidAmerican states that, while many EMS/SCADA systems are implemented with redundant failover systems that facilitate recovery exercises, this may not be the case for all equipment/systems at control centers, substations and/or plants. MidAmerican argues that taking equipment out of service during these exercises could result in an unexpected impact to reliability. MidAmerican also supports the proposal to refine the Reliability Standard to require complete documentation and a lessons learned section for the reasons articulated in the CIP NOPR.
683. Idaho Power requests that the Commission not include the proposed requirements for full operational exercises in the Final Rule. Idaho Power believes that testing should only be performed on a test platform. The risk to the reliable operation of the Bulk-Power System outweighs the perceived benefit of this type of testing. With adequate test plans, trained and qualified personnel, and a regimented change management process, Idaho Power believes adequate protection is in place without additional modifications to the standard.
684. Entergy also disagrees with the proposed requirement to perform a full operational cyber exercise involving operational systems. This is a formula for unnecessary risk to reliability of the control systems used to operate the grid. There is a wide and permuted range of potential incident types that would need to be simulated in a full exercise, and the response to different incidents can literally mean disconnecting control system elements from the network to which they are attached—while in production operation. This is perhaps the most challenging of all the CIP Reliability Standards to address in practice, and in the absence of a representative identical parallel test suite of equipment upon which to conduct the exercises, the reasonableness of such testing is questionable. Entergy believes that the industry should not be required to perform tests in a real time production command and control system—the potential risks outweigh the potential value.
685. SoCal Edison states that it conducts numerous operational tests and drills and requests clarification that drills conducted under CIP-008-1 can be coordinated with other operational tests currently in place.
686. The Commission adopts the CIP NOPR proposal to direct the ERO to
687. In light of the comments received, the Commission clarifies that, with respect to full operational testing under CIP-008-1, such testing need not require a responsible entity to remove any systems from service. The Commission understands that use of the term full operational exercise in this context can be confusing. We interpret the priority of the testing required by this provision to be that planned response actions are exercised in reference to a presumed or hypothetical incident contemplated by the cyber security response plan, and not necessarily that the presumed incident is performed on the live system. A responsible entity should assume a certain type of incident had occurred, and then ensure that its employees take what action would be required under the response plan, given the hypothetical incident. A responsible entity must ensure that it is properly identifying potential incidents as physical or cyber and contacting the appropriate government, law enforcement or industry authorities. CIP-008-1 should require a responsible entity to verify the list of entities that must be called pursuant to its cyber security incident response plan and that the contact numbers at those agencies are correct. The ERO should clarify this in the revised Reliability Standard and may use a term different than full operational exercise.
688. The purpose of proposed Reliability Standard CIP-009-1 is to ensure that recovery plans for critical cyber assets are in place and following established business continuity and disaster recovery techniques and practices. This Reliability Standard requires the development, updating, and testing of recovery plans, as well as storage and testing of associated backup data and backup media.
689. The Commission approves Reliability Standard CIP-009-1 as mandatory and enforceable. In addition, we direct the ERO to develop modifications to CIP-009-1 through the Reliability Standards development process. Further, the Commission also requires the ERO to consider various other matters of clarification, guidance, and modification. The required modifications are discussed below in the following topic areas of concern regarding CIP-009-1: (1) Recovery plans; (2) forensic data collection; (3) operational exercises; (4) updating recovery plans; (5) backup and storage of restoration data and (6) testing of backup media.
690. Requirement R1 of CIP-009-1 requires the responsible entity to create and annually review recovery plans for critical cyber assets. Requirement R1.1 requires specification of response to “events or conditions of varying duration and severity that would activate the recovery plan(s).”
691. In the CIP NOPR, the Commission recognized that the Requirement R1.1 language is very general and does not provide or require a definition of what constitutes a precipitating event or triggering condition necessary for recovery plan implementation. We stated our concern that precipitating events should be readily recognized by responsible entities so that recovery plans are promptly implemented, but declined to propose modifications of the events and conditions language at this time.
692. We also noted that Requirement R1 does not specifically require implementation of a recovery plan because it requires that recovery plans must be created and reviewed but does not explicitly require actual implementation when the events or conditions occur. The Commission proposed to direct the ERO to modify CIP-009-1 to include this requirement. We stated that, in the interim period, the Commission will infer that implementation is embodied in this Requirement when enforcing it, i.e., if an entity has the required recovery plan but does not implement it when the anticipated event or conditions occur, the entity will not be in compliance with this Reliability Standard.
693. MidAmerican supports the proposal to explicitly require the implementation of plans required in this Reliability Standard for the reasons articulated in the CIP NOPR. This issue also has arisen with regard to other Reliability Standards.
694. For the reasons discussed in the CIP NOPR, the Commission adopts the proposal to direct the ERO to modify CIP-009-1 to include a specific requirement to implement a recovery plan. We further adopt the proposal to enforce this Reliability Standard such that, if an entity has the required recovery plan but does not implement it when the anticipated event or conditions occur, the entity will not be in compliance with this Reliability Standard.
695. Requirement R1 of CIP-009-1, in requiring recovery plans, does not require the collection of forensics data and does not address how such collection activities relate to restoration of service efforts.
696. In the CIP NOPR, the Commission stated that concern for the reliability of the Bulk-Power System requires attention to forensics data collection, and noted that the Blackout Report also emphasized the need to improve forensics and diagnostic capabilities in Recommendation 37.
697. We acknowledged that recovery of critical cyber assets and the Bulk-Power System is of short-term critical importance, and information collection efforts should not impede or restrict system restoration, but emphasized that it is also important to long-term reliability interests that responsible entities make solid forensic efforts in a given situation, such as collecting the data immediately after system restoration or the recovery of critical cyber assets, if that is what can be done. We recognize that collecting forensic
698. NERC, SPP, ReliabilityFirst, Alliant, Arizona Public Service, Entergy, Idaho Power and Manitoba argue that the term forensics in other arenas conveys concepts of scientific rigor and chain of custody to assure that data are not tampered with in a legal proceeding. None of these are conducive to rapidly restoring service, or to maintaining or enhancing reliable operations of an already failed component. Thus, NERC, ReliabilityFirst and Idaho Power argue that this term should be removed from the Final Rule and replaced with the phrase “data collection for post-event analysis, where technically feasible.” Alliant agrees with NERC.
699. NERC believes that the Commission's intent would be better served through the development of a guideline concerning how data collection and analysis should be performed to determine causes of failures. NERC, the Commission and the responsible entities could then work together to engage control system vendors and manufacturers to develop and implement changes to their products to more readily allow the collection of high quality cyber event data, that can be used together with operational data to better understand the specific events which caused the outage or failure leading up to the need to invoke the incident response plan. NERC argues that the vendor community is in the best position to develop these toolsets, because, in most cases, both hardware and software modifications would be required to allow the rapid and efficient collection of quality data. Further, NERC argues that technical criteria will need to be developed to allow different manufacturers to generate such event log data in a common format for analysis. Equipment vendors need to be involved in these technical criteria and product development efforts, not the ERO-jurisdictional responsible entities. Idaho Power recommends that the ERO or Regional Entities develop and support work groups to address the latest technologies and methods to alleviate and address the Commission's concerns. Alliant agrees with NERC that these modifications should be effectuated through the Commission-approved Reliability Standards development process.
700. ISO-NE agrees in part with NERC's comments on the proposal to include a reference and requirements regarding the collection of forensic data. Further, forensic analysis is a skill used in the analysis of security incident data, the retention of which for three years is already addressed in CIP-008-1 for incident response. Also, ISO-NE states that CIP-005-1, CIP-006-1 and CIP-007-1 already require the retention of log data to support initial monitoring, analysis, and alerting of identified security incidents.
701. ISO-NE asserts that the broad-brush use of the term forensic data in the Blackout Report included all reliability incident data for post incident analysis. The scope is clear that these Reliability Standards are limited to cyber security incidents, and not all operational incidents impacting reliability. Therefore, ISO-NE believes the Reliability Standards already address this topic adequately, and it is therefore not appropriate to include in CIP-009-1. ISO-NE requests that any direction to the ERO regarding further collection of forensic data, or other operational reliability incident data, be omitted.
702. Entergy argues that forensic procedures can be quite complicated and situation dependent. Entergy argues that, if this CIP Reliability Standard is to be rewritten, it should be limited to the statement that “use of good forensic data collection practices should be employed.” Separate guidance could be included in ancillary advisory documents, such as those already available from NIST and various law enforcement authorities.
703. SoCal Edison and Northern Indiana are concerned that forensic data collection practices may hinder efforts to restore Bulk-Power System functionality. SoCal Edison believes that there may be impacts to restoration timeliness as well as additional personnel and hardware required if collection of forensics data are mandated.
704. NRECA believes that restoring service and reliability after an outage or other event must be the primary concern, and the need to preserve evidence should not compromise that objective. In some cases, both objectives can be achieved, and in other cases they cannot. Operating personnel should have the flexibility to make appropriate determinations as long as they can provide a reasonable explanation for their actions, without being exposed to penalties. In any event, it is difficult to reconcile the Commission's statutory authority to approve or remand Reliability Standards with a forensics requirement, which is not itself a Reliability Standard. The ERO, through its Reliability Standards development process, should be allowed to revisit the issue of what priority should be afforded to forensics without having a specific outcome dictated by the Commission.
705. MidAmerican suggests that the Commission substitute a reference to the National Institute of Justice's Forensic Data guideline, in lieu of the reference to “good forensic data collection.”
706. The Commission adopts, with clarification, the CIP NOPR proposal to direct the ERO to modify CIP-009-1 to incorporate use of good forensic data collection practices and procedures into this CIP Reliability Standard. The Commission continues to believe that it is important to long-term reliability interests that responsible entities collect data in certain situations, such as immediately after system restoration or the recovery of critical cyber assets. In response to ISO-NE, the Commission does not believe that the requirement to keep log data contained in other CIP Reliability Standards is sufficient. As we stated in the CIP NOPR, the data collection procedures could include preserving a corrupted drive, making a data mirror of the system before proceeding with recovery, or taking the important assessment steps necessary to avoid reintroducing the precipitating or corrupted data. None of this is required in the Reliability Standards cited by ISO-NE.
707. The Commission used the term forensic because that is the term used in the Blackout Report. However, the Commission clarifies that it does not intend, as suggested by commenters, that the Reliability Standard impose the extent of scientific rigor or chain of custody required in criminal procedure. Rather, the Commission is concerned with responsible entities preserving the
708. In response to Entergy, NRECA, SoCal Edison and Northern Indiana, recovery of critical cyber assets and the Bulk-Power System is of immediate critical importance, and information collection efforts should not impede or restrict system restoration, as stated in the CIP NOPR. We agree that preserving evidence should not hinder system restoration.
709. We do not object to the alternate proposal developed by the ERO, including use of the phrase “data collection for post-event analysis, where technically feasible,” to describe what should be required under the revised Reliability Standard. The ERO may also consider the methods proposed by Entergy and MidAmerican. We also recognize that collecting forensic data may not be technically feasible for all situations due to equipment limitations, such as older substation installations with little electronic monitoring. Therefore, when revising the Reliability Standard, the ERO may incorporate a technical feasibility exception, subject to the same conditions for exercising the exception as described elsewhere in this Final Rule.
710. Therefore, we direct the ERO to revise CIP-009-1 to require data collection, as provided in the Blackout Report. The modification should focus on responsible entities preserving the data necessary to determine the cause of any problem with the system and may include a technical feasibility exception.
711. Requirement R2 of CIP-009-1 requires the responsible entity to exercise recovery plans at least annually, and that such exercise can range from a paper drill, to a full operational exercise, or to recovery from an actual incident.
712. In the CIP NOPR, the Commission addressed the question of whether full operational exercises should be required to aid in identifying potential problems and to realize improvements, and concluded that some potential problems that could significantly impair reliability will not be found without them.
713. Accordingly, the Commission proposed to direct the ERO to develop modifications to CIP-009-1 to require a full operational exercise once every three years (unless an actual incident occurs), but to permit reliance on table-top exercises annually in other years. In conjunction, we proposed to direct the ERO to consider the appropriateness of a technical feasibility option, in the limited fashion proposed earlier.
714. The Commission noted the lack of clarity of the term full operational exercise and therefore also proposed to direct the ERO to either define in its glossary the term full operational exercise or provide more direction directly in the Reliability Standard as to the parameters of the term for use therein. We acknowledged that many operational exercise practices include table-top components in significant proportions.
715. With the changes included in the CIP NOPR, the California Commission and Texas PUC view this Reliability Standard as acceptable. Consistent with its comments regarding Standard CIP-008-1, MidAmerican supports the Commission's change to a three-year testing cycle, as long as a full operational exercise does not require the asset to be taken out of service.
716. NERC raises similar concerns with the Commission's use of full operational exercises to test recovery plans as it raised with respect to full operational exercises of electronic security perimeters in CIP-005-1.
717. NERC also argues that, when significant damage or failure occurs, responsible entities must take such action as necessary to ensure that their equipment meets the operational and cyber security requirements and expectations. It may not be possible to exactly replicate the damage or failure in a live operations context. NERC maintains that the phrase full operational exercises should be replaced by “demonstrated restoration of critical cyber assets in a test environment.” NERC goes on to explain that its comments on representative test environments in CIP-005-1 also apply here.
718. APPA/LPPC support the Commission's proposal. APPA/LPPC also agree with the Commission's determination that NERC should either define full operational exercise in its glossary or provide more direction directly in the Reliability Standard as to the parameters of the term.
719. APPA/LPPC, Arkansas Electric, Idaho Power, FPL Group, SPP and Consumers oppose including a live vulnerability test in a full operational exercise. APPA/LPPC state that, as noted by the Commission, the benefits of operational exercises must be weighed against the technical feasibility and operational risks of such exercises.
720. FirstEnergy also opposes full operational exercises, on the grounds
721. Northern Indiana requests clarification of what actual incident would excuse a full operational exercise. For instance, an incident (the nature of which may not be known) may occur that compels the responsible entity to stop the full operational exercise, which cannot be rescheduled for several months. The delay in operational testing should reset the clock such that the next paper drill of the tested system is performed one year from completion of the full operational exercise.
722. Idaho Power also argues that, with adequate test plans, trained and qualified personnel, and a regimented change management process, adequate protection is in place without additional changes to the Reliability Standard. ISO-NE asserts that clarification is needed of what constitutes a full operational exercise. ISO-NE thus supports the CIP NOPR's directive to direct the ERO to provide greater clarity as to the meaning of this term. As to whether to provide a definition of full operational exercise in the NERC Glossary, it needs to be understood that what may qualify as such an exercise with regards to readiness of Bulk-Power System operations would be somewhat different from such an exercise with respect to a cyber security incident response plan, or for IT back-up and recovery plans. Therefore, ISO-NE reserves further judgment of requirements for full operational exercises until additional clarity is provided.
723. Arkansas Electric opposes full operational exercises and suggests requiring a “functional exercise” be performed at least every three years. Arkansas Electric states that functional exercises are well defined in the emergency management and disaster recovery disciplines. Arkansas Electric notes that the National Incident Management System defines a functional exercise as one that “simulates the reality of operations in a functional area by presenting complex and realistic problems that require rapid and effective responses by trained personnel in a highly stressful environment.” Arkansas Electric argues that these exercises are more rigorous than tabletop exercises, yet they do not require the same system disruption as a full scale exercise.
724. Texas PUC maintains that the Commission's proposal to allow some entities to conduct partially operational exercises every three years appropriately recognizes the constraints faced by some entities. However, it states that this exception should not excuse entities from conducting more complex drills.
725. The Commission adopts, with modifications, the CIP NOPR proposal to develop modifications to CIP-009-1 through the Reliability Standards development process to require an operational exercise once every three years (unless an actual incident occurs, in which case it may suffice), but to permit reliance on table-top exercises annually in other years. Consistent with our goals and discussion of CIP-005-1, the Commission will not at this time require responsible entities to perform full operational exercises. Instead, the Reliability Standard should require the demonstrated recovery of critical cyber assets in a test environment, with the requirements for representative test environments and for addressing differences between the test environment and the production environment, similar to the conditions discussed for live testing in CIP-005-1. Given the range of views presented in comments regarding live testing, as the Reliability Standard development process forms the details of this “demonstrated recovery” concept, it should consider offering guidance beyond the actual Requirements of the Reliability Standard in separate reference documents. The Commission believes this alleviates commenters' concerns about the risks associated with such testing.
726. The Commission notes ISO-NE's concerns about providing a definition of full operational exercise in the NERC Glossary are addressed since we are not requiring the use of that term in the Reliability Standards.
727. Requirement R3 of CIP-009-1 requires the responsible entity to update the recovery plans to reflect any changes or lessons learned from an exercise or the recovery from an actual incident. It requires plan updates to be communicated to the personnel responsible for activating or implementing the recovery plan within 90 days of the change.
728. The Commission stated its concern that individuals responsible for activating and implementing a recovery plan must have the most current information available, and its belief that a 90-day time lag between when a weakness in a recovery plan is discovered and when it is corrected and communicated to such responsible personnel is too long.
729. MidAmerican supports this proposal for the reasons articulated in the CIP NOPR. Northern Indiana supports retaining the Requirement as is, that is, to allow a 90-day period to both update and communicate recovery plans to responsible personnel.
730. ISO-NE is concerned that there is no clear indication of when the 30 day clock would start and asks that changes resulting from modifications to the systems, controls, and procedure shall be documented within 30 days of final implementation of said modifications, similar to its concerns with respect to CIP-007-1.
731. The Commission adopts the CIP NOPR proposal to direct the ERO to modify Requirement R3 of CIP-009-1 to shorten the timeline for updating recovery plans. We believe that allowing 30 days to update a recovery plan is more appropriate, while continuing to allow up to 90 days for completing the communications of that update to responsible personnel. However, the Reliability Standards development process may propose a time period other than 30 days, with justification that it is equally efficient and effective. As we stated with respect to change made pursuant to CIP-007-1, the Commission believes that having correct
732. Requirement R4 of CIP-009-1 requires that a recovery plan include processes and procedures for the backup and storage of information necessary to successfully restore critical cyber assets.
733. We addressed whether the required backups should be tested as part of the system change before they are stored and assumed to be operational.
734. The Commission stated that it understood that preserving multiple generations of restoration backups is common practice, and that competent implementation of the CIP Reliability Standards would tend to include the good and efficient practice of testing recovery backups as they are created. However, the Commission did not find that direction toward these good practices was contained in, implied by, or readily understood from either this or other Requirements among the CIP Reliability Standards, such as Requirement R6 of CIP-003-1. The Commission reiterated its position, stated with regard to the change control processes required by Requirement R6 of CIP-003-1, where no backups of any kind are mentioned, that there is a need for enhanced direction in issues related to proper change control, and that the CIP Reliability Standards should specifically state that a change control process should include procedures for a tested backup. We noted that adding clarification language here to Requirement R4 of CIP-009-1, such as “these procedures are to include practices to test and verify the operability of the backup before it is stored and relied upon for recovery,” would eliminate this ambiguity.
735. MidAmerican supports the proposal to modify the Reliability Standard to require the ERO to provide directions on best practices for the back up and restore process for the reasons articulated in the CIP NOPR.
736. FirstEnergy and Northern Indiana disagree with the Commission's proposal to require verification and detection after adding, modifying, replacing or removing critical cyber asset hardware or software, arguing that this requirement is essentially the same as requiring continuous assessment. Northern Indiana argues that verification that backup tapes are operational is merely the assessment that the tapes are functional; verification does not assure the content may be used for restoration purposes. In the Final Rule, the Commission should clarify what is intended by backup and verify in the context of backup and restoration media. MidAmerican requests clarification of what constitutes a significant change that would require verification because it contends that this process could be extremely onerous if required outside of a planned plant shutdown.
737. SPP suggests that testing backups prior to storage is only one mitigation strategy that should be considered along with other available mitigations to assure the ability to recover from a system failure following any event, not just a significant upgrade. SPP suggests that in a properly managed data center environment, a combination of image and incremental backups should be regularly performed, or inter-site disk-to-disk replication should be implemented, regardless of significant system modifications. Periodic recovery testing, coupled with sound system backup/replication management processes, is adequate to assure recovery and restoration of failed cyber assets; special pre-modification backups are not necessary. It is impractical and unnecessary to test every backup media prior to storing it. Other mitigation strategies that may provide equivalent assurance of recovery include reconstitution of the asset from installation media with recovery of data from either backup files or redundant systems, and complete reconstitution of the asset from a redundant system.
738. Moreover, SPP states that some systems cannot be backed up due to their design architecture. In this instance, complete, up-to-date system configuration and recovery/or reconstitution documentation must be maintained. In addition, given the nature of certain deployed cyber assets, it is not possible to perform a restoration test without placing the asset and the facility it serves at risk. All of this must be weighed when developing the business continuity plan.
739. The Commission adopts the CIP NOPR proposal to direct the ERO to modify CIP-009-1 to incorporate guidance that the backup and restoration processes and procedures required by Requirement R4 should include, at least with regard to significant changes made to the operational control system, verification that they are operational before the backups are stored or relied upon for recovery purposes. Our intent in doing so is to require responsible entities to have a procedure in place that gives them a high confidence level that their backups will actually restore the system as needed. Auditors should be able to determine compliance by reviewing a responsible entity's policies, procedures and records to determine how the testing is done and what recent tests have been performed. In response to commenters' suggestions on how to verify the backup and restoration processes, the ERO should determine appropriate methods to accomplish the Commission's objectives in the Reliability Standards development process.
740. The Commission does not agree with FirstEnergy and Northern Indiana that requiring verification of backup and restoration processes and procedures when a significant change is made to the operational control system requires continuous assessment. The Commission does not believe that every change will necessitate verification of the backup and restoration processes. Rather, it is sufficient to verify a process if a significant change, such as adding new hardware or installing new software to the control system, is made. The Commission does not believe that responsible entities will be making significant changes to their backup and restoration processes continuously. Similar to our determination with respect to Requirement R4 of CIP-005-1, the ERO should determine, through the Reliability Standards development process, what would constitute a
741. Requirement R5 requires annual testing of information stored on backup media to ensure information essential to recovery is available.
742. The CIP Assessment noted that it is critical that such information be accessible in the event of an actual incident, and that the Reliability Standard does not specify any actions to be taken in the event of a failure in testing, and asked whether such testing should also be conducted on a more frequent basis.
743. In the CIP NOPR, the Commission addressed whether such testing should also be conducted on a more frequent basis and what action should be taken in the event of a failure in testing. We understood that, if these CIP Reliability Standards were implemented in a full and competent manner, then adequate backup verification measures would probably be in place. However, we stated that Reliability Standards demand a higher degree of certainty and should provide the guidance that responsible entities need to have procedures to verify backups are successfully completed every cycle and to have recovery procedures in place for when the backup fails.
744. The Commission proposed to direct the ERO to modify CIP-009-1 to provide direction that backup practices include regular procedures to ensure verification that backups are successful and backup failures are addressed, thus guaranteeing that backups are available for future use.
745. ISO-NE agrees with the Commission proposal if the intent is to review the backup process. However, ISO-NE states that testing the actual backup data are not realistic in most instances, because the environment would literally have to be shut down and be restarted with the data in order to test it. ISO-NE asserts that, in an emergency, the restored data are a good starting point for recovery, but for a test process, such activity would not be acceptable due to the impact on reliability and market systems. Therefore, ISO-NE requests that the Commission omit directing the ERO to make any changes to CIP-009-1 Requirements R4 and R5.
746. FirstEnergy states that the requirement to ensure that backups are successful and available for future use should be limited to spot test restorations, such as restoration of a log file, because the ultimate verification of a backup—a complete restoration itself—is not practical.
747. Northern California agrees with the Commission that NERC should expand Requirement R5 of CIP-009-1 to include verification of backups.
748. The Commission adopts the CIP NOPR proposal to direct the ERO to modify CIP-009-1 to provide direction that backup practices include regular procedures to ensure verification that backups are successful and backup failures are addressed, so that backups are available for future use. However, the Commission agrees with ISO-NE that it is impractical to require the system to be shut down and be restarted with the data in order to test it. As stated above with respect to verifying backups after a significant change, our intent is to give responsible entities a high confidence level that their backups will actually restore the system as needed. Auditors should be able to look at a responsible entity's policies, procedures and records to determine how the testing is done and what recent tests have been performed. The ERO should determine appropriate methods to accomplish the Commission's objectives in the Reliability Standards development process.
749. Violation Risk Factors delineate the relative risk to the Bulk-Power System associated with the violation of each Requirement and are used by the ERO and the Regional Entities to determine financial penalties for violating a Reliability Standard. The ERO assigns a lower, medium or high Violation Risk Factor for each mandatory Reliability Standard Requirement.
750. In a separate filing, the ERO submitted 162 Violation Risk Factors that correspond to Requirements of the proposed CIP Reliability Standards.
751. In the CIP NOPR, the Commission proposed to approve the 162 proposed Violation Risk Factor assignments that correspond to the Requirements of the CIP Reliability Standards and direct the ERO to revise 43 of them. In addition, the Commission noted that the ERO did not assign Violation Risk Factors to nine Requirements and proposed to direct the ERO to make these Violation Risk Factor assignments and file them for Commission approval.
752. The Commission noted that NERC assigned a “lower” designation to almost 85 percent of the Violation Risk Factors corresponding to the Requirements of the CIP Reliability Standards. No Requirements received a “high” Violation Risk Factor assignment. The Commission stated that it believed the ERO mischaracterized many of the Requirements as administrative, resulting in a lower Violation Risk Factor assignment, where in fact a medium or high designation was more appropriate.
753. We proposed to direct the ERO to submit a filing containing revised Violation Risk Factors within 60 days of the date of the Final Rule. We also proposed to direct the ERO to include in its filing a complete Violation Risk Factor matrix.
754. NERC argues that the Commission should not establish a 60-day compliance deadline for NERC to modify the Violation Risk Factors. Instead, it suggests that the Commission should find that Violation Risk Factors may be addressed in the NERC Reliability Standards development process, so long as this produces timely results.
755. While the Commission has elsewhere determined that Violation Risk Factors can be changed outside of the full ERO Reliability Standards development process, NRECA supports and continues to assert that it is preferable for all concerned for such changes to be made within the context of that process. It asserts that institutional bifurcation of the development of the Reliability Standards from the consequences of violation of the Reliability Standards is not a desirable practice and should be minimized. The ERO, through its Reliability Standards development process, should be allowed to revisit the CIP Violation Risk Factors without having a specific outcome dictated by the Commission.
756. Progress maintains that unnecessarily increasing Violation Risk Factors for planning Reliability Standards may have unintended consequences. According to Progress, assigning overly conservative Violation Risk Factors will cause senior managers responsible for CIP Reliability Standard compliance to focus more time and resources on satisfying those Reliability Standards, potentially to the detriment of other Reliability Standards. It maintains that the level of the Violation Risk Factor is intended to communicate the importance of the Reliability Standards and, consequently, the resources that should be devoted to its implementation and the magnitude of the penalty associated with its violation.
757. NERC and other commenters ask the Commission to defer to NERC on the determination of Violation Risk Factors and allow NERC to reconsider the designations using the Reliability Standards development process. The Commission has previously determined that Violation Risk Factors are not a part of the Reliability Standards.
758. That being said, NERC may choose the procedural vehicle to change the Violation Risk Factors consistent with the Commission's directives. NERC may use the Reliability Standards development process, so long as it meets Commission-imposed deadlines.
759. Consistent with the
760. The Commission disagrees with Progress that the Commission's concerns with respect to the CIP Violation Risk Factors will result in overly conservative Violation Risk Factor assignments. We also disagree with the characterization that a Violation Risk Factor delineates the importance of the Reliability Standard. Rather, the Violation Risk Factors delineate the relative risk to the Bulk-Power System associated with the violation of each Requirement. The Commission believes that the analysis below appropriately takes into account the risk of violating each Requirement in the CIP Reliability Standards.
761. The Commission proposed to require NERC to assign several Requirements in the CIP Reliability Standards a high Violation Risk Factor. For example, CIP-002-1 Requirement R2, which requires the identification of assets that are critical to the Bulk-Power System, is assigned a lower Violation Risk Factor. While the product of the Requirement is a list of critical assets, the Commission stated that this is clearly not an administrative Requirement. In fact, the failure to properly identify critical assets could place the Bulk-Power System at an unacceptable risk or restoration efforts could be hindered. Further, this Requirement has a controlling effect over all of the CIP Reliability Standards that follow. The Commission stated that, if an asset is critical and is not identified as such, the remaining CIP Reliability Standards will not be applied to that asset. Depending on the asset that is overlooked, and consequently not protected by the Reliability Standards, a higher level of Bulk-Power System failure is possible. Thus, by NERC's definition, this Requirement should have a high Violation Risk Factor assignment. In addition, the recommendations related to physical and cyber security contained in the Blackout Report,
762. Similarly, CIP-002-1 Requirement R3, which requires the identification of cyber assets that are essential to the operation of critical Bulk-Power System assets, has a medium Violation Risk Factor assignment. By definition, a medium Violation Risk Factor assignment means that the Requirement is unlikely, under emergency, abnormal, or restoration conditions to lead to Bulk-Power System instability, separation, or cascading failures, or to hinder restoration to a normal condition. However, if this Requirement is violated, the Bulk-Power System could in fact be at an unacceptable risk of failure or restoration efforts could be hindered. Further, this Requirement has a controlling effect over all of the CIP Reliability Standards that follow. As with CIP-002-1 Requirement R2, depending on the asset that is overlooked, and consequently not protected by the Reliability Standards, a higher level of Bulk-Power System failure is possible. Also, we stated that proper compliance with CIP-002-1, Requirement R3 is essential to the ability of the proposed CIP Reliability Standards to satisfy the recommendations of the Blackout Report.
763. The Commission also proposed to direct the ERO to change the Violation Risk Factor assignments for several Reliability Standards from a lower to a medium assignment. The Commission's primary reason for proposing to direct these changes was to promote implementation of the recommendations contained in the Blackout Report; to establish consistency within a Reliability Standard, i.e., among sub- and main Requirements of the same Reliability Standard; and consistency across Reliability Standards.
764. Northern California agrees that many requirements inappropriately have a Violation Risk Factor of lower and that NERC should re-evaluate the Violation Risk Factors of the Requirements identified by the Commission in Appendix B of the CIP NOPR, and urges NERC to adopt the Commission's recommended assessment.
765. While APPA and the LPPC members state that they are committed to complying with all of the CIP Reliability Standards, APPA/LPPC believe that the Commission's proposal to elevate the violation risk factor for CIP-002-1, Requirement R2 from low to high and the violation risk factor for CIP-002-1, Requirement R3 from medium to high should be reexamined. While overlooked assets could result in Bulk-Power System failure, the oversight process now contemplated by Regional Entities over asset designation, and the overwhelming incentive responsible entities have to proceed cautiously, make it difficult to see a substantial potential for assets to be overlooked.
766. EEI states that the proposal to direct the ERO to modify CIP-002-1 to denote a high Violation Risk Factor assignment mandates a particular outcome and does not allow for consideration of any alternative.
767. The Commission adopts the CIP NOPR proposal to direct the ERO to revise 43 Violation Risk Factors. While the Commission hopes that APPA/LPPC are correct that there is not a substantial potential for assets to be overlooked, this is not a reason to not modify the Violation Risk Factors. As we stated in Order No. 672, the fundamental goal of mandatory, enforceable Reliability Standards and related enforcement programs is to promote behavior that supports and improves Bulk-Power System reliability.
768. Further, the Commission is not persuaded by the argument that the Violation Risk Factor should not be high because there is an incentive for responsible entities to proceed cautiously. The Violation Risk Factor should consider the risk to the system of non-compliance, regardless of other incentives that users, owners and operators of the Bulk-Power System have to comply.
769. Finally, the regional oversight over asset designation discussed by APPA/LPPC is not in place yet. Therefore, the Commission cannot rule on what it might be.
770. The Office of Management and Budget (OMB) Regulations require that OMB approve certain reporting and recordkeeping (collections of information) imposed by an agency.
771. The “public protection” provisions of the Paperwork Reduction of 1995 require each agency to display a currently valid control number and inform respondents that a response is not required unless the information collection displays a valid OMB control number on each information collection or provides a justification as to why the information collection control number cannot be displayed. In the case of information collections published in regulations, the control number is to be published in the
772.
773. The CIP Reliability Standards do not require a responsible entity to report to the Commission, ERO or Regional Entities the various policies, plans, programs and procedures. However, the documentation of the policies, plans, programs and procedures must be available to demonstrate compliance with the CIP Reliability Standards. The Commission has included the cost of developing the required documentation for the required policies, plans, programs and procedures in its burden estimate. The Commission, however,
774. In formulating our estimate of the reporting burden, the Commission has been guided by several factors.
Further, the reporting burden would vary with the number of critical cyber assets identified pursuant to CIP-002-1. An entity that identifies numerous critical cyber assets, including assets located at remote locations, will likely require more resources to develop its policies, plans, programs and procedures compared to an entity that identifies one or two critical cyber assets, housed at a single location. Based on this distinction, the Commission has developed separate estimates for large investor-owned utilities and other responsible entities such as municipals, generators and cooperatives.
Further, many entities, including those that did not comply with UA-1200, typically have followed certain practices specified in the CIP Reliability Standards. The Commission believes that practices such as conducting cyber security training, having procedures for whom to contact in case of a cyber security incident, and developing a plan for how to restore a computerized control system should it fail are usual and customary practices in the electric industry and others. The Commission has taken such customary practices into account when estimating the reporting burden.
Large investor-owned utility = 322,400 hours@$88 = $28,371,200.
Others, including munis and coops = 795,000 hours@$88 = $69,960,000.
Entities that have not identified critical cyber assets = 8,000 hours@$88 = $704,000.
Because auditably compliant status is not required for many requirements until mid-2010, the Commission has projected the costs over a four-year period. On an annual basis the costs will be ($28,371,200 + $69,960,000 + $704,000)/4 years = $24,758,800 per year.
The hourly rate of $88 is a composite figure of the average cost of legal services ($200 per hour), technical employees ($39.99 per hour) and administrative support ($25 per hour), based on hourly rates from the Bureau of Labor Statistics (BLS). Using the May 2006 OES Industry-Specific Occupational Employment and Wage Estimates, the median hourly rate wage estimate for a computer software engineer is $39.99.
775. MidAmerican states that the Commission's information collection assessment warrants revision for significantly underestimating the cost of compliance, even after controlling for variation in the number of critical cyber security assets identified by the responsible entity. MidAmerican alone estimates its total compliance costs as a substantial fraction of the burden amount estimated by the Commission, based upon compliance with the originally proposed CIP Reliability Standards. That cost should be expected to increase by ten percent based upon the more stringent Reliability Standards and rising labor rates. Based on this actual experience to date, MidAmerican submits that the CIP NOPR burden underestimates implementation difficulties by inadequately accounting for both the replacement costs associated with upgrading existing antiquated cyber infrastructure as well as the host of employer recruiting, hiring and training challenges responsible entities will face to demonstrate compliance. The skilled computer software personnel necessary to achieve substantive compliance are in much demand (but short supply), nationally, and accordingly command compensation levels considerably higher than the CIP NOPR assumptions. To remedy these shortcomings, MidAmerican requests that the Commission revisit this issue by sampling the 1,000 or so entities expected to be required to comply with the CIP Reliability Standards and revising the burden estimate accordingly.
776. MidAmerican seems to misunderstand the purpose of the information collection statement. The OMB regulations require agencies to submit a burden estimate for collections of information contained in proposed rules, not for the entire cost of compliance. As stated in the CIP NOPR, the Commission only included the cost of developing the required documentation for the required policies, plans, programs and procedures in its burden estimate, but did not include in our burden estimate the cost of substantive compliance with the CIP Reliability Standards. MidAmerican raises concerns regarding the total cost of compliance with the Reliability Standards, rather than the burden associated with reporting requirements in the Reliability Standards. Therefore, the Commission does not believe it is necessary to revise the burden estimate based on MidAmerican's comments.
777. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.
778. The Regulatory Flexibility Act of 1980 (RFA)
779. In drafting a rule an agency is required to: (1) Assess the effect that its regulation will have on small entities; (2) analyze effective alternatives that may minimize a regulation's impact and (3) make the analyses available for public comment.
780. If in preparing the NOPR an agency determines that the proposal could have a significant impact on a substantial number of small entities, the agency shall ensure that small entities will have an opportunity to participate in the rulemaking procedure.
781. In its Final Rule, the agency must also either prepare a Final Regulatory Flexibility Analysis (Final RFA) or make the requisite certification. Based on the comments the agency receives on the NOPR, it can alter its original position as expressed in the NOPR but it is not required to make any substantive changes to the proposed regulation.
782. In the CIP NOPR, the Commission analyzed the effect of the proposed rule on small entities.
783. In addition, the Commission's analysis relied on NERC's compliance registry, applying the NERC Statement of Registry Criteria, to identify entities that must comply with the CIP Reliability Standards. For an entity to be included in the compliance registry, the ERO will have made a determination that a specific small entity has a
784. The Commission's analysis concluded that the CIP Reliability Standards would not have a significant economic impact on a substantial number of small entities. The majority of small entities would not be required to comply with mandatory Reliability Standards based on the application of the NERC Registry Criteria. Moreover, the Commission explained that a small entity that is registered but does not identify critical cyber assets pursuant to CIP-002-1 will not have compliance obligations pursuant to CIP-003-1 through CIP-009-1. While a small entity that identifies only a few critical cyber assets must comply with CIP-003-1 through CIP-009-1, the Commission stated that the economic impact of such compliance would not be significant. Likewise, the housing of a limited number of critical cyber assets in a single location will lessen the economic impact of compliance.
785. The Commission also noted that, while not required or proposed by the CIP NOPR, small entities could choose to collectively select a single consultant to develop model software and programs to comply with the CIP Reliability Standards on their behalf. Such an approach could significantly reduce the costs that would be incurred if each company would address these issues independently.
786. The Commission further explained that, while there would be some portion of small entities that would have to expend significant amounts of resources on labor and technology to comply with the CIP Reliability Standards, the Commission believed that this would be a minority. Further, in such circumstances, the economic impact would be justified as necessary to protect cyber security assets that support Bulk-Power System reliability.
787. The Commission also investigated possible alternatives. These included the Commission's adoption in Order No. 693 of the NERC definition of bulk electric system, which reduces significantly the number of small entities responsible for compliance with mandatory Reliability Standards.
788. NRECA states that, for the most part, the CIP NOPR treats small entities in an appropriate manner. NRECA maintains that the approach of having the CIP and other Reliability Standards apply to small entities only if they have a material impact on the reliability of the Bulk-Power System is appropriate and consistent with the Commission's prior orders, the statute, and the ERO's Statement of Registry Criteria, and NRECA supports it fully, with the exception of the Commission's discussion of jointly-owned facilities, which is discussed with respect to CIP-004-1.
789. APPA/LPPC state that application of the NERC Statement of Compliance Registry Criteria has reduced the total number of public power utilities potentially subject to NERC's Reliability Standards from nearly 2,000 to approximately 326 discrete public power utilities, and APPA/LPPC agree with the Commission that NERC's compliance registry goes a long way toward mitigating the economic impact of the proposed rules on small entities. Nonetheless, APPA/LPPC disagree with the Commission's categorical statement that “the CIP Reliability Standards will not have a significant economic impact on a substantial number of small entities.”
790. According to APPA/LPPC, approximately 293 of the 326 public power systems included on the NERC compliance registry meet the SBA definition of a small electric utility.
791. Despite these reservations, APPA/ LPPC believe that the broad contour of the rule contemplated by the CIP NOPR, subject to the changes they request in comments, satisfies the requirements of the RFA. APPA/LPPC state that they recognize that CIP Reliability Standards are necessary to ensure the reliable operation of the Bulk-Power System. While NERC's proposed standards will place the burden on many small entities to identify critical assets and critical cyber assets, this approach is far superior to a top-down approach to asset classification. Assuming small entities do have critical assets and critical cyber assets, they will have to take on significant burdens and incur significant costs to protect their critical cyber assets. However, APPA/LPPC state that NERC's proposed timeline for the implementation plan appears feasible. Moreover, they state that joint action agencies and other similar organizations may form joint registration organizations that accept compliance responsibilities for their members or provide compliance services to their members.
792. Arkansas Electric fully supports the comments submitted in this docket by NRECA. Arkansas Electric argues that, throughout the CIP NOPR, the Commission proposes significant changes to the Reliability Standards which will increase the amount of effort and expense required to comply. Arkansas Electric is concerned that the costs of these additional resources will be especially high for small entities, when viewed in a relative sense. Arkansas Electric is concerned that, even with the friendly tone that some state regulators have taken toward rate recovery for cyber security-related expenses, these dollars would still come from its members. Arkansas Electric
793. California Cogeneration and Energy Producers argue that the eight cyber security Reliability Standards will impose significant new compliance costs on registered entities to the extent they identify critical cyber assets, under CIP-002-1. They suggest that the Commission should direct the ERO to develop pro forma models of protocols and methodologies to be used by entities to facilitate compliance. California Cogeneration submits that pro forma protocols could help mitigate the costs of compliance with the requirements of Reliability Standards CIP-003-1 through CIP-009-1. California Cogeneration points out that the CIP NOPR suggested that groups of entities could collaborate to reduce compliance costs; California Cogeneration argues that this approach could be expanded to include a formal role for NERC.
794. To maximize the effectiveness and the focus of the Reliability Standards, Energy Producers argues that NERC should revisit the NERC Functional Model to include a qualifying facility (QF) category so that Reliability Standards specific to QFs can be developed to account for their unique operating characteristics. To ensure that the regulations effectively promote reliability while not imposing unreasonable costs, Energy Producers argues that the regulations should provide a rigorous definition of critical cyber assets. Such rigor would be provided, first, by retaining the definitions contained in the current draft of the regulations, and second, by providing greater specificity to the risk-based assessment required in CIP-002-1.
795. Iowa Municipals is concerned about the impact that the CIP Reliability Standards will have on smaller entities. While it is true that smaller entities can provide a cyber gateway to larger entities, and many smaller entities will be excluded through the identification of critical cyber assets, it is equally true that some smaller entities will, nonetheless, be subjected to the CIP Reliability Standards. The CIP NOPR pays insufficient attention to supporting compliance by smaller entities. Iowa Municipals makes some suggestions that will assist the Commission to enable smaller entities to comply with the Reliability Standards.
796. One area in which smaller entities' compliance efforts can be supported is through the self-certification process. Iowa Municipals supports the comments filed by MidAmerican that support a semi-annual certification process. As an enhancement to this process, Iowa Municipals recommends that the Commission require NERC to provide a “lessons learned” report to entities within 30 days of the certification deadline. This report has the potential of providing invaluable guidance and assistance to smaller entities.
797. Iowa Municipals also urges the Commission to support smaller entities' compliance efforts by providing either a longer compliance timetable, or providing temporary waivers upon an adequate showing of work to attain compliance. Further, Iowa Municipals suggests that compliance by smaller entities can be promoted by allowing smaller entities to walk in the footsteps of larger entities and reach compliance more quickly by taking advantage of lessons learned by others. Iowa Municipals also argues that following such a better path to compliance by smaller entities should ultimately provide a higher level of system protection.
798. The Southwest TDUs state that the CIP NOPR seems to be of two minds on how the impact of the CIP Reliability Standards might be addressed for smaller entities. On the one hand, the Commission proposes that NERC and the Regional Entities help the small entities by providing technical support to identify critical assets. On the other, the Commission acknowledges that these Reliability Standards could be made applicable down to the smallest entity, which appears to discount the economic impact on these entities required to be analyzed by the RFA because cyber security operations may actually be managed by a control area operator or other larger entity. Southwest TDUs argue that just because a larger entity is performing compliance does not mean the costs of compliance are not being passed on to the small entities. Indeed, there is every likelihood that that will be the case. Southwest TDUs maintain that it does not know how onerous a burden small entities face. The Commission must be ready to adjust the CIP requirements, if experience shows that the burden on small entities proves to be onerous.
799. As of October 2007, there are 1,772 registered entities, of which the Commission estimates that approximately 1,400 will be responsible for compliance with the CIP Reliability Standards. Of these, the Commission estimates that the CIP Reliability Standards would apply to approximately 632 small entities, consisting of 12 small investor-owned utilities and 620 small municipal and cooperatives.
800. Arkansas Electric raises concerns with the cost to small entities of the modifications directed by the Commission. These modifications will be made by the ERO through the Reliability Standards development process. Until NERC files any revised Reliability Standards, the Commission cannot estimate their burden on any user, owner or operator of the Bulk-Power System, including small entities. The Commission therefore does not believe it is appropriate to speculate on the cost of compliance with any modified Reliability Standard at this time.
801. The Commission does not believe it is appropriate to grant California Cogeneration's request that NERC develop pro forma models of protocols and methodologies to be used by entities to facilitate compliance. As discussed in the section regarding guidance, that level of detail could potentially introduce common vulnerabilities resulting from all small entities implementing the Reliability Standards using a nearly identical solution. With respect to California Cogeneration's suggestion that NERC should have a formal role in collaborating to reduce compliance costs, the Commission will not direct that at this time. However, NERC should consider providing information to such groups. Further, the Commission believes that requiring the ERO to develop guidance on how to comply with the Reliability Standards should facilitate compliance by small entities.
802. The Commission also declines to direct the ERO to include a QF category in the Functional Model, as requested by Energy Producers. The Commission believes that this request is outside the scope of this rulemaking, which only concerns the CIP Reliability Standards proposed by NERC.
803. The Commission does not believe it is necessary to allow small entities a longer compliance timetable or to provide temporary waivers upon an adequate showing of work to attain compliance. As we stated in the CIP NOPR, the burden to small entities is not great, but the economic impact is justified as necessary to protect cyber security assets that support Bulk-Power System reliability. Further, the Commission believes that allowing small entities to collectively select a
804. While Southwest TDUs are correct that the Commission acknowledges that the Reliability Standards could be made applicable down to the smallest entity, the Commission disagrees that this discounts the economic impact on these entities. As we stated in the CIP NOPR, to be included in the compliance registry, the ERO will have made a determination that a specific small entity has a material impact on the Bulk-Power System. A small entity placed on the compliance registry could then appeal the determination to the ERO and the Commission.
805. Further, Southwest TDUs argue that just because a larger entity is performing compliance does not mean the costs of compliance are not being passed on to the small entities. We agree; however, in allowing small entities to pool their resources and select a single consultant to develop model software and programs, each entity need not separately fund model software and programs development. Rather, that cost can be spread over several entities.
806. For the reasons stated in the CIP NOPR and above, the Commission certifies that this rule will not have a significant economic impact on a substantial number of small entities. Accordingly, no regulatory flexibility analysis is required.
807. In addition to publishing the full text of this document in the
808. From FERC's Home Page on the Internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field.
809. User assistance is available for eLibrary and the FERC's Web site during normal business hours from FERC's Online Support at 202-502-6652 (toll free at 1-866-208-3676) or e-mail at
810. This Final Rule is effective April 7, 2008. The Commission has determined, with the concurrence of the Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule is a “major rule” as defined in section 351 of the Small Business Regulatory Enforcement Fairness Act of 1996.
Administrative practice and procedure, Electric power, Penalties, Reporting and recordkeeping requirements.
By the Commission.
Securities and Exchange Commission.
Proposed amendments of temporary rules.
We are proposing to amend temporary rules that were published on December 21, 2006, in Release No. 33-8760 [71 FR 76580]. These temporary rules require companies that are non-accelerated filers to include in their annual reports, pursuant to rules implementing Section 404(b) of the Sarbanes-Oxley Act of 2002, an attestation report of their independent auditor on internal control over financial reporting for fiscal years ending on or after December 15, 2008. Under the proposed amendments, a non-accelerated filer would be required to provide the auditor's attestation report on internal control over financial reporting in an annual report filed for fiscal years ending on or after December 15, 2009.
Comments should be received on or before March 10, 2008.
Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an e-mail to
• Use the Federal Rulemaking Portal (
• Send paper comments in triplicate to Nancy M. Morris, Secretary, Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-1090.
Sean Harrison, Special Counsel, Office of Rulemaking, Division of Corporation Finance, at (202) 551-3430, U.S. Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-3628.
We are proposing to amend the following forms and temporary rules: Rule 2-02T of Regulation S-X,
On December 15, 2006,
In the 2006 Release, we cited two primary reasons for deferring implementation of the auditor attestation report requirement for an additional year after implementation of the management report requirement. First, we stated that the deferred implementation would afford non-accelerated filers and their auditors the benefit of anticipated changes by the PCAOB to AS No. 2, subject to Commission approval, as well as any implementation guidance that the PCAOB issued for auditors of smaller public companies.
Second, we expected a deferred implementation of the auditor attestation requirement to save non-accelerated filers the full potential costs associated with the auditor's initial attestation to, and report on, management's assessment of ICFR during the period that changes to AS No. 2 were being considered and implemented, and the PCAOB was formulating guidance specifically for auditors of smaller public companies. Public commenters previously have asserted that the ICFR compliance costs are likely to be disproportionately higher for smaller public companies than larger ones, and that the auditor's fee represents a large percentage of those costs.
Furthermore, we have learned from commenters, including those participating in our roundtables on implementation of the ICFR requirements, that while companies incur increased internal costs in the first year of compliance, some of which are due to “deferred maintenance” items (for example, documentation, remediation, etc.), these costs may
The compliance date extensions that we granted in 2006 were part of a series of actions that the Commission and PCAOB each announced that they intended to take to improve implementation of the internal control over financial reporting requirements.
• Issuance by the Commission of interpretive guidance for management to assist management in complying with the ICFR evaluation and disclosure requirements;
• Consideration of efforts by COSO to provide more guidance on how the COSO framework on internal control can be applied to smaller public companies;
• The PCAOB's issuance, with Commission approval, of Auditing Standard No. 5 (“AS No. 5”), which replaced AS No. 2;
• Reinforcement of auditor efficiency through PCAOB inspections and Commission oversight of the PCAOB's audit firm inspection program;
• Development, or facilitation of development, of implementation guidance for auditors of smaller public companies; and
• Continuation of PCAOB forums on auditing in the small business environment.
On June 20, 2007, we approved the issuance of interpretive guidance
As discussed above, on July 25, 2007, we approved the PCAOB's AS No. 5, which replaced AS No. 2. The new standard sets forth the professional standards and related performance guidance for independent auditors to attest to, and report on, management's assessment of the effectiveness of ICFR. Our management guidance, in combination with AS No. 5, was intended to make ICFR audits and management evaluations of ICFR more cost-effective by being risk-based and scalable to a company's size and complexity. Although the PCAOB issued AS No. 5, and we approved it, according to our planned timetables, there still are some additional actions that the Commission and PCAOB intend to take that give us reason to propose a further extension of the auditor attestation report compliance date for non-accelerated filers.
One of these actions is the PCAOB's issuance of final staff guidance on auditing ICFR of smaller public companies. On October 17, 2007, the PCAOB published preliminary staff guidance that demonstrates how auditors can apply the principles described in AS No. 5 and provides examples of approaches to particular issues that might arise in the audits of smaller, less complex public companies.
Another action involves a study that we are undertaking to determine whether the Section 404(b) auditor attestation requirement of the Sarbanes-Oxley Act is being implemented in a manner that will be cost-effective for smaller reporting companies. The study will pay special attention to those small companies that are complying with the ICFR requirements for the first time.
This study of costs and benefits will include a Web-based survey of companies that are subject to the ICFR requirements as well as in-depth interviews with a subset of these companies. Our plan is to gather data from a large cross-section of companies about the costs and benefits of compliance with the ICFR requirements and to evaluate whether the new management guidance and AS No. 5 are having the intended effect of facilitating more cost-effective ICFR evaluations and audits. Because we intend to collect data based on companies' experiences, this study will be taking place in the coming months as companies for the first time prepare their financial statements and undergo external audits under the new AS No. 5 and/or conduct their internal ICFR evaluations with the aid of the new management guidance. We anticipate that the study and analysis of the results will be completed no earlier than the summer of 2008.
We also note that others have expressed concerns about the orderly and efficient implementation of the ICFR requirements.
If we do not adopt the proposed amendments, non-accelerated filers will have to begin complying with the auditor attestation requirement for fiscal years ending on or after December 15, 2008. To accomplish this, in 2008, many non-accelerated filers would need to engage their independent auditors to perform integrated audits of their financial statements and ICFR. Without an extension, these companies may begin to incur costs before we have an opportunity to observe whether further action to improve the effectiveness and efficiency of Section 404 implementation is warranted. Therefore, we believe that an additional one-year deferral of the auditor attestation requirement would be appropriate so that these companies do not incur unnecessary compliance costs before we have the benefit of the study. An additional one-year deferral will allow the PCAOB additional time during 2008 to promulgate its guidance for ICFR audits of smaller public companies, as well as additional time for the auditors
We propose to amend Item 308T of Regulation S-K, Rule 2-02T of Regulation S-X, and Forms 10-Q, 10-K, 20-F and 40-F to require non-accelerated filers to provide their auditor's attestation in their annual reports filed for fiscal years ending on or after December 15, 2009. If we adopt the proposed amendments, a non-accelerated filer would continue to be required to state in its management report on ICFR that the company's annual report does not include an auditor attestation report.
In the 2006 Release, we also adopted a temporary amendment that provided that the management report included in a non-accelerated filer's annual report that did not contain the auditor's attestation report would be deemed “furnished” rather than “filed” and not be subject to liability under Section 18 of the Exchange Act.
We request and encourage any interested person to submit comments regarding the proposed amendments to extend the auditor attestation report compliance date described above. In particular, we solicit comment on the following questions:
• Is it appropriate to provide a further extension of the auditor attestation requirement for non-accelerated filers as proposed? If so, should we postpone this requirement for an additional year as proposed, or would a longer or shorter timeframe be more appropriate?
• How would the proposed extension affect investors in non-accelerated filers?
• Would the proposed additional deferral of the auditor's attestation report requirement make the application of the Section 404 requirements more or less efficient and effective for non-accelerated filers?
• Should management's report on ICFR be “filed” rather than “furnished” during the second year of the non-accelerated filer's compliance with the ICFR requirements under Section 404(a) if we adopt the proposed extension?
In connection with our original proposal and adoption of the rules and amendments implementing the Section 404 requirements, we submitted cost and burden estimates of the collection of information requirements of the amendments to the Office of Management and Budget (“OMB”). We published a notice requesting comment on the collection of information requirements in the proposing release for the rule amendments. We submitted these requirements to the OMB for review in accordance with the Paperwork Reduction Act of 1995 (“PRA”)
The proposed amendments would postpone for one year the date by which a non-accelerated filer would be required to include in its annual report an auditor attestation report on management's assessment of internal control over financial reporting. As a result, all non-accelerated filers would be required to complete only management's assessment in their first and second year of their compliance with the Section 404 requirements.
We plan to conduct a study to assess whether the Section 404(b) auditor attestation requirement of the Sarbanes-Oxley Act is being implemented in a manner that will be cost-effective for smaller reporting companies. Our management guidance and the new auditing standard were designed to make management evaluations and ICFR audits more cost-effective. We believe that an additional one-year deferral of the auditor attestation report requirement would benefit non-accelerated filers by helping smaller companies avoid incurring unnecessary compliance costs as we determine whether further action to improve the effectiveness and efficiency of Section 404 implementation is warranted. In addition, we believe that non-accelerated filers may experience the following additional benefits from the proposed extension:
• Auditors of non-accelerated filers would have significantly more time to conform their ICFR audit approach to meet the requirements of AS No. 5, and to consider the PCAOB's guidance for auditors of smaller public companies; and
• Non-accelerated filers would have additional time to focus on their approach for evaluating and reporting on the effectiveness of ICFR. This may facilitate their efforts to develop best practices and efficiencies in preparing the management report prior to becoming subject to the auditor attestation report requirement.
If we adopt the proposed amendments, investors in non-accelerated filers will have to wait longer than they would in the absence of the proposed extension for the assurances provided by the attestation report by the companies' auditor on management's report on ICFR and the added investor confidence that could result. The proposed amendments may increase the risk that, without the auditor's attestation, some non-accelerated filers may erroneously conclude that the company's ICFR is effective, when an ICFR audit might reveal that it is not. In addition, some companies may conduct an assessment that is not as thorough, careful and as appropriate to the company's circumstances as they would perform if the auditor were also conducting an audit of ICFR. The proposed amendments may also increase the risk that weaknesses in a company's ICFR will go undetected for a longer period of time.
We request data to quantify the potential costs and benefits described above. We seek estimates of these costs and benefits, as well as any costs and benefits that we have not identified that may result from the adoption of these proposed amendments. We also request
For purposes of the Small Business Regulatory Enforcement Fairness Act of 1996, or “SBREFA,”
• An annual effect on the economy of $100 million or more (either in the form of an increase or a decrease);
• A major increase in costs or prices for consumers or individual industries; or
• Significant adverse effects on competition, investment or innovation.
We request comment on the potential impact of the proposals on the economy on an annual basis. Commenters are requested to provide empirical data and other factual support for their views if possible.
Section 23(a)(2) of the Exchange Act
We believe that taking additional time to evaluate how efficiently the Section 404(b) process is being implemented reduces the possibilities of needless inefficiencies and transition costs for non-accelerated filers. Further, if the costs incurred by companies are unnecessarily high, companies may find it difficult to grow and may experience barriers to capital formation. We expect that this additional one-year delay of the auditor attestation report requirement will make the implementation process more efficient and less costly for non-accelerated filers, which should promote efficiency and capital formation.
It is possible that a competitive impact could result from the differing treatment of non-accelerated filers and larger companies that already have been complying with the Section 404 requirements, but we do not expect that the extension will have any measurable effect on competition. We solicit public comment that will assist us in assessing the impact that the proposed amendments could have on competition, efficiency and capital formation.
This Initial Regulatory Flexibility Analysis (“IRFA”) has been prepared in accordance with the Regulatory Flexibility Act.
The Commission plans to complete a study of the costs and benefits of companies' Section 404 implementation. We are proposing to defer the implementation of the auditor attestation report requirement for non-accelerated filers for an additional year for the following reasons, among others discussed above:
• To enable non-accelerated filers more time to prepare and gain efficiencies in the review and evaluation of the effectiveness of internal control over financial reporting;
• To provide the Commission with time to review the findings of its study and to consider whether further action to improve the effectiveness and efficiency of Section 404 implementation is warranted;
• To provide the PCAOB additional time to promulgate its guidance for ICFR audits of smaller public companies; and
• To provide the auditors of non-accelerated filers additional time to consider such guidance.
The proposed amendments aim to further the goals of the Sarbanes-Oxley Act to enhance the quality of public company disclosure concerning the company's internal control over financial reporting and increase investor confidence in the financial markets.
We are issuing the proposals under the authority set forth in Section 19 of the Securities Act, Sections 3, 12, 13, 15, 23 and 36 of the Exchange Act, and Sections 3(a) and 404 of the Sarbanes-Oxley Act.
The proposed changes would affect some issuers that are small entities. Exchange Act Rule 0-10(a)
The proposed amendments would alleviate reporting and compliance burdens by postponing by an additional year the date by which non-accelerated filers must begin to comply with the auditor attestation report on ICFR in their annual reports.
The ICFR requirements do not duplicate, overlap, or conflict with other federal rules.
The Regulatory Flexibility Act directs us to consider alternatives that would accomplish our stated objectives, while minimizing any significant adverse impact on small entities. In connection with the proposed amendments, we considered the following alternatives:
• Establishing different compliance or reporting requirements or timetables that take into account the resources available to small entities;
• Clarifying, consolidating or simplifying compliance and reporting requirements under the rules for small entities;
• Using performance rather than design standards; and
• Exempting small entities from all or part of the requirements.
The proposed amendments would establish a different compliance and reporting timetable for small entities. We believe that the proposed amendments would promote the primary goal of enhancing the quality of reporting and increasing investor confidence in the fairness and integrity of the securities markets. Therefore we do not believe exempting small entities from the proposed amendments would be appropriate.
We encourage the submission of comments with respect to any aspect of this Initial Regulatory Flexibility Analysis. In particular, we request comments regarding:
• The number of small entity issuers that may be affected by the proposed amendments;
• The existence or nature of the potential impact of the proposed amendments on small entity issuers discussed in the analysis; and
• How to quantify the impact of the proposed amendments.
Commenters are asked to describe the nature of any impact and provide empirical data supporting the extent of the impact. Such comments will be considered in the preparation of the Final Regulatory Flexibility Analysis, if we adopt the proposed amendments, and will be placed in the same public file as comments on the proposed amendments themselves.
The amendments described in this release are being proposed under the authority set forth in Section 19 of the Securities Act, Sections 3, 12, 13, 15, 23 and 36 of the Exchange Act, and Sections 3(a) and 404 of the Sarbanes-Oxley Act.
Accountants, Accounting, Reporting and recordkeeping requirements, Securities.
Reporting and recordkeeping requirements, Securities, Small businesses.
Reporting and recordkeeping requirements, Securities.
For the reasons set out in the preamble, the Commission proposes to amend title 17, chapter II, of the Code of Federal Regulations as follows:
1. The authority citation for part 210 continues to read as follows:
15 U.S.C. 77f, 77g, 77h, 77j, 77s, 77z-2, 77z-3, 77aa(25), 77aa(26), 78c, 78j-1, 78
2. Section 210.2-02T is amended by:
a. Removing paragraphs (a) and (b), and redesignating paragraphs (c) and (d) as paragraphs (a) and (b);
b. Revising the date “December 15, 2008” in newly redesignated paragraph (a) to read “December 15, 2009”; and
c. Revising newly redesignated paragraph (b).
The revision reads as follows:
(b) This section expires on June 30, 2010.
2. The authority citation for part 228 continues to read, in part, as follows:
15 U.S.C. 77e, 77f, 77g, 77h, 77j, 77k, 77s, 77z-2, 77z-3, 77aa(25), 77aa(26), 77ddd, 77eee, 77ggg, 77hhh, 77jjj, 77nnn, 77sss, 78
3. Section 228.308T is amended by revising the date “December 15, 2008” in the “Note to Item 308T” to read “March 15, 2009”.
4. The authority citation for part 229 continues to read, in part, as follows:
15 U.S.C. 77e, 77f, 77g, 77h, 77j, 77k, 77s, 77z-2, 77z-3, 77aa(25), 77aa(26), 77ddd, 77eee, 77ggg, 77hhh, 77iii, 77jjj, 77nnn, 77sss, 78c, 78i, 78j, 78
5. Section 229.308T is amended by:
a. Revising the date “December 15, 2008” in the “Note to Item 308T” to read “December 15, 2009”; and
b. Revising the date “June 30, 2009” in paragraph (c) to read “June 30, 2010”.
6. The general authority citation for part 249 is revised to read as follows:
15 U.S.C. 78a
7. Form 20-F (referenced in § 249.220f), Part II, Item 15T is amended by:
a. Revising the date “December 15, 2008” in paragraph (2) to the “Note to Item 15T” to read “December 15, 2009”; and
b. Revising the date “June 30, 2009” in paragraph (d) to read “June 30, 2010”.
The text of Form 20-F does not, and this amendment will not, appear in the Code of Federal Regulations.
8. Form 40-F (referenced in § 249.240f) is amended by:
a. Revising the date “December 15, 2008” in “Instruction 3T(2)” to the “Instructions to paragraphs (b), (c), (d) and (e) of General Instruction B.(6)” to read “December 15, 2009”; and
b. Revising the date “June 30, 2009” in the paragraph following “Instruction 3T” to the “Instructions to paragraphs (b), (c), (d) and (e) of General Instruction B.(6)” to read “June 30, 2010”.
The text of Form 40-F does not, and this amendment will not, appear in the Code of Federal Regulations.
9. Form 10-Q (referenced in § 249.308a) is amended by revising Item 4T to Part I to read as follows:
The text of Form 10-Q does not, and this amendment will not, appear in the Code of Federal Regulations.
(a) If the registrant is neither a large accelerated filer nor an accelerated filer as those terms are defined in § 240.12b-2 of this chapter, furnish the information required by Items 307 and 308T(b) of Regulation S-K (17 CFR 229.307 and 229.308T(b)) with respect to a quarterly report that the registrant is required to file for a fiscal year ending on or after December 15, 2007 but before December 15, 2009.
(b) This temporary Item 4T will expire on June 30, 2010.
10. Form 10-QSB (referenced in § 249.308b) is amended by revising Item 3A(T) to Part I to read as follows:
The text of Form 10-QSB does not, and this amendment will not, appear in the Code of Federal Regulations.
(a) Furnish the information required by Items 307 and 308T(b) of Regulation S-B (17 CFR 228.307 and 228.308T(b)) with respect to a quarterly report that the small business issuer is required to file for a fiscal year ending on or after December 15, 2007 but before October 31, 2008.
11. Form 10-K (referenced in § 249.310) is amended by:
a. Revising the date “December 15, 2008” in paragraph (a) to Item 9A(T) to Part II to read “December 15, 2009”; and
b. Revising the date “June 30, 2009” in paragraph (b) to Item 9A(T) to Part II to read “June 30, 2010”.
The text of Form 10-K does not, and this amendment will not, appear in the Code of Federal Regulations.
12. Form 10-KSB (referenced in § 249.310b) is amended by revising the date “December 15, 2008” in paragraph (a) to Item 8A(T) to Part II to read “March15, 2009”.
The text of Form 10-KSB does not, and this amendment will not, appear in the Code of Federal Regulations.
By the Commission.