Karnal bunt is a fungal disease of wheat ( Triticum aestivum ), durum wheat ( Triticum durum ), and triticale ( Triticum aestivum × Secale cereale ), a hybrid of wheat and rye. Karnal bunt is caused by the smut fungus Tilletia indica (Mitra) Mundkur and is spread by spores, primarily through the movement of infected seed. Our Karnal bunt-related import regulations are contained in Subpart—Wheat Diseases (7 CFR 319.59 through 319.59-2).

On March 3, 2004, we published in the Federal Register (69 FR 9976-9982, Docket No. 02-057-1) a proposal to amend the regulations by listing regions affected with Karnal bunt, as well as articles that would be regulated for Karnal bunt; increasing the flexibility of the regulations so that they could provide more readily for the recognition of areas where Karnal bunt is not known to occur within regions where Karnal bunt is known to be present; describing conditions, including requirements for phytosanitary certificates, under which wheat and related articles from regions affected with Karnal bunt could be imported into the United States; and specifying cleaning and/or disinfection requirements for imported farm machinery and other equipment used to handle or store Karnal bunt-positive seed or host crops. The proposed changes would make our regulations regarding the importation of wheat and related articles from regions affected with Karnal bunt substantively equivalent to our domestic Karnal bunt regulations and would make the former consistent with international agreements to which the United States is a party.

We solicited comments concerning our proposal for 60 days ending May 3, 2004. We received two comments by that date, both from representatives of domestic wheat industry groups. Both commenters were in favor of the proposed rule.

However, one commenter offered suggestions for changes to the background information contained in the preamble of the proposed rule. These suggestions are discussed below.

The commenter noted that the proposed rule's economic analysis mentioned, but did not identify, five durum-producing Mexican States in addition to the States of Sonora and Baja California ( i.e. , the States where the Mexicali Valley, a Karnal bunt-free area already recognized in the regulations, is located). The commenter identified four of the five Mexican States and offered relative per-State percentages for durum production in Mexico and suggested that, due to transportation costs and other considerations within Mexico, more wheat originating in the Mexican State of Sonora may be exported to the United States than had been explored in the economic analysis.

While increased Mexican wheat imports from Mexico may occur, as the commenter suggests, our economic analysis concludes that the effects are likely to be small relative to the value of the domestic industry. The commenter did not provide evidence to the contrary. We are making no changes in response to this comment.

With respect to the five durum-producing Mexican States mentioned but not specifically identified in the proposed rule, we have updated the economic analysis for this final rule to identify these five States, which are Chihuahua, Guanajuato, Jalisco, Michocan, and Queretaro.

The commenter pointed out that Karnal bunt has been reported in additional countries not mentioned in the background information in the preamble of the proposed rule. These countries are Nepal, Iran, and South Africa.

The countries we mentioned in the proposed rule are those countries that have been listed in the wheat import regulations as countries where Karnal bunt is known to exist. In this final rule, we have updated the regulatory text of § 319.59-4(b)(1) to include those additional countries on that paragraph's list of countries where Karnal bunt is known to occur.

In addition to that change, we are also amending the definition of inspector in this final rule to reflect the reassignment of certain responsibilities from the Animal and Plant Health Inspection Service to the Department of Homeland Security's Bureau of Customs and Border Protection by the Homeland Security Act of 2002.

In addition to the changes discussed above, we have also made two other changes in this final rule in order to ensure that the regulations are internally consistent. First, in § 319.59-4(a)(2) of the proposed rule, we listed Triticum spp. (wheat) plants among the articles designated as regulated articles for Karnal bunt, and in paragraph (c) of that section we described the conditions under which regulated articles could be imported from regions where Karnal bunt is known to occur. However, under § 319.59-2(a), the importation of Triticum spp. plants into the United States from any country except Canada is prohibited. In order to avoid any potential confusion between the provisions in §§ 319.59-2 and 319.59-4, we have removed wheat plants from the list of regulated articles for Karnal bunt so it does not appear that wheat plants could be imported into the United States under the conditions described in § 319.59-4(c).

The other change is similar in nature. Specifically, in § 319.59-4(b)(1) we list regions where Karnal bunt is known to occur, and paragraph (c) of that section describes the conditions under which regulated articles, including articles of Triticum spp., could be imported from those regions. However, several of the regions listed in § 319.59-4(b)(1) are also listed in § 319.59-3(b) as regions from which the importation of certain articles, including articles of Triticum spp., is prohibited due to flag smut. In order to prevent a conflict between those two sets of provisions, we have amended the conditions for the importation of regulated articles from regions where Karnal bunt exists (§ 319.59-4[c]) to provide that the regulated articles will be eligible for importation only if they are not otherwise prohibited under § 319.59-3.

Therefore, for the reasons given in the proposed rule and in this document, we are adopting the proposed rule as a final rule, with the changes discussed in this document.

This rule has been reviewed under Executive Order 12866. The rule 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.

This rule amends the import regulations pertaining to Karnal bunt to make them substantively equivalent to the domestic Karnal bunt regulations and will help the United States meet its obligations under international agreements to which it is a party.

For this rule, we have prepared an economic analysis. The economic analysis provides a cost-benefit analysis as required by Executive Order 12866, as well as an analysis of the potential economic effects of this rule on small entities, as required under the Regulatory Flexibility Act. The economic analysis is summarized below. Copies of the full analysis are available by writing or calling the person listed under FOR FURTHER INFORMATION CONTACT .

The economic analysis investigates the potential economic effects in the United States that may result from the removal of Karnal bunt-related restrictions on wheat imports. It is anticipated that any additional wheat imports that do occur as a result of this rule would be from Mexico. There are five Mexican States that appear to meet the requirements in this rule for Karnal bunt-free status. These States are Chihuahua, Guanajuato, Jalisco, Michocan, and Queretaro. The Mexicali Valley in Sonora  1 and Baja California was declared Karnal bunt-free in 1998 and is therefore not directly affected by this rule. Other countries affected with Karnal bunt which may be eligible to export wheat to the United States under the regulations may still be precluded from doing so for a number of reasons, including the presence of other wheat pests.

Any new wheat imports into the United States from Mexico are likely to be durum wheat. In Mexico, demand for durum wheat is limited because the demand for pasta is limited. However, Mexican wheat producers favor durum wheat due to its higher yield and disease resistance, creating a small surplus of durum for export. Mexican wheat exports since 1995 have been almost exclusively durum wheat. Because Mexican wheat exports have been so concentrated in durum wheat, it is expected that any additional imports into the United States from any new Karnal bunt-free areas in Mexico would also be durum wheat. For the period 1998-2001, the annual average durum wheat production in the United States was about 3 million metric tons (MT). Imports of durum wheat from all sources averaged about 458,000 MT. Approximately 2 percent of those imports were from the Karnal bunt-free area of Mexico. 2

Our economic analysis considers two scenarios for expanded U.S. wheat imports from Mexico, assuming no displacement of other imports. The first scenario analyzes the impact of additional Mexican durum wheat exports to the United States of an amount equal to 1 percent of total wheat production in the five additional Mexican States cited previously (about 7,000 MT). This reflects the fact that about 1 percent of the wheat production in the Mexicali Valley, which is already eligible to be shipped to the United States, is indeed exported to the United States. 3 The second scenario analyzes the impact of additional Mexican durum wheat exports of an amount equal to 12 percent of total wheat production in those five States (about 87,000 MT). For the period 1998-2001, Mexican wheat exports to the world represented on average approximately 11.6 percent of total Mexican wheat production annually. 4

There are reasons to believe that new imports would be limited and that the first scenario more closely approximates the amount of Mexican wheat that may eventually enter the U.S. market. Under this scenario, the new imports are estimated to be an addition of 7,280 MT, which approximates the 1 percent share of Mexican wheat production in the Mexicali Valley that was exported to the United States between 1998 and 2001. The Mexicali Valley is one of Mexico's largest wheat producing areas. It is also closer to the United States than the Mexican population centers in central and southern Mexico. Transportation costs to the Mexican population centers from this area are high because rail lines must traverse mountains. Despite the fact that the U.S. market has been open to imports of wheat from this area since 1998, Mexican wheat exports directed to the United States between 1998 and 2001 have averaged less than 5 percent of all Mexican wheat exports.

Another reason to believe that the quantity of new wheat imports from Mexico that may occur as a result of this rule would be small is due to the fact that the five additional Mexican States identified previously are producing less than 25 percent of all Mexican wheat, and little durum wheat. At present, durum wheat production in Mexico is concentrated in the northwestern portion of the country. It has been estimated that 75 percent of Mexican durum wheat production occurs in Sonora, 13 percent in Baja California, and 5 percent in Sinoloa. 5

In addition, Mexico's population consumes far more wheat than the country produces, as is evident in its status as a net importer. The Mexican population is concentrated in the central and southern part of the country. With the exception of Chihuahua, the five Mexican States considered in the analysis are in the central part of Mexico. The transportation of wheat from these States to the United States would be more difficult and more costly than to closer Mexican population centers. This makes it likely that the shift to production for export in the five States will be limited.

The entry of additional durum wheat from Mexico into U.S. markets would induce producer losses for U.S. producers of durum wheat and consumer gains. Under the most likely scenario of new wheat imports of 7,280 MT, and assuming a demand elasticity of −0.35 and a supply elasticity of 0.34, prices of durum wheat could potentially decrease by about 0.3 percent. Producers would potentially lose about $1.122 million while consumers potentially gain $1.123 million. The net benefit in this scenario would be about $1,000. Under the less likely scenario of a new import quantity of approximately 87,000 MT, durum wheat prices could decline by 4 percent. Consumer gains of $13.539 million would offset producer losses of $13.353 million, resulting in a net benefit of $186,000. In both cases, consumer benefits would be slightly higher than producer losses, which would lead to a net positive impact on the overall economy. To put the producer surplus reductions in perspective, the average annual value of durum wheat production in the United States for 1998-2001 was $326.3 million. Thus, while the additional imports from Mexico would affect domestic producers of durum wheat, those effects are expected to be small relative to the value of the industry. It should also be noted that the actual loss to domestic producers is likely to be smaller than the magnitudes estimated, as the analysis does not consider the displacement of other imports.

The Small Business Administration (SBA) has established guidelines for determining which establishments are to be considered small under the Regulatory Flexibility Act. According to the standard established by the SBA for agricultural producers, a producer with less than $0.75 million in annual sales is considered a small entity. Of the 241,334 U.S. wheat farms in 1997, at least 92 percent were considered small. 6 The number of durum wheat producers is not known. It is likely that durum wheat producers affected by the rule would be considered small entities. However, as was discussed above, increased Mexican wheat imports from Mexico would likely have a small adverse impact on domestic producers.

Under these circumstances, the Administrator of the Animal and Plant Health Inspection Service has determined that this action will not have a significant economic impact on a substantial number of small entities.

This final rule has been reviewed under Executive Order 12988, Civil Justice Reform. This rule: (1) Preempts all State and local laws and regulations that are inconsistent with this rule; (2) has no retroactive effect; and (3) does not require administrative proceedings before parties may file suit in court challenging this rule.

In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq. ), the information collection or recordkeeping requirements included in this rule have been approved by the Office of Management and Budget (OMB) under OMB control number 0579-0240.

The Animal and Plant Health Inspection Service is committed to compliance with the Government Paperwork Elimination Act (GPEA), which requires Government agencies in general to provide the public the option of submitting information or transacting business electronically to the maximum extent possible. For information pertinent to GPEA compliance related to this rule, please contact Mrs. Celeste Sickles, APHIS’ Information Collection Coordinator, at (301) 734-7477.

The Department of Agriculture is issuing this rule in conformance with Executive Order 12866.

Executive Order 12988, Civil Justice Reform, instructs each executive agency to adhere to certain requirements in the development of new and revised regulations in order to avoid unduly burdening the court system. The final rule was reviewed under this Executive Order and no additional related information has been obtained since then. This final rule is not intended to have a retroactive effect. The United States Grain Standards Act provides in Section 87g that no State or subdivision may require or impose any requirements or restrictions concerning the inspection, weighing, or description of grain under the Act. Otherwise, this final rule will not preempt any State or local laws, regulations, or policies, unless they present any irreconcilable conflict with this rule. There are no administrative procedures which must be exhausted prior to any judicial challenge to the provisions of this final rule.

The Regulatory Flexibility Act (RFA) (5 U.S.C. 601 et seq.) requires agencies to consider the economic impact of each rule on small entities. GIPSA has determined that this final rule will not have a significant economic impact on a substantial number of small entities, as defined in the Regulatory Flexibility Act. Under the provisions of the United States Grain Standards Act, grain exported from the United States must be officially inspected and weighed. Mandatory inspection and weighing services are provided by GIPSA at 33 export facilities. All of these facilities are owned by multi-national corporations, large cooperatives, or public entities that do not meet the requirements for small entities established by the Small Business Administration. GIPSA is amending the grain standards to change the definition of contrasting classes in Hard Red Winter wheat and Hard Red Spring wheat such that Hard White wheat is not a contrasting class but is considered as wheat of other classes. GIPSA also is amending the grain standards by adding the sample size used to determine sample grade factors, because the standards should transmit this information. The two changes made to the wheat standards in this final rule are needed to ensure market-relevant standards and grades. Further, the regulations are applied equally to all entities.

The U.S. wheat industry, including producers (approximately 240,000), handlers (approximately 6,800 domestic elevators), traders (approximately 200 active wheat futures traders), processors (approximately 184 flour mills), merchandisers, and exporters, are the primary users of the U.S. Standards for Wheat and utilize the official standards as a common trading language to market wheat. We assume that some of the entities may be small. Further, the United States Grain Standards Act (USGSA) (7 U.S.C. 87f-1) requires the registration of all persons engaged in the business of buying grain for sale in foreign commerce. In addition, those individuals who handle, weigh, or transport grain for sale in foreign commerce must also register. The USGSA regulations (7 CFR 800.30) define a foreign commerce grain business as persons who regularly engage in buying for sale, handling, weighing, or transporting grain totaling 15,000 metric tons or more during the preceding or current calendar year. At present, there are 90 registrants who account for practically 100 percent of U.S. wheat exports, which for fiscal year (FY) 2002 totaled approximately 24,073,138 metric tons (MT). While most of the 90 registrants are large businesses, we assume that some may be small.

Pursuant to the Paperwork Reduction Act of 1995, the existing information collection requirements are approved under OMB Number 0580-0013. No additional collection or recordkeeping requirements are imposed on the public by this final rule. Accordingly, OMB clearance is not required by section 350(h) of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. , or OMB's implementing regulation at 5 CFR part 1320.

GIPSA is committed to compliance with the Government Paperwork Elimination Act, which requires Government agencies, in general, to provide the public the option of submitting information or transacting business electronically to the maximum extent possible.

GIPSA established the class Hard White wheat on May 1, 1990. In the Final Rule (54 FR 48735), GIPSA stated “that classification by varietal kernel characteristics rather than vitreousness of the kernel is practicable at this time for HWW (sic) and SWW (sic) since only a few hard endosperm white * * * varieties are being produced. GIPSA recognizes that if more hard endosperm varieties are released into the marketplace in the future, the classification system may become less practical.” GIPSA further stated “* * * if clear quality or market distinctions develop * * * it would consider subclasses at a future date”. At that time, a minimum visual color line was established, which was subsequently replaced with a new color line in 1999 (Program Bulletin 99-8). In 2001, environmental conditions caused a darker visual appearance in some varieties of hard white, resulting in a GIPSA decision to suspend the color line for classification purposes (Program Notice 01-06). Under Program Notice 01-06, “All Hard White wheat varieties are considered Hard White wheat regardless of color.”

On June 4, 2003, GIPSA proposed in the Federal Register , (68 FR 33408) to amend the standards for wheat to create subclasses in the class hard white. GIPSA proposed the subclass names of Hard White wheat and Hard Amber White wheat, for wheat meeting and exceeding (darker than) the interpretive color line, respectively. Further, GIPSA proposed changing the definition of Contrasting Classes for Hard Red Winter wheat and Hard Red Spring wheat such that Hard White wheat is not a contrasting class in these two red wheat classes. Further, due to inquiries about the portion size used to determine Maximum Count Limits of Other Material, GIPSA proposed amending the standard to transmit this information.

GIPSA published the proposed rule in the Federal Register on June 4, 2003 (68 FR 33408) with a 60-day comment period ending August 4, 2003. GIPSA received four comments during the comment period. One comment was submitted on behalf of the Hard White Wheat Working Group and the Hard White Wheat Advisory Committee (an aggregated wheat industry group comprised of wheat boards, committees, or commissions of the top ten Hard White wheat producing states; large grain merchandisers; not for profit wheat industry groups; and a private wheat breeding company). One comment each was received from the Kansas Wheat Commission, one wheat producer cooperative, and one individual wheat producer.

On the basis of the comments received and other available information, GIPSA is implementing two of the proposed changes to the wheat standards. The following paragraphs address comments received regarding the proposed changes.

GIPSA received four comments (one aggregated industry comment in support and three comments in opposition) on the proposal to establish subclasses. The aggregated wheat industry comment supported subclasses. This commenter did note that the proposal concerning adding a subclass to the Hard White wheat class was met with a spirited discussion, both pro and con. The commenter (1) supported the establishment of a subclass within the Hard White Wheat class; (2) recommended changing the subclass names to Bright Hard White Wheat for all hard white wheat that is equal to or lighter than the interpretive color line and Hard White Wheat for all hard white wheat that is darker than the interpretive color line, and continue the use of an interpretive color line and (3) recommended the use of an objective test to determine color line rather than a subjective approach.

One comment opposed to establishment of subclasses in Hard White wheat was received from the Kansas Wheat Commission which represents producers responsible for production of more than 50 percent of all Hard White wheat grown in the United States. The comment stated that since Hard White wheat is moving in the marketplace under the current method of grading, establishing a subclass would create a perception that wheat does not meet the established color line is of lower quality, resulting in discounts to producers. The commenter stated that establishing a subclass would create supply problems in Hard White wheat and also objected to the word “Amber” in the subclass name.

Another opposing commenter felt that because the color differences are environmentally induced, and occur sporadically, grain producers and marketers would be damaged by subclasses, vis-à-vis not having product available to sell to the markets they had worked to develop. Another comment opposing the proposed rule predicted “marketing disruption and chaos resulting in economic loss to American wheat producers is the inevitable result whenever Mother Nature gives us a darker colored crop if these arbitrary rule changes are allowed to become law”.

Taking into account the lack of consensus among stakeholders, GIPSA believes that creating subclasses in Hard White wheat would not be in the best interest of the industry. There is no market need at this time. Based on the comments received and other available information, GIPSA will not establish subclasses in Hard White wheat. GIPSA will, however, maintain the Hard White wheat color line and, as currently done, continue to certify, upon request, that the sample color exceeds or is lighter than the color line. This provides additional information about sample color to satisfy those customers for whom color is important.

GIPSA proposed changing the definition of Contrasting Classes for Hard Red Winter wheat and Hard Red Spring wheat such that Hard White wheat is not a contrasting class in these two red wheat classes. One comment was received from the aggregated industry group in support of the proposal. No comment was received opposing the proposal. Therefore as set forth in the proposal, GIPSA is amending the grain standards to change the definition of contrasting classes in Hard Red Winter wheat and Hard Red Spring wheat such that Hard White wheat is not a contrasting class but is considered as wheat of other classes. The grade limit will remain unchanged. For kernel identification, Hard White wheat kernels would be determined by visual assessment and would include the dark colored, amber, white wheat kernels, per the Grain Inspection Handbook, Book II, Chapter 13, Section 13.26. In the case where samples challenge the normal visual inspection process, the alkali test would be utilized to determine kernel color (FGIS-Program Notice 01-07).

GIPSA proposed to amend the wheat standard to specify the amount of wheat upon which sample grade factor determinations are made. No comment was received either supporting or opposing the proposal. Earlier versions of the standard contained this information and GIPSA believes the standard should transmit this information. Therefore, as set forth in the proposal, GIPSA will amend the wheat standards to include this information.

On the basis of these comments and other available information, GIPSA has decided to revise the wheat standards as proposed with the exception of establishing subclasses in Hard White wheat. This final rule is effective on May 1, 2006, the beginning of the 2006 wheat harvest, and will facilitate domestic and export marketing of wheat.

The Administrator may impose a civil penalty against a person other than an individual acting as a pilot, flight engineer, mechanic, or repairman, after notice and an opportunity for a hearing on the record, for violations cited in 49 U.S.C. 46301(d)(2) or 47531. 49 U.S.C. 46301(d)(7)(A) and 47531. These violations, in general, involve aviation safety issues. Also, under 49 U.S.C. 5123 and 49 CFR 1.47(k), the Administrator may, after notice and an opportunity for a hearing, assess a civil penalty against any person who knowingly violates the Federal hazardous materials transportation law, 49 U.S.C. chapter 51, or any of its implementing regulations.

The rules governing proceedings in these civil penalty cases are set forth in 14 CFR 13.16 and 14 CFR part 13, subpart G. Briefly, under these rules, these proceedings are conducted “in-house” as follows: (1) An “agency attorney” prosecutes a civil penalty case (14 CFR 13.203(a)); (2) a DOT ALJ conducts the hearing and issues an initial decision (14 CFR 13.205); and (3) the Administrator, acting as the FAA decisionmaker, issues a decision resolving any appeal from an initial decision (14 CFR 13.233).

To ensure that this process operates fairly and in accordance with the Administrative Procedure Act (APA), 5 U.S.C. 554(d), the FAA has issued rules requiring a separation of the functions performed by (1) “agency attorneys,” who prosecute civil penalty actions, and (2) attorneys who advise the Administrator on appeals from initial decisions. Separating these functions insulates the Administrator from any advice or influence by an FAA employee engaged in the investigation or prosecution of civil penalty actions. It also insulates the prosecutors from possible influence by the advisers to the Administrator on appeals.

On March 3, 2004, the FAA published Notice 1100.290, announcing the creation of two Deputy Chief Counsel positions: the Deputy Chief Counsel for Policy and Adjudication, and the Deputy Chief Counsel for Operations. As a result, it s no longer accurate to refer only to the “Deputy Chief Counsel” in the rules that provide for the separation of functions in the Chief Counsel's Office, 14 CFR 13.202 (Definition of agency attorney) and 13.203.

To describe accurately the current division of functions within the Chief Counsel's Office, we are revising the rules to add: (1) The Deputy Chief Counsel for Operations to the list of attorneys who prosecute civil penalty actions as specified in 14 CFR 13.202's definition of “agency attorney,” and (2) the Deputy Chief Counsel for Policy and Adjudication to 14 CFR 13.203(c)'s list of lawyers who advise the Administrator regarding the resolution of appeals. We are also revising 14 CFR 13.202 to add the Deputy Chief Counsel for Policy and Adjudication to the list of attorneys who may not prosecute civil penalty actions.

Under the current organization of the Chief Counsel's Office, the Deputy Chief Counsel for Policy and Adjudication supervises the Assistant Chief Counsel for Regulations. The Assistant Chief Counsel for Regulations and members of her staff occasionally provide advice to agency attorneys, but are otherwise uninvolved in prosecuting civil penalty cases. The Deputy Chief Counsel for Policy and Adjudication does not and will not supervise the Assistant Chief Counsel for Regulations or any member of her staff in connection with providing advice to an agency attorney engaged in the prosecution of any civil penalty case. The Assistant Chief Counsel for Regulations and the members of her staff do not and shall not consult or discuss with the Deputy Chief Counsel for Policy and Adjudication any issue on which their advice is sought by an agency attorney. Thus, the Deputy Chief Counsel for Policy and Adjudication will be kept “out of the loop” when either the Assistant Chief Counsel for Regulations or an attorney on her staff is consulted by agency attorneys prosecuting a civil penalty action. As a result, this division of functions within the Office of the Chief Counsel does not, and will not, contravene 14 CFR 13.202(3), which provides that an attorney supervised in a civil penalty action by an adviser to the Administrator in that civil penalty (or a factually related) action shall not prosecute that action.

Also, to ensure that the Assistant Chief Counsel for Regulations and her staff do not prosecute civil penalty cases but limit their role to that of occasional advisors to agency attorneys, we are revising the definition of “agency attorney” in Section 13.202 to omit the Assistant Chief Counsel for Regulations, as well as attorneys in the Regulations Division. This revision will make the rule consistent with the current practice within the Office of the Chief Counsel. Also, this revision will make 14 CFR 13.202's list of attorneys who may prosecute civil penalty actions consistent with the Administrator's current delegation of authority in civil penalty actions in 14 CFR 13.16(e) to certain FAA attorneys. The Assistant Chief Counsel for Regulations and members of her staff are not included in the list of attorneys to whom the Administrator has delegated the authority to (1) Initiate actions and assess civil penalties; (2) refer cases to the United States Attorney General or a delegate of the Attorney General for collecting civil penalties; and (3) compromise the amount of a civil penalty.

The position of the Special Counsel and Director of Civil Penalty Adjudications was eliminated several years ago. As a result, we are removing all references to this position in 14 CFR 13.202 and 13.203.

The FAA Civil Penalty Hearing Docket is now located in Room 2014 of the Wilbur Wright Building, 600 Independence Avenue, SW., Washington, DC 20591. Anyone hand-delivering a document for filing—or wishing to review any docket materials in person—should go to the Wilbur Wright Building at the above address. Packages sent by expedited courier to the Hearing Docket should be addressed as follows: Hearing Docket, Federal Aviation Administration, 600 Independence Avenue, SW., Wilbur Wright Building—Room 2014, Washington, DC 20591; Att: Hearing Docket Clerk, AGC-430.

All envelopes and packages sent by U.S. Mail to individuals in the Wilbur Wright Building are processed by the FAA Headquarters' mail room staff located at 800 Independence Avenue, SW., Washington, DC 20591. Consequently, anyone using U.S. Mail to file a document should use the following address: Hearing Docket, Federal Aviation Administration, 800 Independence Avenue, SW., Washington, DC 20591; Att: Hearing Docket Clerk, AGC-430, Wilbur Wright Building—Room 2014.

Accordingly, this amendment revises the following regulations: 14 CFR 13.16(h) (filing a request for hearing); 14 CFR 13.209 (filing an answer); 14 CFR 13.210 (filing documents, generally); 14 CFR 13.230(b) (examination and copying of the record); and 14 CFR 13.233 (filing appeals from initial decisions).

The Secretary of Transportation directed the Office of the Secretary and eight of the DOT operating administrations, including the FAA, to consolidate their separate paper-based docket facilities into a single centralized facility and convert to an electronic image-based system. 61 FR 29282, June 10, 1996. Documents in non-security civil penalty cases (governed by the procedural rules in 14 CFR part 13, subpart G) in which the complaint was filed on or after December 1, 1997, have been scanned into the Docket Management System (DMS). 63 FR 19559, 19570-19571, April 20, 1998. (The Hearing Docket remains the official docket, and continues to retain the original documents.) The documents in these civil penalty cases are available on the Internet at http://dms.dot.gov . While the availability of these documents on the Internet was announced in the Federal Register on April 20, 1998, 14 CFR part 13, subpart G was not amended to reflect the availability of documents on the DMS website. The FAA is adding a new 14 CFR 13.210(e) to inform the parties about the availability of documents through the DMS website. Also, we are revising 14 CFR 13.230 to notify members of the public that they may review and copy the documents in the record at the Docket Management Facility, located on the Plaza Level of the Nassif Building at the U.S. Department of Transportation, 400 Seventh Street, SW., Room PL-401, Washington, DC 20590.

The decisions of the Administrator, indexes of the decisions, and other useful information are available on the FAA civil penalty adjudication Web site at http://www.faa.gov/agc/cpwebsite. The new Section 13.210(e) also describes the FAA civil penalty adjudication Web site.

Part 14 of Title 14 of the Code of Federal Regulations applies to actions under the EAJA. Originally 14 CFR 14.28 provided that either the applicant or the FAA counsel may appeal from the initial decision issued by an ALJ regarding an application for fees under the EAJA in a civil penalty proceeding under subpart G of part 13 of the Federal Aviation Regulations. When 14 CFR 14.28 was revised in 1999, creating paragraphs (a) and (b), the phrase “in accordance with subpart G of part 13 of the Federal Aviation Regulations, specifically 14 CFR 13.233” was inadvertently omitted from the new paragraph (a). 64 FR 32936, June 18, 1999. This amendment reinserts the language. By reinserting this phrase, it will be clear to the parties that the procedural rules in 14 CFR part 13, subpart G, govern any appeal from an initial decision concerning a fee application under the EAJA when the underlying action was governed by 14 CFR part 13, subpart G.

In general, under the APA, 5 U.S.C. 553, agencies must publish regulations for public comment and give the public at least 30 days notice before adopting regulations. There is an exception to these requirements if the agency for good cause finds that notice and public procedure are impracticable, unnecessary, or contrary to the public interest. In this case, the FAA finds that notice and comment requirements are unnecessary due to the administrative nature of the changes. The revisions simply update 14 CFR 13.202 and 13.203 regarding recent office changes. It is in the public interest that these revisions take effect promptly so that members of the public will understand how the FAA does business. Also, it is in the public interest that the revisions to 14 CFR 13.16, 13.209, 13.210, 13.230 and 13.233 take effect promptly so that members of the public know how to file documents and how to gain access to the Hearing Docket. The revision to 14 CFR 14.28(a) merely reinserts language that was inadvertently omitted during a previous revision. The amendments set forth in this notice do not affect the rights or duties of any regulated entity.

The FAA proposed to amend 14 CFR Part 39 with an AD for certain Boeing Model 747-400, -400D, and -400F series airplanes. That action, published in the Federal Register on September 7, 2004 (69 FR 54060), proposed to require replacing at least one flap control unit (FCU) in the main equipment center with a new or modified FCU.

We provided the public the opportunity to participate in the development of this AD. We have considered the comments that have been submitted on the proposed AD.

One commenter agrees with the proposed AD.

One commenter requests that the compliance time specified in paragraph (f)(1) of the proposed AD be reduced. The commenter states that the 60-month compliance time is too long and should be shortened substantially due to the potential severity of the situation ( i.e. , landing without flaps) and the nature of the proposed modifications. The commenter believes that the availability of parts necessary to complete the modifications is not an issue.

The FAA does not agree to reduce the compliance time specified in paragraph (f)(1) of the final rule. In developing the compliance time for this AD, we considered the average utilization rate of the affected fleet, the practical aspects of an orderly modification of the fleet during regular maintenance periods, and the availability of required parts as well as the safety implications of the identified unsafe condition. In addition, the low probability of the identified unsafe condition occurring (disengagement of all three flap control units (FCU) causing loss of primary flaps control and flaps indication display) and the existing operational manual bulletin that provides guidance to the crew for extending the flaps in alternate mode in the absence of indication are consistent with longer compliance times. Based on these factors, the proposed compliance time of 60 months after the effective date of the final rule was determined to be appropriate. Further, we arrived at the proposed compliance time with manufacturer concurrence. We have not changed the final rule in this regard.

One commenter requests that paragraph (g) of the proposed AD be removed. The commenter states that paragraph (g) of the proposed AD would require actions specified in Boeing Service Bulletin 747-27-2319, dated January 24, 1991, to be done before or concurrently with paragraph (f) of the proposed AD. The commenter notes that the actions in paragraph (f) of the proposed AD are to be done according to Boeing Alert Service Bulletin 747-27A2386, dated March 13, 2003, and that the alert service bulletin specifies in paragraph 1.B. that “you cannot make the changes in this service bulletin unless the changes given in Boeing Service Bulletin 747-27-2319 are made.” Thus, the commenter believes there is no need for paragraph (g) of the proposed AD.

We do not agree to remove paragraph (g) of the final rule. We agree that paragraph (f) of the final rule requires the actions to be done “in accordance with the Accomplishment Instructions of Boeing Alert Service Bulletin 747-27A2386, dated March 13, 2003” and that paragraph 1.B. of the alert service bulletin refers to the concurrent actions that are specified in paragraph (g) of the final rule. However, paragraph 1.B. of the alert service bulletin precedes the Accomplishment Instructions of the alert service bulletin. Because the Accomplishment Instructions of the alert service bulletin do not specify to do any concurrent action, paragraph (g) of the final rule is needed to clarify that the concurrent action must be done. We have not changed the final rule in this regard.

One commenter points out that paragraph 3.B.2. of the Boeing Alert Service Bulletin 747-27A2386 specifies that a built-in test equipment (BITE) test be done according to Chapter 27-51-51 of the Boeing 747-400 airplane maintenance manual (AMM). The commenter notes that there is no BITE test in either 27-51-00/501 or 27-51-51/401 of the Boeing 747-400 AMM. The commenter contends the alert service bulletin refers to a test that does not exist and is not necessary. The commenter also states that the alert service bulletin specifies installing the FCU in accordance with Chapter 27-51-51 of the Boeing 747-400 AMM and that the referenced AMM specifies to do an operational test of the FCU that includes both a central maintenance computer initiated ground test and exercising the flaps through full travel to ensure proper operation and indication.

We infer from the comment that the commenter requests that the reference to the BITE test be clarified. We partially agree. We acknowledge that paragraph 3.B.2. of the alert service bulletin specifies a BITE test be done according to Chapter 27-51-51 of the Boeing 747-400 AMM. However, Chapter 27-51-51 of the Boeing 747-400 AMM refers to a BITE test only in the summary of the AMM procedure, but not within the body of the AMM procedure. Within the body of the AMM procedure, there is a “GROUND TEST,” under the heading “OPERATIONAL TEST,” that is to be done following installation of the FCU. Although the nomenclature within the Boeing documents may seem inconsistent, we consider the “GROUND TEST” specified in Chapter 27-51-51 of the Boeing 747-400 AMM to be part of the FCU BITE test. Furthermore, Chapter 27-51-51 of the Boeing 747-400 AMM includes all necessary testing that must be done following installation of a new FCU. In addition, because the final rule references only the alert service bulletin, there is no need to add a clarification of the BITE test to the final rule. We have not changed the final rule in this regard.

We have carefully reviewed the available data, including the comments that have been submitted, and determined that air safety and the public interest require adopting the AD as proposed.

There are about 614 airplanes of the affected design worldwide. This AD will affect about 87 airplanes of U.S. registry. The following tables provide the estimated costs for U.S. operators to comply with this AD.

Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, Section 106, describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the Agency's authority.

We are issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, Section 44701, “General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.

We have determined that this AD will not have federalism implications under Executive Order 13132. This AD will not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.

For the reasons discussed above, I certify that this AD:

(1) Is not a “significant regulatory action” under Executive Order 12866;

(2) Is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and

(3) Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

We prepared a regulatory evaluation of the estimated costs to comply with this AD. See the ADDRESSES section for a location to examine the regulatory evaluation.

The FAA proposed to amend 14 CFR part 39 with an AD for all Dassault Model Falcon 10 series airplanes. That action, published in the Federal Register on September 28, 2004 (69 FR 57886), proposed to require a temporary change to the airplane flight manual (AFM) to provide procedures to the flightcrew for touchdown using the main landing gear to avoid a three-point landing. That action also proposed to require repetitive inspections of the piston rod of the drag strut actuator of the nose landing gear (NLG) for cracks, which would terminate the AFM revision, and corrective actions if necessary. In addition, the proposed AD provided a terminating modification, which would end the repetitive inspections.

We provided the public the opportunity to participate in the development of this AD. We have considered the comments that have been submitted on the proposed AD.

One commenter requests that the proposed AD be revised to allow operators to replace a cracked drag strut actuator with an actuator having the same part number. The commenter states that this should be allowed only once, and that the operators would still have to perform the repetitive inspections specified in paragraph (h)(2) of the proposed AD. The commenter is concerned that there may be a shortage of new, improved drag strut actuators since the parallel French airworthiness directive, 2002-137(B), dated March 20, 2002, does not mandate the replacement of a cracked drag strut actuator with a new, improved actuator.

We agree with the commenter's request. We have revised paragraph (h)(1) of this AD to specify that operators may replace a cracked drag strut actuator with a part having the same part number, or do the terminating modification specified in paragraph (i) of this AD.

Two commenters, the airplane manufacturer and one of its subsidiaries, request that paragraph (m) of the proposed AD be revised to specify that only drag strut actuators, part number (P/N) 747721, that fail an ultrasonic inspection as specified in paragraph (h) of the proposed AD may not be reinstalled on the airplane. Specifically, the commenters request to include the text “* * * which has failed the ultrasonic inspection of the piston rod for cracks in accordance with Dassault Service Bulletin F10-294, dated March 20, 2002.” The commenters state that if the piston rod passes an ultrasonic inspection it is acceptable to the airplane manufacturer to allow that drag strut actuator to remain in service on the airplane. The commenters note that, after reading paragraph (m) of the proposed AD, a person could conclude that it is unacceptable to reinstall any drag strut actuator, P/N 747721, if the actuator is removed from the airplane for any reason. One of the commenters states that the additional text is necessary to ensure a suitable number of spare parts are available to operators upon publication of the AD.

We agree with the intent of the commenters' requests. Instead of revising the Parts Installation paragraph included in the proposed AD, we are omitting that paragraph from this AD.

We have carefully reviewed the available data, including the comments that have been submitted, and determined that air safety and the public interest require adopting the AD with the changes described previously. We have determined that these changes will neither increase the economic burden on any operator nor increase the scope of the AD.

This AD affects about 154 airplanes of U.S. registry.

The AFM revision takes about 1 work hour per airplane, at an average labor rate of $65 per work hour. Based on these figures, the estimated cost of the AFM revision required by this AD for U.S. operators is $10,010, or $65 per airplane.

The inspection takes about 1 work hour per airplane, at an average labor rate of $65 per work hour. Based on these figures, the estimated cost of the inspection required by this AD for U.S. operators is $10,010, or $65 per airplane, per inspection cycle.

Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, Section 106, describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the Agency's authority.

We are issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, Section 44701, “General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.

We have determined that this AD will not have federalism implications under Executive Order 13132. This AD will not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.

For the reasons discussed above, I certify that this AD:

(1) Is not a “significant regulatory action” under Executive Order 12866;

(2) Is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and

(3) Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

We prepared a regulatory evaluation of the estimated costs to comply with this AD. See the ADDRESSES section for a location to examine the regulatory evaluation.

This amendment to part 97 of the Federal Aviation Regulations (14 CFR part 97) establishes, amends, suspends, or revokes Standard Instrument Approach Procedures (SIAPs). The complete regulatory description of each SIAP is contained in official FAA form documents which are incorporated by reference in this amendment under 5 U.S.C. 552(a), 1 CFR part 51, and § 97.20 of the Federal Aviation Regulations (FAR). The applicable FAA Forms are identified as FAA Forms 8260-3, 8260-4, and 8260-5. Materials incorporated by reference are available for examination or purchase as stated above.

The large number of SIAPs, their complex nature, and the need for a special format make their verbatim publication in the Federal Register expensive and impractical. Further, airmen do not use the regulatory text of the SIAPs, but refer to their graphic depiction on charts printed by publishers of aeronautical materials. Thus, the advantages of incorporation by reference are realized and publication of the complete description of each SIAP contained in FAA form documents is unnecessary. The provisions of this amendment state the affected CFR (and FAR) sections, with the types and effective dates of the SIAPs. This amendment also identifies the airport, its location, the procedure identification and the amendment number.

This amendment to part 97 is effective upon publication of each separate SIAP as contained in the transmittal. Some SIAP amendments may have been previously issued by the FAA in a National Flight Data Center (NFDC) Notice to Airmen (NOTAM) as an emergency action of immediate flight safety relating directly to published aeronautical charts. The circumstances which created the need for some SIAP amendments may require making them effective in less than 30 days. For the remaining SIAPs, an effective date at least 30 days after publication is provided.

Further, the SIAPs contained in this amendment are based on the criteria contained in the U.S. Standard for Terminal Instrument Procedures (TERPS). In developing these SIAPs, the TERPS criteria were applied to the conditions existing or anticipated at the affected airports. Because of the close and immediate relationship between these SIAPs and safety in air commerce, I find that notice and public procedure before adopting these SIAPs are impracticable and contrary to the public interest and, where applicable, that good cause exists for making some SIAPs effective in less than 30 days.

The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. It, therefore—(1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. For the same reason, the FAA certifies that this amendment will not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

From time-to-time the Bureau of Industry and Security (BIS) reviews portions of the Export Administration Regulations (EAR) and identifies omissions, unnecessary language, obsolete provisions, and provisions for which clarification is desirable. This rule is the product of such a review; it clarifies, updates, and revises the EAR. It does not make substantive changes to the provisions and requirements of the EAR. In brief, this rule:

• Updates the description of BIS's general plan of organization in § 730.9;

• Revises and shortens the description of the scope of the Commerce Country Chart in § 738.3(a);

• Clarifies availability of License Exception TMP for exhibition and demonstration in Country Group D:1;

• Clarifies availability of License Exception TMP for reexports of kits of replacement parts to Country Group D:1;

• Adds the Under Secretary for Industry and Security as an official who may determine whether information subject to § 12(c) of the Export Administration Act may be released to the public in conformance with the applicable Departmental Organization Order;

• Removes an unnecessary statement about responsibility to classify items from § 748.3(a);

• Revises the description of emergency processing of license applications to conform to current agency practice;

• Redesignates two paragraphs in § 748.11 to conform to the standard Code of Federal Regulations structure;

• Corrects a citation to the recordkeeping requirements pertaining to certificates or other documents obtained in connection with exports subject to the Inter-American Firearms Convention;

• Sets the value of aircraft and vessels on temporary sojourn to $0 for license application purposes to prevent confusing statistical values of items licensed for export to embargoed destinations;

• Revises the titles of the head and deputy head of BIS in part 756 (Appeals) to conform to the currently applicable Departmental Organizational Orders;

• Corrects a citation error in the prohibition against concealment or misrepresentation of facts and adds another citation to clearly distinguish the export control documents from the boycott report documents that are subject to § 764.2(g);

• Revises the title of the head of BIS in part 766 (Administrative Enforcement Proceedings) to conform to the currently applicable Departmental Organizational Orders;

• Revises the address for filing papers in administrative enforcement proceedings;

• Revises the definition of the term “controlled country” to make clear that controlled countries are countries subject to national security export controls, to add two previously omitted countries, and to reflect the shift of North Korea from Country Group E:2 to D:1;

• Removes a reference to a no longer existent technical note and corrects the name of another document referenced in ECCN 1C018; and

• Revises the ECCN 3A001 License Exceptions paragraph to exclude certain commodities controlled for missile technology reasons consistent with § 740.2(a)(5).

The above-referenced changes are described in detail below.

Section 730.9 of the EAR describes BIS's general plan of organization. This rule revises § 730.9 to reflect the current organization of the Bureau. Revised § 730.9 incorporates references to government Web sites as the sources of detailed information about BIS and its constituent units.

Section 738.3(a) describes the scope of the Commerce Country Chart. Prior to publication of this rule, § 738.3(a) stated that only two instances existed in which the Country Chart could not be used in the process of determining license requirements based on the reasons for control expressed in Export Control Classification Numbers (ECCN) on the Commerce Control List; short supply items, and “Unique entries”. The section then listed the ECCNs that were “unique.” Since the time that § 738.3 was initially written, the Commerce Control List has been revised in ways that make that description inaccurate. The number of ECCNs that contain, in their license requirements sections, license requirements that are not related to the Country Chart has grown. In some ECCNs, these license requirements are in lieu of Country Chart license requirements. In other ECCNs, these license requirements are in addition to Country Chart license requirements. In addition, some ECCNs now serve as cross references to the license requirements of other government agencies. This rule clarifies and shortens § 738.3 by providing a more general description of when the Country Chart is needed to determine, in whole or in part, license requirements and by eliminating references to specific ECCNs.

On August 10, 2001, BIS published a rule revising the exhibition and demonstration provisions of License Exception TMP (§ 740.9(a)(2)(iii) of the EAR) to expand the scope of permissible destinations for such exhibitions and demonstrations from Country Group B to all destinations not in Country Group E:1. When publishing that rule, BIS stated that it “expands the scope of eligible countries for License Exception TMP for exhibition and demonstration by making Country Group D:1 eligible for this provision” ( see 66 FR 42108, August 10, 2001). However, that rule did not revise § 740.9(a)(3)(i)(B) of the EAR, which prohibits use of License Exception TMP for destinations in Country Group D:1 unless excepted in that paragraph. This rule adds an exception to § 740.9(a)(3)(i)(B) covering exhibition and demonstration of commodities and software authorized under § 740.9(a)(2)(iii), making the former consistent both with the latter and with BIS's published statement concerning the effect of the rule published on August 10, 2001.

Section 740.9(a)(2)(ii) authorizes exports and reexports of kits of replacement parts under License Exception TMP to all destinations except those in Country Group E:1. However, prior to publication of this rule, § 740.9(a)(3)(i)(B)( 3 ), which provides an exception to the prohibition of use of License Exception TMP for shipments of kits of replacement parts to destinations in Country Group D:1, referred only to exports. This rule adds the phrase “or reexported” to § 740.9(a)(3)(i)(B)( 3 ), making it consistent with § 740.9(a)(2)(ii).

This rule revises § 748.1(c) to list the Under Secretary for Industry and Security as an official upon whose determination BIS will release information that is subject to § 12(c) of the Export Administration Act (EAA) to the public. Section 12(c) of the EAA sets forth the criteria for public release of information obtained for purposes of considering or concerning export license applications. Section 12(c) designates the Secretary of Commerce as the official in the Executive Branch who has authority to determine whether a release of information that is subject to § 12(c) of the EAA is in the national interest. In Department of Commerce Departmental Organization Order (DOO) 10-16, the Secretary of Commerce designates the Under Secretary for Industry and Security, formerly the Under Secretary for Export Administration, to exercise this authority. This rule revises § 748.1(c) to reflect the requirements of DOO 10-16.

Section 748.3 describes the procedures for requesting BIS to classify items that are subject to the EAR and for requesting advisory opinions from BIS. This rule removes the phrase “In light of your responsibility to classify your item” from the first sentence of § 743.3(a) because the phrase has no relevance to EAR procedures for requesting BIS to perform the classification.

Section 748.4(h) describes procedures for requesting emergency treatment of license applications and BIS's policy for dealing with those requests. Prior to publication of this rule, that section set forth some procedures that BIS no longer requires to be followed. Moreover, in accordance with Executive Order 12981, as amended by Executive Orders 13020, 13026, and 13117, BIS may not unilaterally issue emergency licenses if the application must be reviewed by other government agencies. This rule revises § 748.4(h) to describe BIS's current practice of giving applications expedited review and requesting the other reviewing agencies to do likewise when BIS determines that expedited review is appropriate.

This rule redesignates § 748.11(e)(4)(ii)( 1 ) and ( 2 ) as § 748.11(e)(4)(ii)(A) and (B) respectively.

Section 748.14 of the EAR requires, inter alia , that applicants for licenses to ship certain firearms and related items to destinations in countries that are members of the Organization of American States obtain and retain an import certificate or equivalent original document. This rule corrects one sentence in § 748.14(b) to state that the recordkeeping provisions of Part 762, rather than only § 762.2, apply to the Firearms Convention certificate requirement. Section 762.2 is merely a list of records that must be kept. The complete recordkeeping requirements are set forth in the whole of Part 762.

The departure of a vessel or aircraft from the United States is, under the EAR, an export of that aircraft or vessel. If the vessel or aircraft is traveling, even temporarily, from the United States to a destination for which it would require an export license and no license exception is available, a license is required for the export of the vessel or aircraft in addition to any licenses that may be required for its cargo. License applicants are required to state the value of the export on license applications. To date, this provision has required applicants seeking licenses for vessels or aircraft on temporary sojourn to estimate the value of the vessel or aircraft even though the value is irrelevant to determining the outcome of the application. In addition, these values can create a misleading impression in BIS's annual licensing statistics as readers who may be unaware of the requirement to license these temporary exports erroneously conclude that BIS has licensed large volumes of aircraft and vessels for permanent export to embargoed destinations. This rule addresses both problems by adding a new paragraph (u) to supplement No. 2 to part 748, instructing the applicant to declare the value of the aircraft or vessel as $0 on applications to send vessels or aircraft on temporary sojourn. This rule also adds a reference to that new paragraph (u) in § 748.8, which contains references to all of the “unique license requirements” in Supp. No.2 to Part 748.

Part 756 describes the procedures for appealing certain administrative actions to the head of BIS. This rule revises the titles of “Under Secretary for Export Administration” and “Deputy Under Secretary for Export Administration” to read “Under Secretary for Industry and Security” and “Deputy Under Secretary for Industry and Security,” respectively in § 756.2. This change conforms the titles in § 756.2 to those in the Department of Commerce Departmental Organizational Orders 10-16 and 50-1, as amended, dated March 19, 2004.

Section 764.2(g)(1)(ii) prohibits falsifying, misrepresenting, or concealing material facts in export control documents and boycott reports. Prior to publication of this rule, that section referenced § 760.6 of the EAR for the definition of boycott reports. Section 760.6 does not exist. This rule adds to § 764.2(g)(1)(ii) a reference to the definition of export control documents found in § 772.1. This rule also revises a sentence in § 764.2(g)(1)(ii) to clarify the definition of boycott reports by referring to such reports as “reports filed or required to be filed pursuant to § 760.5 of the EAR.”

Section 766.2 defines certain terms that are used in administrative enforcement proceedings under the EAR. Prior to publication of this rule, three of those definitions, “initial decision,” “recommended decision,” and “Under Secretary” referred to the Under Secretary for Export Administration. This rule revises the title of the Under Secretary in those definitions to read the “Under Secretary of Commerce for Industry and Security,” pursuant to the title established in the Department of Commerce Departmental Organizational Orders 10-16 and 50-1, as amended, dated March 19, 2004.

Section 766.5 sets forth an address for filing papers in administrative enforcement proceedings. This rule replaces the obsolete address in § 766.5 with the current address for filing papers with the administrative law judge.

Section 772.1 of the EAR defines many terms used in the regulations, including the term “controlled country.” Under this definition, the term “controlled country” refers to destinations to which BIS applies Commerce Control List based national security controls. All such destinations, except Cuba, are listed in Country Group D:1. Prior to publication of this rule, two destinations that had been added to Country Group D:1, and thereby made subject such national security controls, were omitted from the definition. Those destinations are: Macau, which was added to Country Group D:1 on May 28, 1999 ( see 64 FR 28908); and Iraq, which was added on July 30, 2004 ( see 69 FR 46074). Additionally, North Korea was removed from Country Group E:2 and added to Country Group D:1 on June, 19, 2000 ( see 65 FR 38150—38151). This rule revises the definition of the term “controlled country” in § 772.1 to state that Macau, Iraq, and North Korea are in Country Group D:1, and to eliminate redundant statements from the definition.

Export Control Classification Number 1C018 was revised in 1999 to remove the advisory note from that ECCN ( see 64 FR 47667—47668, September 1, 1999). However, that revision did not change the reference to License Exception GBS in the License Exceptions section of that ECCN, which continued to indicate that License Exception GBS was available for items listed in the advisory note that had been removed. This rule corrects that error by revising the reference to License Exception GBS to read “N/A” to make clear that License Exception GBS is not available for any item in ECCN 1C018. This rule also replaces the term “International Munitions List” in the heading of 1C018 with the term “Wassenaar Arrangement Munitions List” to reflect the current name of that document.

ECCN 3A001, paragraph .a.1.a. controls certain integrated circuits when usable in missiles and paragraph .a.5.a controls certain analog-to-digital converters when “designed or modified” for military use, hermetically sealed and rated for operation in the temperature range from below −54°C. to above +125°C. for missile technology reasons. Prior to publication of this rule, the License Exception section of ECCN 3A001 indicated that commodities in paragraph .a were eligible for License Exception LVS and that commodities in paragraphs .a.2 to .a.12 were eligible for License Exception GBS. However, section 740.2(a)(5) prohibits the use of license exceptions for items controlled for missile technology reasons except for some specified ECCNs in some specific circumstances. ECCN 3A001 is not one of those specified ECCNs. This rule adds the phrases “except a.1.a and a.5.a when controlled for MT” to the LVS paragraph and “except a.5.a when controlled for MT” to the GBS paragraph to make them consistent with § 740.2(a)(5).

1. This final rule has been determined to be not significant for purposes of E.O.12866.

2. Notwithstanding any other provision of law, no person is required to respond to, nor shall any person be subject to a penalty for failure to comply with a collection of information, subject to the requirements of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq. ) (PRA), unless that collection of information displays a currently valid Office of Management and Budget (OMB) Control Number. This rule involves collections of information subject to the PRA. These collections have been approved by the Office of Management and Budget (OMB) under control numbers 0694-0088 and 0694-0058.

Control number 0694-0088 “Multi-Purpose Application” carries a burden hour estimate of 58 minutes to prepare and submit form BIS-748. Miscellaneous and recordkeeping activities account for 12 minutes per submission. Control Number 0694-0058 “Voluntary Self-disclosures” carries an annual burden hour estimate of 670 hours. BIS believes that this rule will not change the burden hours imposed by either of these collections. Send comments regarding these burden estimates or any other aspect of these collections of information, including suggestions for reducing the burden, to David Rostker, OMB Desk Officer, by e-mail at david_rostker@omb.eop.gov or by fax to 202.395.285; and to the Regulatory Policy Division, Bureau of Industry and Security, Department of Commerce, PO Box 273, Washington, DC 20044.

3. This rule does not contain policies with Federalism implications as that term is defined in Executive Order 13132.

4. The Department finds that there is good cause under 5 U.S.C. 553(b)(3)(B) to waive the provisions of the Administrative Procedure Act requiring a notice of proposed rulemaking and the opportunity for public comment because this regulation updates internal agency process matters, clarifies license exceptions, corrects citation errors and clarifies paperwork requirements as described in the preamble. The revisions made by this rule are purely administrative and do not affect the rights or obligations of the public. Because these revisions are not substantive changes to the EAR, it is unnecessary to provide notice and opportunity for public comment. No other law requires that a notice of proposed rulemaking and an opportunity for public comment be given for this rule. Because notice of proposed rulemaking and opportunity for public comment are not required to be given for this rule under the Administrative Procedure Act or by any other law, the analytical requirements of the Regulatory Flexibility Act (5 U.S.C. 601 et seq. ) are not applicable.

This rule revises License Exception TMP (15 CFR 740.9) to authorize certain exports, but not reexports, to Sudan of certain commodities and software that otherwise would require a license pursuant to § 742.10 or § 742.15 of the EAR. This rule makes the tools of trade provisions of License Exception TMP available to (1) non-governmental organizations that are engaged in activities to relieve human suffering in Sudan and that are registered by the Department of the Treasury, Office of Foreign Assets Control (OFAC) pursuant to 31 CFR 538.521, or (2) organizations that are authorized by OFAC to take actions, for humanitarian purposes, that otherwise would be prohibited by the Sudanese Sanctions Regulations (31 CFR part 538), or (3) staff or employees of either such type of organization. Under this rule, those parties are authorized, under section 740.9(a)(i) of the EAR, to export to Sudan certain basic telecommunications equipment controlled under Export control Classification Number (ECCN) 5A991 such as cell phones, personal digital assistants and other wireless handheld devices, personal computers (including laptops) controlled under ECCN 4A994 that do not exceed a composite theoretical performance of 6,500 millions of theoretical operations per second (MTOPS), and global positioning system (GPS) or similar satellite receivers controlled under ECCN 7A994. These revisions to License Exception TMP also allow the export of related software controlled under ECCNs 4D994 and 5D992 for the use of such telecommunications equipment or computers. The software must be loaded onto the commodity prior to being exported and remain loaded on the commodity while in Sudan. This rule also authorizes parts and components of those ECCN 5A991 and 4A994 devices that are controlled under ECCN 5A992 and that are installed with, or contained in, such computers or equipment to be exported under License Exception TMP. The parts and components must remain installed with, or contained in, such computers or equipment while in Sudan. The tools of trade must accompany (either hand carried or as checked baggage) a member of the staff or an employee of such an organization to Sudan.

In connection with the temporary tools of trade exports that it authorizes pursuant to License Exception TMP, this rule employs the term “staff and employees” rather than the term “employees” that applies to other temporary tools of trade exports under License Exception TMP. The broader term will allow the use of License Exception TMP for temporary tools of trade exports by persons traveling to Sudan at the direction of, or with the knowledge of, an organization registered pursuant to 31 CFR 538.521 or an organization authorized by OFAC to take actions, for humanitarian purposes, that otherwise would be prohibited by the Sudanese Sanctions Regulation (31 CFR part 538) to assist in the work of such organization in Sudan, even if such person is not an employee of such organization. For example, a health care worker traveling from the United States to Sudan, at the direction of, or with the knowledge of, an eligible organization to act as a volunteer providing medical care as part of the activities of that organization would be considered “staff” under this rule, even if that person is not an employee of the eligible organization. This rule makes no such expansion of eligibility for use of License Exception TMP for temporary tools of trade exports to destinations other than Sudan.

Exports made pursuant to this rule must also meet the general requirements for temporary exports under License Exception TMP set forth in § 740.9(a) of the EAR and the specific requirements applying to tools of trade set forth in § 740.9(a)(2)(i). Such exports are also subject to the restrictions on the use of all License Exceptions found in § 730.2 of the EAR.

BIS is publishing this rule to facilitate the activities of organizations working to relieve human suffering in Sudan by reducing the need for export licenses faced by such organizations, their staffs and employees. The commodities and software being made eligible for export under License Exception TMP by this rule do not require a license for export or reexport to most destinations, but do require a license for export or reexport to Sudan because that country has been designated by the Secretary of State as a state sponsor of terrorism.

Although the Export Administration Act of 1979 (EAA), as amended, expired on August 20, 2001, Executive Order 13222 of August 17, 2001 (3 CFR, 2001 Comp., p. 783 (2002)) as extended by the Notice of August 6, 2004, 69 FR 48763 (August 10, 2004), continues the EAR in effect under the International Emergency Economic Powers Act (IEEPA).

Rulemaking Requirements:

1. This rule has been determined to be significant for purposes of E.O. 12866.

2. Notwithstanding any other provision of law, no person is required to respond to, nor shall any person be subject to a penalty for failure to comply with a collection of information, subject to the requirements of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq. ) (PRA), unless that collection of information displays a currently valid Office of Management and Budget (OMB) Control Number. This rule involves a collection of information subject to the PRA that has been approved by OMB under control number 0694-0088, “Multi-Purpose Application, which carries a burden hour estimate of 58 minutes to prepare and submit form BIS-748. Send comments regarding these burden estimates or any other aspect of these collections of information, including suggestions for reducing the burden, to David Rostker, OMB Desk Officer, by e-mail at david_rostker@omb.eop.gov or by fax to 202-395-285; and to the Regulatory Policy Division, Bureau of Industry and Security, Department of Commerce, P.O. Box 273, Washington, DC 20044.

3. This rule does not contain policies with federalism implications as this term is defined in Executive Order 13132.

4. The provisions of the Administrative Procedure Act (5 U.S.C. 553) requiring notice of proposed rulemaking, the opportunity for public participation, and a delay in effective date, are inapplicable because this regulation involves a military and foreign affairs function of the United States 5 U.S.C. 553(a)(1)). Further, no other law requires that a notice of proposed rulemaking and an opportunity for public comment be given for this rule. Because a notice of proposed rulemaking and an opportunity for public comment are not required to be given for this rule under 5 U.S.C. 553 or by any other law, the analytical requirements of the Regulatory Flexibility Act (5 U.S.C. 601 et seq. ) are not applicable. Therefore, this rule is being issued in final form.

1. On October 6, 2004, the Commission issued a Notice of Proposed Rulemaking (NOPR) that proposed to standardize and clarify market-based rate sellers' reporting requirement for changes in status. The Commission proposed to impose uniform standards on all market-based rate sellers by eliminating the option to delay reporting changes in status until submission of the triennial review, or to file a triennial review in lieu of reporting changes in status as they occur. Acting pursuant to section 206 of the FPA, the Commission proposed to amend its regulations and to modify the market-based rate authority of current market-based rate sellers to include the requirement to timely report to the Commission any change in status that would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority. The Commission proposed that this reporting requirement be incorporated into the market-based rate tariff of each entity that is currently authorized to make sales at market-based rates, as well as that of all future applicants. The Commission proposed that notice of such changes in status be filed no later than 30 days after the change in status occurs.

2. As discussed more fully below, in this Final Rule, the Commission, among other things: Imposes uniform standards on all market-based rate sellers by eliminating the option to delay reporting changes in status until submission of the triennial review or to file a triennial review in lieu of reporting changes in status as they occur; specifically refers to “control” of generation or transmission facilities as a trigger which could result in the obligation to make a change in status filing; provides guidance as to the “characteristics” the Commission relies on in evaluating whether to grant market-based rate authority; provides guidance as to the form, content, and timing of a change in status filing; and incorporates into all market-based rate tariffs the standards discussed herein.

3. In doing so, the Commission has adopted many of the recommendations suggested by commenters. In this regard, the Commission clarifies that a change in status filing is one of the tools the Commission uses to ensure that wholesale electric rates remain just and reasonable. In particular, a change in status filing informs the Commission of changes that may occur from time to time that relate to the four-part analysis (generation market power, transmission market power, other barriers to entry, and affiliate abuse and reciprocal dealing) the Commission relies on for granting market-based rate authority. At the same time, however, the Commission finds that some of the recommendations made by commenters are more appropriately addressed in the market-based rate rulemaking proceeding that the Commission has initiated in Docket No. RM04-7-000.

4. As discussed below, the Commission finds that a number of issues regarding the Commission's analysis under the four-part test ( e.g. , what constitutes control of an asset, how to treat long-term contracts, how to evaluate whether an applicant has transmission market power) are more appropriately addressed in the market-based rate rulemaking, in which numerous technical conferences have been held and comments filed. It is in that proceeding that the Commission will examine the recommendations of commenters and address the adequacy of the current four-part analysis, including whether and how it should be modified to assure that electric market- based rates are just and reasonable under the FPA.

5. With respect to change in status filings, in this Final Rule applicants are reminded that the baseline determination of whether a filing is required is whether the change in status in question would have been reportable in an initial application for market-based rate authority under the Commission's four-part analysis, as it may change from time to time. To the extent that the change in status in question would have been reportable in an initial request for market-based rate authority, a change in status filing is required. For example, if an applicant acquires additional uncommitted capacity, a change in status filing is required.

6. The Commission provides this guidance to enable applicants to better determine when they must report a change in status. The electric industry is a dynamic industry and no bright-line standard is possible to encompass all relevant factors and possibilities that may occur. The Commission believes that sufficient guidance has been provided in this Final Rule and reminds applicants that they have the right to make a change in status filing under section 205 of the Commission's regulations at any time. With this safeguard, the Commission is certain that applicants have the means to fully comply with the change in status requirement and with the standards adopted herein can do so efficiently and with no additional burden.

7. As the Commission explained in the NOPR, it has a statutory duty under the FPA to ensure that rates charged by public utilities authorized to make wholesale sales in interstate commerce at market-based rates are just and reasonable. 1 - 2 The Commission uses a four-part test to determine whether to grant market-based rate authority. That test examines whether the applicant or its affiliates possess the potential to exercise market power by considering generation market power, transmission market power, barriers to entry, and the potential for affiliate abuse or reciprocal dealing. Sellers authorized to make sales at market-based rates are then required to file electric quarterly reports containing a summary of the contractual terms and conditions in every effective service agreement for market-based power sales and transaction information for their market-based rate sales during the most recent calendar quarter. 3

8. The Commission has also required that market-based rate sellers report any changes in status that would reflect a departure from the characteristics the Commission relied upon in its existing grant of market-based rate authority. When the Commission first granted market-based rate authorizations, it required traditional utilities that satisfied the Commission's initial market power review to file an updated market power analysis every three years to allow the Commission to monitor competitive conditions and to determine whether the applicants still satisfied our market power concerns. 4 Power marketers, on the other hand, were required to promptly notify the Commission of changes in status. 5 Subsequently, the Commission has allowed market-based-rate sellers to choose between promptly reporting changes in status, filing a three-year update in lieu of reporting changes in status as they occurred, 6 or reporting such changes in conjunction with the updated market analysis. 7 The Commission reserved the right to require such an analysis at any time and, in the NOPR, proposed to continue to reserve this right.

9. To carry out its statutory duty under the FPA to ensure that market-based rates are just and reasonable, the Commission must rely on market-based rate sellers to provide accurate, up-to-date information regarding any relevant changes in status, such as ownership or control of generation or transmission facilities and affiliate relationships. In contrast to when the Commission first began to authorize market-based rate sales, as markets have expanded and developed, both the number and types of market-based rate sellers have increased ( e.g. , independent power producers, power marketers, affiliated generators) and the complexity of wholesale markets has increased. Furthermore, market structure is rapidly evolving due to restructuring, corporate realignments and new types of contractual and subcontracting arrangements, in which utilities increasingly grant other firms control over managing various aspects of their business such as power marketing. In light of these structural changes, the Commission has concluded that more timely reporting of changes in status is necessary.

10. Therefore, the Commission proposed in the NOPR to eliminate the option to delay reporting changes in status until the next triennial review, or to file a triennial review in lieu of promptly reporting changes in status, and to standardize the change in status reporting requirement. Accordingly, the proposed regulations would require that, as a condition of obtaining and retaining market-based rate authority, all sellers will be required to timely report to the Commission any change in status that would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority.

11. With only a few exceptions, the commenters support the Commission's proposal to standardize market-based rate sellers' reporting requirement. Nearly all of the comments received urge the Commission to more clearly define market-based rate sellers' reporting obligation and to do so in a manner that does not impose an excessive reporting burden.

12. Mayflower LP (Mayflower) argues that the Commission's entire approach of attempting to develop market power tests is misguided because the variables involved are too complex to describe effectively in a regulation. Mayflower contends that the Commission should instead prioritize its resources to mitigating the obvious cases of market power, in particular by utilizing section 205(f) of the FPA  8 to end market power abuses through fuel adjustment clauses, which allow utilities to pass through the costs of operating dirty and inefficient gas and boiler generation, while cleaner, cheaper-to-run combined cycle generation sits idle. 9

13. Tractebel North America, Inc. (Tractebel), citing the Commission's recent order disclaiming jurisdiction under section 203 for a generation-only facility in Perryville Energy Partners, 10 argues that the review of transactions in the context of market-based rate authority is an inadequate substitute for Commission review of a public utility's acquisition of an asset under section 203. Accordingly, in cases where the Commission lacks jurisdiction under section 203, Tractebel urges the Commission to review acquisitions of generation not only in the context of a notice of change in status, but also in related filings, such as any rate filing for transmission interconnection service over assets that will continue to be owned by the seller and filings related to exempt wholesale generator (EWG) status. 11

14. Finally, Pacific Gas & Electric Company (PG&E) argues that the reporting requirement proposed in the NOPR should apply to energy marketers but not to investor-owned utilities that are serving native load customers and are members of an independent system operator (ISO) or regional transmission organization (RTO). According to PG&E, there are legitimate differences between energy marketers (who, as net sellers, engage in electric trades for profit and can influence the market relatively rapidly) and traditional utilities such as PG&E (who are net buyers and do not speculate). 12

15. We decline to adopt Mayflower's proposal to address alleged market power abuses through fuel adjustment clauses because it goes beyond the scope of the instant rulemaking. Section 205(f) requires the Commission to review practices under public utility automatic adjustment clauses to ensure efficient use of resources under such clauses. If a party believes that this is not being done, the Commission encourages the filing of a complaint to remedy the matter. Proposals such as Mayflower's, which urge the Commission to adopt a new approach toward the mitigation of market power, are more appropriately addressed in the generic rulemaking in Docket No. RM04-7-000.

16. In response to Tractebel's comments, the acquisition of a generating facility by a utility with market-based rate authority such as occurred in Perryville is an event that would trigger the filing of a change in status report consistent with this rule. Whether it would trigger other jurisdictional filings such as a rate filing for transmission interconnection service or filing related to EWG status, as Tractebel suggests, would depend on the facts of the particular case. As the Commission stated in the Perryville case, the Commission will consider the effect of the addition of the Perryville capacity as part of the Commission's review of Entergy's updated market power analysis in Docket No. ER91-569-023, et al. 13

17. We will also reject PG&E's suggestion to exempt investor-owned utilities such as PG&E from the reporting requirement. Adopting PG&E's proposal could result in allowing large vertical utilities to increase their market share or otherwise obtain market power without notifying the Commission of changed circumstances. Under PG&E's proposal, a vertical utility could have changed circumstances that would result in that utility no longer satisfying one or more prongs of the four-part test that the Commission uses to determine whether to grant market-based rate authorization. With no notification to the Commission in that regard such a proposal provides little or no protection to customers in the market between review periods, ( i.e. , triennial review). To the extent that PG&E assumes an RTO's mitigation warrants an exemption, we have rejected such an exemption in the previous orders. 14

18. With respect to the types of events that should trigger the reporting obligation, the Commission proposed in the NOPR that, as an initial matter, the following events would qualify as changes in status: (1) Ownership or control of generation or transmission facilities or inputs to electric power production; or (2) affiliation with any entity not disclosed in the filing that owns or controls generation or transmission facilities or inputs to electric power production or affiliation with any entity that has a franchised service area. 15 The Commission noted that, although the change in status provision has not specifically referenced “control” of assets, the Commission has historically taken into account all of the assets that a market-based rate seller controls in our four-part test for granting market-based rate authority. In order to eliminate any market uncertainty, the Commission proposed that the regulations specifically reference “control” as well as ownership as a factor relied upon by the Commission. As we noted in the NOPR, the Commission's early orders granting market-based rate authority acknowledged that sellers may exercise market power through contractual arrangements granting them control of generation or transmission facilities just as effectively as they could through ownership. 16 Similarly, the Commission's guidelines for the assessment of mergers and its generation market power analysis for market-based rate authority provide that, for the purposes of the market power analysis, the capacity associated with contracts that confer operational control of a given facility to an entity other than the owner must be assigned to the entity exercising control over that facility, rather than to the entity that is the legal owner of the facility. 17 In addition, with respect to notifications of changes in status, the Commission has found that an entity controls the facilities of another when it controls the decision-making authority over sales of electric energy, including discretion as to how, when and to whom it could sell power generated by these facilities. 18

19. Several commenters assert that the definitions of triggering events are vague or unclear and request that the Commission clarify these elements of the proposed regulations. 19 Some commenters request that the Commission clarify these terms by issuing a supplemental NOPR offering a detailed description of the specific information it needs  20 or by setting forth clear “rules of the road” to provide market-based rate sellers guidance as to whether they are in compliance with the Commission's requirements. 21 Cinergy Services, Inc. (Cinergy) urges the Commission to limit the scope of the present rulemaking to reviewing reporting requirements for changes in status relevant to the Commission's current four-part analysis for market-based rate authority and to defer consideration of new issues or modifications to the current market-based rate tests for the parallel rulemaking in Docket No. RM04-7-000. 22

20. Commenters were divided as to whether the Commission should include an illustrative list of triggering events. Calpine Corporation (Calpine) and Transmission Access Policy Study Group (TAPS) argue that the Commission should adopt bright-line standards for what constitutes a reportable event and suggest specific events that should trigger the reporting requirement, which are discussed further below. 23 National Rural Electric Cooperatives Association (NRECA) argues that the Commission should clearly define when the reporting obligation is triggered because failure to comply could potentially result in retroactive refunds pursuant to the Ninth Circuit's decision in California ex rel. Lockyer v. FERC    24 and/or suspension or revocation of market-based rate authority. 25

21. On the other hand, the Bank Power Marketers and Industrial Energy Users—Ohio and PJM Industrial Customers Coalition (IEU—Ohio/PJMICC) argue that the Commission should not rely on a laundry list of transaction types  26 or an illustrative list of reporting triggers. 27

22. American Public Power Association (APPA) comments that the reporting requirement should provide for the reporting of changes that “could affect the public utility's eligibility for [market-based rate] authority,” based on current standards for authorization of market-based rates, rather than requiring reporting of only those events that “would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority.”  28

23. EEI, supported by Pacificorp, argues that the reporting obligation should extend only to changes in circumstances within the applicant's control. According to EEI, an applicant should not be required to report a change of circumstances based on an action taken by a competitor (such as a decision to retire a generation unit or take transmission capacity out of service) or natural events (such as a high hydro-year, higher wind generation or load disruptions due to adverse weather conditions) that might change the result of the interim screens. 29

24. Finally, commenters suggest the following additional triggering events: The acquisition of Financial Transmission Right (FTR) positions into constrained load pockets that exceed a seller's load obligations in the load pocket, 30 any changes in ISO or RTO status for the relevant market; or any changes in state regulations relative to load-serving obligations in the relevant market;  31 changes in market definition, e.g. , due to transmission outages or the change in size of a load pocket, provided that such changes are confirmed by the independent and published judgment of an ISO or RTO overseeing local market power issues pursuant to a Commission tariff. 32

25. After careful consideration of the comments, the Commission rejects commenters' proposals to clarify the reporting requirement by including an illustrative list of triggering events or to otherwise expand the list of triggering events beyond those contained in the NOPR. We reject this suggestion, first, because we believe that the definition of triggering events contained in the Commission regulations adopted here, offers market-based rate sellers sufficient notice of and guidance concerning the scope of their reporting requirement. The reporting requirement we adopt herein ensures that the Commission retains the discretion and flexibility to protect customers in light of future, unforeseen changes in wholesale electricity markets that may allow market-based rate sellers to exercise market power. Consequently, the Commission does not believe that commenters have provided sufficient support for their contention that the inclusion of an illustrative list would in fact increase regulatory certainty.

26. In response to the request of Cinergy, we clarify that the reporting requirement is limited to reviewing changes in status relevant to the Commission's current four-part analysis for market-based rate authority and that the Commission will not consider any new tests or modifications of its current four-part test in this docket. APPA has argued that the Commission should change its existing reporting requirement—which obligates market-based rate sellers to report changes that “would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority”—to require reporting of changes that “could affect the public utility's eligibility for [market-based rate] authority,” based on current standards for authorization of market-based rate authority. We clarify that the “characteristics” refer to the Commission's four-part test and our analysis thereof. The Commission evaluates any request to obtain or retain market-based rate authority under its currently applicable standards for each of the four prongs; similarly, a notice of change in status is required in circumstances where the factors the Commission relied upon in evaluating the four-part test as it applies to an applicant change. Under these circumstances, the Commission will apply the currently applicable standard in its assessment of whether that entity may continue to make sales at market-based rates. Second, APPA's proposal to require reporting of changes that “could affect the public utility's eligibility for [market-based rate] authority” appears to be more subjective than our current standard and could result in sellers reporting information that the Commission would not consider relevant. We believe that we have given sufficiently clear guidance regarding triggering events to limit market-based rate sellers' discretion to avoid reporting changes in status that would confer or enhance market power.

27. We agree with EEI that the reporting obligation should extend only to changes in circumstances within the knowledge and control of the applicant. Accordingly, an applicant should not be required to report a change in circumstances based on an action taken by a competitor (such as a decision to retire a generation unit or take transmission capacity out of service) or natural events (such as hydro-year, higher wind generation or load disruptions due to adverse weather conditions). While we will not expand the triggering events as proposed in the NOPR in this Final Rule, interested persons can pursue these matters in the course of the generic rulemaking we have established in Docket No. RM04-7-000, which will address proposed modifications to the Commission's current four-part test for granting market-based rate authority.

28. Commenters suggest a number of events that should be exempted from the reporting requirement. BP Energy Company (BP Energy), Cinergy, Duke Energy Corporation (Duke), EPSA, FirstEnergy, and Edison Electric Institute and Alliance of Energy Suppliers (EEI) contend that the reporting requirement should not apply to events covered by section 203 applications. 33

29. Bank Power Marketers and Westar Energy, Inc. (Westar) oppose the proposals contained in the NOPR on the ground that the proposed reporting requirement would be both excessive and duplicative, given that the Commission already receives the same information through existing reporting requirements, e.g. , section 203 applications, triennial updates, Electric Quarterly Reports (EQR), Form 3-Q, etc. 34

30. EEI and PacifiCorp argue that long-term contracts should not be reportable. 35 National Grid USA (National Grid) argues that market-based rate sellers should not be required to report long-term contracts that were entered into either to satisfy their “provider of last resort” (POLR) obligations or through state-regulated competitive solicitation processes that are consistent with the Commission's standards for inter-affiliate transactions. 36 National Grid and IEU—Ohio/PJMICC also support the exemption of purchases from qualified facilities mandated by the Public Utility Regulatory Policies Act of 1978 (PURPA). 37

31. Duke suggests that the following events should be exempt: (i) Transactions outside market-based rate sellers' home or first-tier control area markets; (ii) affiliate transactions subject to other reporting requirements; (iii) transactions involving post-1996 generation facilities; and (iv) intra-corporate reorganizations that do not involve the acquisition of additional assets and thus do not affect market share or concentration. 38 Cinergy argues that the reporting obligation should not apply to transactions that do not increase ownership or control, specifically: (i) Intra-corporate transactions between affiliates within one holding company system or transactions that are simply a change in corporate form; (ii) purely financial transactions such as futures, swaps and derivatives that do not have a physical component; and (iii) construction of new generation otherwise exempt under Commission regulations. 39 Tucson Electric Power Company (Tucson Electric) urges the Commission to exempt entities subject to oversight by an Independent Market Monitor (IMM) because the IMM will investigate and report to the Commission any anticompetitive behavior. 40

32. Finally, Cinergy and Tractebel urge the Commission to clarify that the Commission is only concerned with changes in status that may increase market power, but not those that decrease it, so, for example, the purchase of generation might trigger the reporting requirement, but a sale should not. 41 Similarly, Calpine argues that a public utility's decrease in generation capacity cannot increase its generation market power over what the Commission assumed when it granted market-based rate authority, so it would be a waste of resources to require such reporting. 42

33. With respect to changes in ownership or control of transmission facilities, EEI, FirstEnergy and National Grid argue that, given the existence of the open access transmission tariff (OATT) requirement, which constrains the exercise of vertical market power, there should be no reporting requirement for changes in status regarding transmission facilities covered by an OATT. 43 National Grid urges the Commission to defer the establishment of reporting requirements associated with changes in transmission market power status until it has developed, in the context of Docket No. RM04-7-000, more of an understanding of what transmission market power is and how it might be abused. 44 EEI, FirstEnergy, and National Grid all argue that, since any transfer of ownership or control of transmission facilities would be covered by a section 203 application, a separate reporting requirement in the context of market-based rate authority is unnecessary and duplicative. 45 National Grid argues that such a reporting requirement might discourage transmission providers from transferring their transmission facilities to Independent Transmission Companies (ITCs). 46 Finally, National Grid contends that construction activities undertaken pursuant to a Commission-approved regional planning process should not be reportable because additional transmission capacity improves competition among resources. 47

34. In order to avoid unnecessary duplication of effort, we clarify that a market-based rate seller may incorporate by reference in its notice of change in status any filings regarding the change in status made pursuant to other reporting requirements. Furthermore, intra-corporate reorganizations that do not otherwise have an impact on our four-part test and are not otherwise reportable need not be reported as a change in status.

35. We reject commenters' proposal to exempt from the reporting requirement transactions that are subject to other reporting requirements, such as dispositions of jurisdictional facilities covered by section 203 applications and long-term contracts or affiliate transactions that are filed pursuant to section 205. The Commission can best exercise its statutory duty to ensure just and reasonable rates by imposing an enforceable post-approval reporting requirement regarding changes in status. 48 Appropriate market monitoring cannot be satisfied simply by ensuring that public utilities are complying with other provisions of the FPA. Moreover, as discussed below, the time and effort required to prepare the notice of a change in status—consisting of a transmittal sheet and a brief narrative statement—will be de minimis and will constitute a fraction of that required to submit the section 203 application or section 205 filing. Furthermore, the information required to comply with the reporting requirement would normally be collected by the market-based rate seller in the ordinary course of preparing the underlying filing.

36. We also reject Tucson Electric's proposal to exempt transactions involving entities subject to oversight by an IMM. Consistent with our decision not to allow an exemption from the generation market power analysis for sales into an ISO/RTO with Commission-approved market monitoring and mitigation, we will not exempt from the change in status reporting requirement entities subject to oversight by an IMM. The Commission has an independent statutory duty to ensure that rates are just and reasonable, and we cannot delegate this responsibility in these circumstances to an IMM.

37. Commenters also propose to exempt transactions outside the applicant's home or first-tier control area markets and to exempt new construction. These commenters have not presented any persuasive evidence that these transactions—to the extent that they are covered by the Commission regulations adopted herein and satisfy the materiality threshold set forth below—should be treated differently.

38. As a general matter, we reject Duke's suggestion that acquisitions of post-1996 generation be exempt from the reporting requirement. Section 35.27 merely adopts a rebuttable presumption that post-1996 generation cannot exercise market power, 49 and the Commission considers post-1996 generation in initial applications for and triennial reviews of market-based rate authority under appropriate circumstances. 50 However, we clarify that to the extent that the generation owned or controlled by an applicant [in the relevant market] and its affiliates is post-1996, and the applicant or an affiliate acquires through purchase or acquisition additional post-1996 generation, no change in status filing is required. The Commission has found that in circumstances where construction of all of an applicant's generation commenced after July 9, 1996, no interim generation market power analysis need be performed. 51 On the other hand, in the above example, if the applicant owned pre-1996 generation a change in status filing may be required since the Commission has stated that if an applicant sites generation in an area where it or its affiliates own or control other generation assets, the applicant must study whether its new capacity, when added to the existing capacity, raises generation market power concerns. 52 Finally, we note that the generic rulemaking in Docket No. RM04-7-000 will address whether the Commission should retain the exemption for post-1996 generation in section 35.27 of the Commission's regulations.

39. In response to Cinergy's request, we clarify that purely financial transactions involving future swaps and derivatives that do not provide for physical delivery are exempt from the reporting requirement for the same reason that such contracts need not be reported in Electric Quarterly Reports (EQRs). 53

40. The Commission accepts the proposal submitted by Calpine, Cinergy and Tractebel that a decrease in ownership or control due to dispositions of generation, transmission or inputs to production should not be reportable to the extent such transaction decreases the applicant's generation market power as measured by the indicative screens.

41. Finally, we reject National Grid's arguments that long-term contracts that were entered into by a utility to satisfy its POLR obligations or pursuant to a state-regulated competitive solicitation process should be exempted from the reporting requirement. To the extent that an applicant acquires additional capacity that impacts the Commission's analysis of one or more prongs of the four-part test used in evaluating whether to grant market-based rate authority, a change in status filing is required.

42. Several commenters express support for the inclusion of “control” as a triggering event. In supporting the inclusion of control as a triggering event, the California EOB argues that the concept of control should be used to expand the scope of the triggering requirements, not narrow them. 54

43. Other commenters argue that the definition of control is vague and overly broad and note, for example, that it could be interpreted to cover individual power purchase transactions. 55 These commenters argue that the Commission should narrowly define control by identifying the specific decision-making authority that the purchaser or reseller must have in order to constitute control. PG&E argues that control should only cover cases where the purchaser has operational control of the resource, i.e. , the ability to determine when it is available for operation, and should not apply to an entity who has contracted for the first right, or even the exclusive right, to call or dispatch the resource when it is needed. 56 FirstEnergy contends that market-based rate sellers should only be required to report long-term contracts that transfer to the purchaser or reseller the authority over dispatch of the unit and preclude the generation owner from dispatching the unit without the consent of the purchaser or reseller. 57 Similarly, Duke Energy Corporation (Duke) argues that the Commission should apply general principles of agency as developed by Commission precedent, whereby the Commission has found that a purchaser has control if it possesses decisionmaking authority over key operations, such as decisions to commit or de-commit a generator or to make or not make sales. 58 EPSA agrees that control over an asset is a key consideration in a market power analysis. However, EPSA states that the use of the term “operational control” creates uncertainty and suggests that the Commission drop all references to “operational control” and replace it with “scheduling and dispatch control” or clarify that operational control refers to a contractual right to control the output of a plant. 59 The Bank Power Marketers suggest that the factors indicating control include definitive authority to: Require a plant to run or to shut down; declare unscheduled outages; or establish output levels when running ( i.e. , to ramp-up or down). 60

44. Calpine suggests that the test for control should be whether the purchaser has the authority to make available to the market and withhold from the market generation products associated with generation capacity. 61 For example, Calpine submits that a tolling agreement should be reportable if it permits a public utility to operate a plant that gives it the authority to generate or not generate from that plant. 62 Cinergy argues that control should be defined in a manner that is more directly linked to standard measures of market power as used by the Commission and the antitrust agencies, i.e. , whether a new contractual arrangement provides an applicant with the ability to economically or physically withhold from the market, or erect a barrier to entry. 63 For the same reasons, TAPS urges the Commission to require reporting of long-term maintenance agreements between market-based rate sellers or their affiliates that grant the entity providing the maintenance services the ability to decide when such maintenance is performed. TAPS contends that, if the entity providing maintenance also operates facilities in the same market (or has an affiliate that does so), its decisions about when to perform the maintenance (thereby possibly requiring an outage) could be influenced by its (or its affiliate's) sales activities in the market. 64

45. SoCal Edison requests that the Commission identify the duration of the change in control necessary to trigger the reporting requirement. According to SoCal Edison, very short-term transactions may temporarily convey control over a resource, but it is doubtful that requiring reporting of such transactions 30 days after their conclusion will provide meaningful or useful information to the Commission. SoCal Edison suggests that the appropriate minimum duration would be at least a 32-day transaction involving change in control. 65 SoCal Edison also argues that the Commission should consider focusing primarily on net changes in control of uncommitted generation. 66

46. BP Energy urges the Commission to clarify that the reporting requirement is limited to ownership or contractual control equivalent to ownership, rather than “influence”, which is vague and subject to conflicting interpretations. 67 FirstEnergy argues that market-based rate sellers should only be required to report changes in ownership that result in a change in control. FirstEnergy states that the Commission has previously recognized that certain passive owners of generation assets do not have control over such assets, and therefore do not constitute regulated public utilities. According to FirstEnergy, even if a public utility acquires or increases its ownership interest in a generation or transmission facility, it would not be appropriate to attribute the capacity in that facility to the utility, unless the utility had decisionmaking authority over sales of electric energy from the facility. FirstEnergy asserts that it is essential that the Commission define more precisely when a change in ownership or control conveying the requisite decisionmaking authority is deemed to have occurred. It notes that the Commission has previously ruled that a voting interest of 10 percent or more creates a rebuttable presumption of control over a utility that is not an EWG and that a voting interest of five percent or more is used in the case of a utility that is an EWG. 68 FirstEnergy submits that, as a practical matter, it is unlikely that a voting interest that is less than or equal to these thresholds, without more, will convey decisionmaking authority over sales of electric energy. FirstEnergy thus suggests that the Commission should adopt a higher threshold of asset ownership of at least 33.3 percent before a potentially reportable change in control is deemed to have occurred. 69 FirstEnergy adds that even a 33.3 percent voting interest should not be deemed to have transferred decisionmaking control if another entity (either individually or in conjunction with affiliated interests) owns a larger voting interest.

47. We will adopt the inclusion of control as one of the factors that could result in a change of status filing. We have previously stated that “control” refers to arrangements, contractual or otherwise, granting control of generation or transmission facilities, just as effectively as they could through ownership. 70 In short, if an applicant has control over certain capacity such that the applicant can affect the ability of the capacity to reach the relevant market, then that capacity should be attributed to the applicant when performing the generation market power screens. 71 As the Commission's guidelines for the assessment of mergers and its generation market power analysis for market-based rate authority provide, for the purposes of the market power analysis, the capacity associated with contracts that confer operational control of a given facility to an entity other than the owner must be assigned to the entity exercising control over that facility, rather than to the entity that is the legal owner of the facility. We believe that the Commission has given adequate specificity as to what constitutes control and the Commission will not, in this docket, further define or narrow the definition. Control of assets is a concept that this industry has dealt with for many years. The Commission is reluctant to provide a laundry list of agreements that may or may not constitute control of an asset. It is not possible to predict every contractual agreement that could result in a change of control of an asset. However, to the extent parties wish to propose specific definitions or clarifications to the Commission's historical definition of control, they may do so in the course of the market-based rate rulemaking in Docket No. RM04-7-000.

48. In response to SoCal Edison's request that the Commission identify the duration of the change in control necessary to trigger the reporting requirement, we clarify that long-term contracts with a duration of a year or more must be reported, which is consistent with our treatment of long-term contracts in the April 14 Order. 72

49. Commenters also request clarification as to the scope of affiliate-related reporting requirements. 73 BP Energy states that, as proposed, the reporting obligation appears to attach to affiliation with any entity not disclosed in the original application that owns or controls generation or transmission facilities or inputs to electric power production, or any entity with a franchised service territory. BP Energy requests clarification that the reporting requirement does not require a public utility with market-based rates to file a notice of a change in status if an affiliated generator identified in the original application increases the amount of generation it owns, so long as the public utility with market-based rates does not own or control the newly-acquired generation. 74

50. Sempra Energy Global Enterprises (Sempra) seeks a similar clarification that, when updating information regarding activities of affiliates, a market-based rate seller is only required to report new affiliations and would not be required to report changes in status on behalf of other affiliates whose existence has already been disclosed to the Commission. Sempra adds that a market-based rate seller should only be required to provide information that relates to a new affiliation in markets where the seller's relevant operations or assets overlap with those of the new affiliate. 75

51. With respect to BP Energy's and Sempra's request for clarification, as noted above, the reporting requirement applies to changes in status relevant to the Commission's current four-part analysis for market-based rate authority. To the extent that an affiliate experiences a change in status, such change in status must be reported to the extent that it impacts the factors the Commission relied upon in evaluating the four-part test as it applies to the applicant and granting the applicant market-based rate authority. To avoid any unnecessary duplication, we clarify that the various affiliates within a corporate family may submit a single notice for the corporate family as a whole for each reportable change in status that occurs listing all affiliated companies holding market-based rate authority in such notice.

52. We noted in the NOPR that the Commission's general practice has been to require notifications of changes in status when the market-based rate applicant obtained ownership of new inputs to electric power production, other than fuel supplies. However, since the Commission is interested in being informed of significant acquisitions of ownership or control of any inputs to electric power production, we proposed to require a reporting obligation to this effect and sought comments on this proposal.

53. A number of commenters request clarification of the term “inputs to electric power production” and urge the Commission to define this term to include or exclude certain inputs. APPA, EPSA, Powerex and TAPS submit that fuel supplies should not be considered inputs to electric power production. 76

54. Cinergy argues against a reporting obligation for fuel supplies because, according to Cinergy, the Commission has found the markets for natural gas and coal to be workably competitive. Cinergy asserts that information regarding fuel supplies is typically not required for the initial application for market-based rate authority and therefore should not be presumed to be relevant to the question of continued eligibility for market-based rate authority. Thus, in light of the lack of benefits to be obtained from the reporting of fuel supply arrangements, Cinergy contends that reporting would be unduly burdensome. Cinergy also contends that the only conceivable relevance of fuel supplies in authorizing market-based rates is in demonstrating that no barriers to entry or vertical market power concerns are present. To the extent that the Commission wishes to extend its consideration of barriers to entry to fuel supplies, Cinergy argues that the appropriate context to do so is not in the current rulemaking, but rather in the generic rulemaking proceeding in Docket No. RM04-7-000. 77

55. APPA, Calpine, the National Association of State Utility Consumer Advocates (NASUCA) and TAPS, however, support the inclusion of fuel supplies within the list of triggers for reporting changes in status. NASUCA states that electric utilities, power brokers, and other sellers of energy at market-based rates can acquire substantial control over natural gas supplies or other sources of fuel for generating units and effectively dominate the fuel supplies in the markets in which they also sell electricity. According to NASUCA, including fuel supplies within the category of changes that warrant a reporting requirement properly reflects the convergence of the electricity and natural gas industries and the potential for exercising market power that can result from the acquisition of critical supplies of fuel. 78 Calpine similarly asserts that the ability to control the transportation of inputs such as fuel may be just as important as controlling the input itself. 79

56. With respect to pipeline capacity, EPSA argues that increased pipeline capacity holdings should not be reportable because firm capacity is obtained through Commission-authorized programs and is posted on the pipeline's bulletin board. 80 FirstEnergy, by contrast, argues that changes in status relating to ownership or control of interstate natural gas pipelines or local distribution companies should be reportable because control over natural gas supplies are the principal input to electric power production may enable an entity with market-based rate authority to erect barriers to entry by competitors, especially if the seller is a combination electricity/natural gas utility. FirstEnergy asserts that the acquisition of other inputs, e.g. , generation plant sites, construction or engineering companies or fuel production resources, should not be reportable. 81

57. Other commenters also argue that the Commission's inquiry should be focused on the potential for market-based rate sellers to erect barriers to entry. Bank Power Marketers argue that the Commission should issue a supplementary NOPR to provide additional guidance on what level of ownership or control of inputs to electric power production is “significant” enough to warrant disclosure and submits that, in order to be “significant”, the acquisition of an input must be of the type that gives the acquirer vertical market power; otherwise, such acquisitions should not be reportable. 82 Similarly, Sempra argues that the Commission has never clearly defined the scope of what constitutes “inputs to electric power production” and that it should either be deleted or, alternatively, the Commission should implement a “timeout” with regard to enforcement of the reporting requirement for such inputs until it has completed its consideration of the barriers to entry prong of its market-based rate analysis in the Docket No. RM04-7-000 proceeding. 83 BP Energy contends that the disclosures should be limited to only the information necessary to identify the type and the source of potential barriers to entry. 84 BP Energy states that the Commission should identify specifically what the relevant “inputs to electric power production” are, and it should state clarify whether such inputs include items other than those specified in previous orders, i.e. , ownership or control of new generation sites, fuel supplies (natural gas, oil or coal), transportation of fuel supplies or whether the affiliate is a supplier of electric equipment. 85 Duke argues that an arrangement regarding inputs to electric power production should only be reportable if it conveys to the market-based rate seller the decisional control sufficient to enable it to erect barriers to entry. Under this approach, Duke contends that natural gas, oil or coal transportation or storage contracts and fuel purchase contracts should not be reportable. 86

58. As we stated in the NOPR, the Commission's general practice has been to require notification of changes in status when the market-based rate applicant obtained ownership of new inputs to electric power production, other than fuel supplies. However, we proposed in the NOPR to include fuel supplies as an input to electric power production and sought comments on this proposal. After careful consideration of the comments, including the arguments raised by commenters that this issue in any event is more appropriately raised in the proceeding in Docket No. RM04-7-000 as part of the Commission's consideration of the barriers to entry prong of the market-based rate analysis, we have decided not to make any changes to our precedent at this time as to what constitutes an input to electric power production, including expanding the definition to include fuel supplies. As a result, the regulations we adopt in this rule will require the reporting of ownership or control of inputs to electrical power production, other than fuel supplies. Nevertheless, we will provide interested persons an opportunity to propose modifications to this approach in the course of the generic rulemaking proceeding in Docket No. RM04-7-000.

59. Further, we clarify that an arrangement regarding inputs to electric power production, other than fuel supplies, is reportable to the extent that the factors the Commission relied on in evaluating the four-part market-based rate test as it applies to the applicant change.

60. We recognized in the NOPR that the language in the proposed regulations may be susceptible to different interpretations among market-based rate sellers concerning the scope of their reporting requirement. Accordingly, we sought public comment as to whether and how this language should be modified to ensure that the types of changes in status that could impact the continued basis of a grant of market-based rate authority are identified and timely reported to the Commission. For example, we asked whether there should be a threshold level of increases in generation (such as through acquisition, self-build, long-term power purchases, re-powering) that would trigger the reporting requirement. If so, we asked what amount of increase in generation should trigger the reporting requirement.

61. Several commenters suggest specific materiality thresholds by designating a particular amount or percentage of increase in generation capacity as the trigger for the reporting requirement, while others urge the Commission to clearly define the threshold without suggesting a particular amount. 87 For example, APPA, TAPS, and Tractebel suggest a threshold of 100 MW. 88 APPA and TAPS further suggest that acquisitions of 100 MW or more should be promptly reported with all capacity changes (increases or decreases) identified as part of the market-based rate sellers' Order No. 2001 quarterly transactions reports. 89 Powerex argues that the materiality threshold should be no less than a 250 MW change increase in the ownership or control of generation capacity from the last triennial review or the last notice of a change in status. 90 EEI, supported by Xcel, proposes that the reporting threshold should be an increase in net excess generation capacity ( i.e. , an increase in the applicant's generation capacity above its forecasted native load growth requirements, reliability requirements and contractual obligations) that is equal to the greater of: (i) 250 MW, (ii) 10 percent of installed nameplate generation capacity, or (iii) five percent of the capacity in the control area market. 91 FirstEnergy suggests that an increase in generation capacity should trigger the reporting requirement if it exceeds the greater of either 250 MW or a 10 percent increase in the market-based rate seller's uncommitted generation capacity. 92

62. BP Energy and EPSA both contend that the materiality threshold should take into account the increase in the market-based rate seller's market share and its impact on the relevant geographic market, as well as the absolute amount of the increase in generation capacity. EPSA suggests that the materiality threshold should be in the range of 250-500 MW or one to two percent of the installed capacity in a market area. 93 BP Energy proposes a materiality threshold for ownership or control of generation that would be the greater of a net positive change of 300 MW or one to two percent of the installed capacity in the relevant market (determined by ISO/RTO or NERC region or control area). 94 ELCON proposes that the final rule should include a materiality threshold for large, end-use corporations for changes in generation at its production sites, e.g. , a 300 MW increase in generation, or alternatively, an increase in generation equal to one or two percent of installed capacity in a region market; to the extent that the increase in generation is less than this threshold, the 30-day reporting requirement should be waived. 95

63. SoCal Edison argues that EEI's proposal should be modified to provide that only the 10 percent threshold for increases in generation capacity should apply for load-serving entities because such entities may add 250 MW or more in the normal course of business—in order to meet resource adequacy requirements or in response to normal load growth—without effecting any material change in its ability to exercise market power. 96 SoCal Edison proposes that the materiality threshold for a change in status other than an increase in generation capacity should be a net increase of 10 percent from the data that the Commission relied upon in granting market-based rate authority. 97

64. Cinergy proposes that a transaction should not be considered material if, first, it involves the acquisition of generation that is not in the same relevant geographic market as the applicant's existing generation. Alternatively, a transaction would not be material if: (i) It increases the applicant's generation in the relevant geographic market by two percent or less; (ii) the applicant's existing generation in the market is low ( e.g. , less than 1000 MW), and the increase is less than 10 percent of the total market; or (iii) the acquired generation is in an RTO that has restructured its market. 98

65. PacifiCorp urges the Commission to permit market-based rate sellers to rely on forecasts of load growth in determining whether an acquisition of new generation resources constitutes a material change in the conditions in the market. 99 According to Pacificorp, a utility should be required to report a material change only when it increases its net generating capacity by acquiring additional resources in excess of its forecasts for native load growth. Avista Corporation (Avista) suggests that, for a utility the size of Avista, the threshold level of increase in generation before triggering the reporting requirement should be not less than 10 percent of the utility's retail and wholesale peak load obligations. 100

66. NASUCA opposes the establishment of a materiality threshold for reporting a change in status, but suggests instead that the Commission could exempt from the rule changes in status that do not stem from changes in ownership or control of generation, fuel, transmission or power supply assets such as a change in corporate name unrelated to a merger or acquisition. 101 According to NASUCA, establishing triggers for determining when reporting of a change in status is necessary may lead to under-reporting due to varying interpretations of what types of assets should be considered. NASUCA asserts that requiring all changes, however small, to be reported will permit Commission review and ensure that a change in status will not allow a seller with market-based rate authority to exercise market power.

67. PG&E, as discussed above, opposes the imposition of a uniform reporting requirement that imposes identical reporting obligations on energy marketers and traditional utilities. PG&E urges the Commission to establish, for traditional utilities, a threshold for an increase in wholesale sales or revenues from wholesale sales that the Commission concludes is statistically relevant or has the potential to influence the overall market. Under PG&E's proposal, if a traditional utility's quarterly report shows an increase in wholesale sales or revenues from wholesale sales that exceeded this threshold, the utility would be obligated to provide—in the same quarterly report—additional information about the transactions that caused the increase. PG&E contends that this proposal, if adopted would ensure that the Commission received targeted information, while reducing the burden on both utilities and the Commission. 102

68. After careful consideration of the comments received, the Commission has concluded that small increases in generation of less than 100 MW need not be immediately reported. However, market-based rate sellers must report as a change in status each cumulative increase in generation of 100 MW or more that has occurred since the most recent notice of a change in status filed by that seller, ( i.e. multiple increases in generation that individually do not exceed the 100 MW threshold must all be reported once the aggregate amount of such increases reaches 100 MW or more). The Commission's market power analysis, which is performed at the time of an initial application and every three years thereafter, considers all relevant generation capacity to assess whether a seller lacks, or has adequately mitigated, generation market power. In light of these periodic reports, we believe that a minimum reporting threshold for generation increases during the interim period is appropriate. We believe that this approach strikes the proper balance between the Commission's duty to ensure that market-based rates are just and reasonable and the Commission's desire not to impose an undue regulatory burden on market-based rate sellers.

69. Finally, we believe that the definition of control ( i.e. , arrangements, contractual or otherwise, that grant to a purchaser or reseller or to another third party who is not the legal owner of the facilities in question operational control over the facility) that we discuss earlier in this order already contains within it a materiality threshold. Changes in status that do not comprise control (and that do not otherwise trigger the reporting requirement) need not be reported.

70. Likewise, we reject PG&E's proposal to treat traditional utilities in this regard differently than other market-based rate applicants. PG&E's suggestion that the Commission link the change in status reporting requirement to increases in wholesale sales or revenues is inconsistent with the market-based rate four-part test which evaluates, among other things, whether an applicant is a pivotal supplier and the applicant's size in relation to the market. However, to the extent an applicant has historical wholesale sales and transmission data it believes is relevant, the Commission encourages the inclusion of such data in the applicant's submittal, and the Commission will consider such data in its analysis.

71. In the NOPR, the Commission also asked whether the applicant should have a reporting requirement if portions of the applicant's transmission system are taken out of service for a significant period of time (thus potentially affecting the scope of the relevant geographic market). If so, we sought comments on what criteria should trigger this reporting requirement.

72. A number of commenters support the extension of the reporting requirement to cover transmission outages and propose specific thresholds for triggering the reporting requirement. The California Public Utilities Commission (California Commission) states that the Commission should require reporting (and provide guidelines regarding when such reporting is required) when a transmission facility remains congested over a specified period of time such that market power could result. 103 Powerex supports the imposition of a reporting requirement for transmission outages that last for a significant period of time, but requests that the Commission clarify that the reporting requirement applies only to the market-based rate seller that owns or controls the transmission facilities suffering an outage and not to its affiliates. 104 Powerex notes that, in any case, information on transmission outages typically is otherwise available on the transmission owner's Open Access Same-Time Information System (OASIS). 105 Calpine submits that the transmission providers' reporting requirement should cover instances where a transmission outage that lasts 10 days or more results in a decrease of 10 percent or more in the amount of total transmission capacity on transmission facilities operated by the transmission provider within the control area in which the public utility owns or controls generating capacity, or in facilities connecting to an adjacent control area. 106 APPA and TAPS propose that transmission providers be required to report all non-public, extended transmission outages to the Commission's Office of Market Oversight and Investigation for monitoring and to publicly report extended outages of certain designated critical facilities. 107 NASUCA contends that all entities with market-based rate authority affected by an extended outage should be required to report such outages regardless of whether they own the affected transmission assets. 108

73. Certain investor-owned utilities such as FirstEnergy and Xcel oppose a reporting requirement for transmission outages, arguing that it is unnecessary because such outages are reported on a transmission provider's OASIS. 109 National Grid argues that transmission outages should not be reportable where such outages are administered by independent entities such as an ISO or an RTO. 110

74. Other investor-owned utilities such as Avista and Cinergy support the reporting requirement for major transmission outages that last longer than one year. 111 Duke also agrees that transmission outages should be reportable provided that they are expected to last 6 months or more and that they reduce available transmission capacity on the path or flowgate in question by 20 percent of the posted total transmission capability of that path. 112 Cinergy further suggests that, for transmission outages that occur within an RTO-operated market, the filing of the change in status should be made by the RTO, in consultation with the transmission owner. 113

75. After careful consideration of the comments, we are not prepared at this time to require the reporting of transmission outages per se as a change in status. However, to the extent a transmission outage affects one or more of the factors of the four-part market-based rate test ( e.g. , if it reduces imports of capacity by competitors that, if reflected in the generation market power screens, would change the results of the screens from a “pass” to a “fail”), a change of status filing would be required. Because such instances would occur on a company-specific basis, a minimum threshold ( e.g. , 10 percent reduction in capacity) is not workable. We will consider this matter further in the context of the generic rulemaking in Docket No. RM04-7-000 in which we are addressing, among other things, issues associated with transmission market power.

76. Beyond ownership or control of generation or transmission facilities or inputs to electric power production and affiliation with any entity not disclosed in the filing that owns or controls generation or transmission facilities or inputs to electric power production or affiliation with any entity that has a franchised service area, we sought comment as to whether there are other arrangements, contractual or otherwise, that should be promptly reported to the Commission. For example, we posed the following questions:

• What types of arrangements, contractual or otherwise, do market-based rate sellers enter into that could cause a need for the Commission to revisit the continuing basis of the grant of market-based rate authority for such sellers?

• What threshold of materiality, if any, of such arrangements should be met before such arrangements need be reported to the Commission?

• Should marketing alliances, brokering arrangements, tolling agreements or other sales-oriented arrangements be reported?

77. APPA, NASUCA and TAPS support the imposition of the reporting requirement for such sales-oriented arrangements and request that the Commission consider subjecting a wider range of arrangements to the reporting requirement. 114 NASUCA recommends that financial transactions including, but not limited to, the above types of sales-oriented arrangements should be covered by the reporting obligation, because such transactions provide the same type of control over power sales as ownership of physical assets would. 115 TAPS recommends that the Commission consider long-term maintenance agreements that grant a market-based rate seller the ability to decide when such maintenance is performed because, if the entity providing maintenance also operates facilities in the same market or has an affiliate that does so, its decisions about when to perform the maintenance (thereby possibly requiring an outage) could be influenced by its or its affiliate's sales activities in the market. 116 APPA, Powerex, and TAPS support an approach of listing the specific types of arrangements that the Commission expects to be reported to provide clarity to power sellers. 117

78. BP Energy, however, questions whether brokering agreements can be subjected to the reporting requirement. BP Energy asserts that it is not presently clear whether brokering activities and agreements are subject to the Commission's jurisdiction under the FPA. 118 BP Energy requests that, if the Commission intends to require reporting of brokering agreements, the Commission should identify the basis and scope of its claimed jurisdiction. Tractebel also questions the Commission's jurisdiction over such arrangements and argues that brokering arrangements should not be reportable, given that information on such arrangements need not be reported as part of an application for market-based rate authority or a triennial review. 119

79. Cinergy, EEI and Sempra argue that the Commission's suggestion to require reporting of specific types of contracts would elevate the form of the agreement over the substance. Cinergy opposes the Commission's proposal in the NOPR regarding other reportable arrangements, which it characterizes as a “label-based” approach, because there is little standardization or uniformity in the industry as to the content of such agreements. Cinergy urges the Commission to instead focus on the attributes of the agreement in question, i.e. , what degree of control over generation or transmission it conveys. 120 EEI similarly argues that the reporting requirement should be limited to those arrangements in which the seller acquires control over generation or transmission facilities, franchised distribution service facilities or production inputs exceeding the thresholds established by the Commission. 121

80. Sempra opposes as unnecessary the proposal in the NOPR to require reporting of specific types of contracts, arguing that the Commission's existing requirement that a notice of a change in status must be filed when an applicant acquires, or gains control of, additional generation or transmission assets already captures a transaction like that described in the El Paso Electric Power Co. case. 122 Sempra further argues that to require market-based rate sellers to file updates for a broad, ill-defined list of commercial arrangements would unfairly place the burden on the market-based rate seller to guess which commercial relationships to report, in violation of the Commission's decision in Morgan Stanley Capital Group, Inc., where the Commission concluded that entities with market-based rate authority no longer needed to report “business and financial arrangements between power marketers and their customers and transmission providers. 123

81. APPA, Powerex, and TAPS, on the other hand, support an approach of listing the specific types of arrangements that it expects to be reported because this approach provides clarity to sellers. 124 For example, APPA and TAPS argue that these arrangements should be reported because they may provide a market-based rate seller with the means to determine whether capacity is offered into a market or whether a competitor can or will enter a market and may create opportunities for sellers to coordinate their behavior with other competitors. APPA and TAPS further emphasize that tolling agreements should be reported because they allow a fuel supplier to control the plants' production of energy for sale, thus affecting market outcomes, even if the fuel supplier does not operate the plant. 125

82. Based on our review of the comments received, we find that contracts or arrangements that convey ownership or control over generation, transmission or other inputs to electric power production, other than fuel supplies, should be reported as a change in status. This is consistent with the four-part test the Commission relies upon in determining whether to grant market-based rate authority. Specifically, the April 14 Order requires an applicant to include in its analysis all capacity owned or controlled by the applicant or its affiliates. 126

83. We agree in principle with the comments submitted by Cinergy, EEI and Sempra, which stated that the label placed on a specific contract does not determine whether it constitutes a reportable change in status. Instead, it is the manner in which the specific terms and conditions of the contract or arrangement convey ownership or control of the generation, transmission or other inputs to electric power production. Nevertheless, we believe that providing a non-exclusive, illustrative list of other reportable arrangements will assist market-based rate sellers in complying with their reporting obligations. Therefore, we clarify that agreements that relate to operation (including scheduling and dispatch), maintenance, fuel supply, risk management, and marketing that transfer the control of jurisdictional assets are subject to the change in status reporting requirement. These types of arrangements have been referred to as energy management agreements, asset management agreements, tolling agreements, and scheduling and dispatching agreements.

84. With respect to the form and content of change in status reports, the NOPR proposed that the market-based rate seller be required to submit a transmittal letter including a description of the change in status and a narrative explaining whether (and, if so, how) this change in status reflects a departure from the characteristics relied upon by the Commission in originally granting the seller market-based rate authority, in particular, whether the change in status affects the results of any of the prongs of the four-part test that the Commission uses to determine whether a public utility qualifies for market-based rate authority. If the market-based rate seller believes that a change in status does not affect the continuing basis of the Commission's grant of market-based rate authority, we proposed that it should clearly state the reasons on which it bases this conclusion.

85. BP Energy, California EOB, Calpine, EPSA, and Powerex agree that market-based rate sellers should provide a narrative explaining the manner in which changes in status reflect a departure from the characteristics relied upon for market-based rate authorization. 127 EPSA submits that a short transmittal letter explaining the transaction should suffice to put the parties and the Commission on notice of any possible change in status. According to EPSA, requiring more of applicants would be administratively burdensome, costly and unnecessary. EPSA contends that that Commission's goal should be to adopt a cost-effective approach to protecting customers from the exercise of market power, while at the same time minimizing the costs and uncertainty associated with a change in status, and that a short transmittal letter would accomplish that goal. 128

86. BP Energy, Calpine, and Powerex argue that the report should consist of a narrative only and should not include an updated market analysis such as that which is required by the triennial review. 129 Similarly, SoCal Edison supports the timely provision of a narrative that includes germane information, including a recitation of the key dimensions of the transaction, but opposes a requirement to make an extensive showing to justify retention of market-based rate authority. 130

87. With respect to contractual arrangements, the United States Department of Justice (DOJ) opposes a reporting requirement that might call for a full-blown competitive analysis for every reportable transaction and instead suggests that market-based rate sellers simply file a copy of the contract concerned along with a summary of its key attributes that have an effect on the parties' incentive or ability to exercise market power. 131 DOJ also suggests that Commission limit the obligation of applicants to disclose confidential, “business sensitive” information, which may discourage utilities from entering into otherwise efficient agreements, and customer-specific transaction data, which may reduce competition by facilitating collusion among competitors in oligopolistic markets. 132

88. Cinergy proposes that the Commission adopt a two-tiered approach to reporting, depending on whether the event to be reported is material or not. In cases where an applicant concludes in good faith that the change is non-material, the applicant would submit a short letter describing the event and briefly informing the Commission why the applicant believes the event is non-material. For material changes in status, the applicant would describe with greater particularity the basis for a continued grant of market-based rate authority, including an updated market analysis where appropriate. 133

89. NRECA urges the Commission to minimize the reporting requirement for smaller market participants. NRECA suggests that the Commission could do so by including in the final rule a provision for waiver of the reporting requirement for small market participants that can show that the likelihood that the changes in status in question could affect the competitiveness of those markets is de minimis . Alternatively, the Commission could clarify that the report for small market participants may be as simple as a two-sentence letter describing the change and averring that they have not acquired market power as a result. 134

90. Some commenters contend that the change in status report should include some form of market power analysis. NASUCA contends that the report should include a revised triennial rate review filing and an updated market power analysis. 135 Powerex and EPSA urge the Commission to affirmatively state that market participants may submit, in addition to the narrative explanation, the summary pages of their original pivotal supplier and market share analyses, modified to reflect the changed circumstances. 136

91. Finally, EEI and FirstEnergy argue that even the submission of a narrative only would be unduly burdensome and superfluous. According to EEI, a narrative filing requirement would be problematic because market-based rate sellers would not always know the complete scope and nature of the characteristics relied upon by the Commission or any changes in the ownership or control of other market participants in the market area and because the Commission has not yet adopted final generation market power screens or articulated the screens and tests for the remaining three prongs. EEI proposes that, instead, market-based rate sellers should be required to provide the Commission only with a description of the transaction and that such sellers should only be required to examine the implications of a change in status (as a supplement to the notice of a change in status) if the Commission or a market participant raises a concern. 137

92. FirstEnergy objects to the narrative requirement, first, on the ground that it is superfluous: the only changes in status for which a report may be required are changes in status that reflect a departure from the characteristics that the Commission relied upon in granting market-based rate authority; however, if a change in status does not affect the relevant characteristics, no report is required. FirstEnergy further contends that the narrative requirement unreasonably imposes on each seller an affirmative obligation to justify the continuation of their market-based rate authority every time it engages in a transaction that constitutes a reportable change in status, which would be costly and time-consuming. FirstEnergy also argues that there is no reason to believe that generation suppliers are uniquely situated to provide the kind of information that the Commission may need to evaluate whether a change in status might affect the continuation of a supplier's market-based rate authority, e.g. , information concerning the size of the market or the availability of transmission import capacity into the market, which is equally available to the supplier and its competitors. FirstEnergy therefore suggests that, in the absence of a demonstration that legitimate concerns exist, the supplier should not be required to spend the time and resources that may be required to defend the continuation of its market-based rate authority between its triennial market power updates. 138

93. We will adopt the proposal in the NOPR that the market-based rate seller submit a transmittal letter, including a description of the change in status and a narrative explaining whether (and, if so, how) this change in status reflects a departure from the characteristics relied upon by the Commission in originally granting the seller market-based rate authority.

94. After careful consideration of the comments received, we will not specify a uniform length for the narrative that an entity must file to explain whether a given change in its status reflects a departure from the characteristics relied upon by the Commission for the original and continued grant of market-based rate authority. The nature of the change that triggers the reporting requirement will necessarily determine the length and quality of the narrative, as well as whether additional documents and analysis is needed. It is incumbent upon the applicant to decide whether the change in status is a material change and to provide adequate support and analysis. This is consistent with our approach to new applications for market-based rate authority, where it is the applicant's responsibility to determine what to report and the degree of support and analysis to include.

95. Further, we will not require entities affected by a change in status to automatically file an updated market analysis, such as that required by the triennial review. However, an entity may provide such an analysis if it chooses. The Commission reserves the right to require additional information, including an updated market power analysis, if necessary to determine the effect of an entity's change in status on its market-based rate authority.

96. In addition to including this reporting requirement in the Commission's regulations, we proposed that this reporting requirement be incorporated into the market-based rate tariff of each entity that is currently authorized to make sales at market-based rates, as well as that of all future applicants. Market-based rate sellers would be required to submit a conforming provision to their market-based rate tariffs at the time that they file any amendment to their tariffs or (if earlier) when they apply for continued authorization to sell at market-based rates ( e.g. , in their three-year updated market power analysis). However, the Commission proposed that the obligation to report be effective at the time that the Final Rule becomes effective.

97. Most commenters support the inclusion of the reporting requirement into the market-based rate tariff of each seller. No substantive opposition was expressed by commenters.

98. We will adopt the proposal in the NOPR and require that the reporting requirement be incorporated in the market-based rate tariffs of each entity that is currently authorized to make sales at market-based rates, as well as that of all future applicants. Market-based rate sellers will be required to include the reporting requirement in their market-based rate tariffs either at the time that they file any amendment to their tariffs, when they report a change in status under this Final Rule, or when they file their three-year updated market power analysis, whichever occurs first. However, regardless of the date on which the seller amends its market-based rate tariff to include the reporting requirement, such reporting requirement will be considered part of the seller's market-based rate tariff as of 30 days after the date of publication of this Final Rule in the Federal Register .

99. With respect to the procedures for reporting a change in status, we proposed in the NOPR that such notifications be filed no later than 30 days after the occurrence of the triggering event. We sought comment as to whether this proposed time period is appropriate.

100. Calpine and NRECA support the proposed 30-day reporting period. 139 Calpine urges the Commission to clarify the event that marks the change in status and starts the 30-day clock running. Calpine proposes that it should be based on the legal effective date of the triggering event. For an increase in ownership or control of generation capacity, Calpine states that this would be the date that the public utility legally assumes ownership or control over the asset. For a self-build or repowering event, it could be the date of commercial operation. 140 NRECA rejects arguments that the 30-day reporting period is burdensome, noting that events constituting a change in status such as the acquisition or disposition of generation assets, require advance planning in excess of 30 days and that the reporting requirement can be built into the planning process for such transactions.

101. ELCON asks the Commission to modify the 30-day reporting requirement to reduce the potential burden on entities that cannot exercise market power such as large industrial users that own and operate a growing amount of behind-the-meter customer generation. ELCON suggests that, first, the final rule keep the 30-day initial notice period that would alert the Commission that a potential change in status may have occurred, but it should then allow the respondent an additional 60 days thereafter to file additional documentation as necessary.

102. APPA, BP Energy and TAPS suggest the Commission permit prospective reporting, to the extent possible, of known or expected changes in status. 141 IEU-Ohio/PJMICC would go further and require prospective reporting at least 60 days before the circumstances affecting market-based rate authority actually occur, to the maximum extent possible. 142 Similarly, NASUCA urges the Commission to require that the report be submitted no later than the effective date of the change in status. 143 In contrast, Avista argues that the time period for reporting should not begin to run until after the date of commercial operation and/or control over the asset is reached. 144 Tractebel requests the Commission to consider pre-authorizing certain changes in status, as it does, for example in the context of changes in status regarding qualifying facilities under PURPA. 145

103. Other commenters, however, argue that the 30-day period is too short. EPSA, Xcel, and Powerex propose that change in status reports should be submitted on a quarterly basis, for example, concurrently with EQRs or Form 3-Qs. 146 Duke suggests that the reporting period should be extended to six months, 147 while Avista recommends a period of 60 days after initial delivery under a long-term contract begins. 148

104. Calpine and EPSA request clarification of the procedures for filing and responding to change in status reports to avoid uncertainty. EPSA proposes that such clarification should occur in a supplemental NOPR whereby the comments in this NOPR and in the supplemental NOPR can be considered by the Commission. Further, EPSA suggests that this reporting requirement be an interim requirement pending final issuance of a comprehensive market-based rate authority framework in Docket No. RM04-7-000 or another comprehensive proceeding. 149 Calpine requests clarification of whether the reports should be filed in the same docket that originally granted market based-rate authority, whether the reports would be publicly noticed, and whether the Commission intends to respond to the reports if they raise no concerns. 150

105. We are not persuaded by the suggestions to increase the 30-day period to a longer period of time, whether 60 days, quarterly, or six months. Thirty days appropriately balances the amount of time the applicant needs to prepare its filing against our need for timely information regarding changes in status that may affect prices and markets. The Commission finds the 30-day time period an appropriate one in which to receive information about a change in status so as to enable the Commission to effectively carry out our statutory responsibility to oversee competitive conditions in wholesale electricity markets. For this reason, we are not persuaded by the suggestion that we require entities to file changes in status concurrently with their EQRs. As discussed above, quarterly reporting would not provide the Commission with information on market developments in a sufficiently timely manner to perform our statutory duties. Furthermore, contrary to the suggestions of some commenters, combining the change in status reporting requirement with other reporting requirements, e.g. , EQRs, would not create any efficiencies or reduce the burden on either the Commission or market-based rate sellers. In particular, the Commission has developed a specific electronic format for reporting transactions in EQRs  151 that would not accommodate the range of events that constitute changes in status.

106. We clarify that reports of changes in status must be filed no later than 30 days after the legal or effective date of the change in status, including a change in ownership or control, whichever is earlier. Parties are free to file reports of prospective changes, but that filing must contain the same information it would if it had filed after the change in status. We note that when performing the Commission's generation market power screens, applicants are prohibited from making forward-looking adjustments.

107. In response to a request for additional information about the processing of these reports, we clarify that the report should be filed in the same docket in which market-based rate authority was granted, and it should be served on the service list for that docket. The report will be noticed, and a comment period will be established.

108. BP Energy, EEI, EPSA and FirstEnergy request that the Commission clarify that change in status reports are purely informational and that any revisions or revocations to an entity's market-based rate authority will be made pursuant to section 206 proceedings. 152 With respect to the burden of proof, Calpine recommends that the public utility should have the burden to demonstrate that it is still entitled to market-based rates after the change in status occurs and that if the Commission or any party believes that a report indicates that the basis for a public utility's market-based rates has been undermined by the change in status, there should also be a remedy through a section 206 action. 153

109. Powerex and SoCal Edison note that the NOPR failed to address the treatment of confidential and commercially sensitive information, and SoCal Edison requests that the Commission clarify that it requires only the minimal reasonable information necessary. 154

110. With respect to the procedural rights of third parties, APPA and TAPS argue that third parties should be permitted to report known or expected changes in status and that the Commission should permit them the opportunity to submit comments on change in status reports. Those reports meriting closer attention should result in the Commission's issuing a show cause order asking the seller to justify continuation of market-based rate authority. 155

111. Finally, Tractebel argues that the Commission should provide the opportunity for market-based rate sellers that comply with the reporting requirement, as well for protesters and intervenors, to obtain a timely “redetermination” or “reaffirmation” of their market-based rate authority. 156

112. Cinergy proposes that, for purposes of regulatory certainty, the Commission should commit to issue orders on notices of changes in status within 60 days of filing. Where an order accepts for filing a change in status report, such acceptance would be deemed an acknowledgement by the Commission that the reported event does not affect the applicant's market-based rate authorization. Similarly, if the Commission does not issue an order within 60 days, any reported transaction undertaken after such a 60-day period that conforms materially to the description of the transaction in the notice should fall within a safe-harbor and not trigger penalties, refunds or loss of market-based rates. 157

113. In response to the requests above, we will clarify the legal effect of a notice of a change in status and the procedures that the Commission will follow in acting on notices of changes in status. First, a notice of a change in status, like the triennial update filing requirement, is a filing made in compliance with the terms and conditions under which the Commission has granted market-based rate authority. As discussed above, we will require that the reporting requirement be incorporated in the market-based rate tariffs of each market-based rate seller. Thus, a notice of change in status is an integral part of the market-based tariff, compliance with which is a condition for the retention of market-based rate authority. Consistent with the Commission's current practice, the Commission will continue the same procedures it has followed in processing filings of changes in status. Namely, the Commission will issue a notice of the filing to provide an opportunity for public comment. The filing will receive a subdocket under the docket number in which the seller originally received market-based-rate authority. The Commission, where appropriate, may request additional information from the market-based rate seller, institute a section 206 investigation or inform the parties that the Commission does not intend to take any further action regarding the change in status filing.

114. We further note that because a notice of a change in status, like a triennial update, is a compliance filing, rather than a rate filing under section 205 of the FPA, the Commission is not required to take action within 60 days. Consequently, we will reject Cinergy's proposal to commit to issuing an order on notices of a change in status within 60 days and to establish a safe harbor where the Commission has not acted on the filing within 60 days after receipt. Further, the filing alone may not provide sufficient information for the Commission to make a definitive finding regarding the impact of the change in status on the filing entity's market-based rate authority, and the Commission may require more than 60 days to gather the necessary information. However, it is the Commission's intention to act on these filings as expeditiously as possible.

115. With respect to the requests of BP Energy, EEI and FirstEnergy that the Commission clarify that it will only revoke or revise market-based rate authority pursuant to a section 206 proceeding, we note that the Commission's long-standing policy, in conformance with the FPA, has been to do so pursuant to a section 206 proceeding, 158 and we will not change that policy here. In section 206 proceedings, the complainant or the Commission bears the burden of proof. Accordingly, we cannot change the statutory burden in response to Calpine's request. 159

116. Commission regulations set forth the procedures for requesting special treatment for confidential and commercially sensitive information to prevent public disclosure, 160 and we do not find it necessary to establish additional procedures for such information contained in a notice of a change in status in response to the requests of Powerex and SoCal Edison.

117. With respect to APPA's and TAPS' concerns about the rights of third parties, we clarify that nothing in this final rule or the Commission regulations adopted herein changes the rights of third parties to file in response to a notice of change in status or to file a complaint pursuant to section 206.

118. Office of Management and Budget (OMB) regulations require OMB to approve certain information collection requirements imposed by agency rule. 161 The Commission solicited comments on the Commission's need for this information, whether the information will have practical utility, the accuracy of provided burden estimates, ways to enhance the quality, utility and clarity of the information to be collected, and any suggested methods for minimizing respondents' burden, including the use of automated information techniques.

119. Estimated Annual Burden to satisfy the reporting requirement, the Commission expects respondents to submit a transmittal letter including a description of the change in status and a narrative explaining whether (and, if so, how) this change in status reflects a departure from the characteristics relied upon by the Commission in originally granting the seller market-based rate authority. The Commission estimates that, on average, it will take respondents six hours per response and that approximately 25 percent of current market-based rate sellers would experience a change in status in any given year.

Title: Electric Rate Schedules and Filings, Reporting Requirement for Changes in Status For Public Utilities With Market-Based Rate Authority (FERC-516).

Action: Proposed collection.

OMB Control No.: 1902-0096.

Respondents: Businesses or other for profit.

Frequency of Responses: On occasion.

Necessity of Information: The proposed regulations will revise market-based rate sellers' reporting obligation and are intended to ensure that rates and terms of service offered by market-based rate sellers remain just and reasonable.

Internal Review: The Commission has reviewed the proposed amendment to its regulations to establish a reporting obligation for changes in status and has determined that these regulations are necessary to ensure just and reasonable rates. These regulations, moreover, conform to the Commission's plan for efficient information collection, communication, and management within the electric utility industry. The Commission has assured itself, by means of internal review, that there is specific, objective support for the burden estimates associated with the information/data retention requirements.

120. Interested persons may obtain information on the reporting requirements by contacting: Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, Attention: Michael Miller, Office of the Executive Director, phone: (202) 502-8415, fax: (202) 273-0873, e-mail: michael.miller@ferc.gov . Comments on the proposed requirements of the subject rule may also be sent to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503, Attention: Desk Officer for the Federal Energy Regulatory Commission, phone: (202) 395-4650.

121. DOJ contends that the preparation of the transmittal letter may take more than six hours to prepare and may impose significant costs on applicants. 162

122. The estimate contained in the NOPR of the time necessary to comply with the reporting requirement is an average. While such a letter may take more than six hours in some cases, we believe that in most cases compliance will take substantially less time. As we explain above, the more significant events triggering the reporting requirement will also trigger other reporting requirements, e.g. , a section 203 application. In such a case, market-based rate sellers may incorporate by reference the related filing, and compliance with the change in status reporting requirement accordingly would require a minimal amount of time to prepare.

123. 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. 163 The Commission has categorically excluded certain actions from this requirement as not having a significant effect on the human environment. Included in the exclusion are rules that are clarifying, corrective, or procedural or that do not substantially change the effect of the regulations being amended. 164 Thus, we affirm the finding we made in the NOPR that this final rule is procedural in nature and therefore falls under this exception; consequently, no environmental consideration would be necessary.

124. The Regulatory Flexibility Act of 1980 (RFA)  165 generally requires a description and analysis of final rules that will have significant economic impact on a substantial number of small entities. 166 The Commission is not required to make such analyses if a rule would not have such an effect.

125. The Commission concludes that the final rule would not have such an impact on small entities. Based on past experience, most of the sellers having changes in status that would likely trigger a filing under the proposed regulations would be entities that do not meet the RFA's definition of a small entity. Therefore, the Commission certifies that this final rule will not have a significant economic impact on a substantial number of small entities.

126. In addition to publishing the full text of this document in the Federal Register , the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through FERC's Home Page ( http://www.ferc.gov ) and in FERC's Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.

127. From FERC's Home Page on the Internet, this information is available in the Commission's document management system, 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.

128. User assistance is available for eLibrary and the FERC's Web site during normal business hours. For assistance, please contact FERC Online Support at 1-866-208-3676 (toll free) or 202-502- 6652 (e-mail at FERCOnlineSupport@FERC.gov ), or the Public Reference Room at 202-502-8371, TTY 202-502-8659 (e-mail at public.referenceroom@ferc.gov ).

This Final Rule will take effect March 21, 2005. The Commission has determined with the concurrence of the Administrator of the Office of Information and Regulatory Affairs of the Office of Management and Budget, that this rule is not a major rule within the meaning of section 251 of the Small Business Regulatory Enforcement Fairness Act of 1996. 167 The Commission will submit the Final Rule to both houses of Congress and the General Accounting Office. 168

1. The Federal Energy Regulatory Commission is amending its regulations to establish requirements governing the conduct of open seasons for capacity on proposals to construct Alaska natural gas transportation projects. This Final Rule fulfills the Commission's responsibilities to issue open season regulations under section 103 of the Alaska Natural Gas Pipeline Act (the Act), enacted on October 13, 2004. 1 Section 103(e)(1) of the Act directs the Commission, within 120 days from enactment of the Act, to promulgate regulations governing the conduct of open seasons for Alaska natural gas transportation projects, including procedures for allocation of capacity. As required by section 103(e)(2) of the Act, these regulations (1) include the criteria for and timing of any open season, (2) promote competition in the exploration, development, and production of Alaska natural gas, and (3) for any open seasons for capacity exceeding the initial capacity, provide for the opportunity for the transportation of natural gas other than from the Prudhoe Bay and Point Thomson units.

2. As Congress has recognized, construction of a natural gas pipeline from the North Slope of Alaska to markets in the lower 48 states is in the national interest and will enhance national energy security by providing access to the significant gas reserves in Alaska to meet anticipated demand for natural gas. A successful Alaska natural gas transportation project will have to overcome a variety of significant logistical and procedural obstacles. The Commission strongly believes that it is in the mutual interest of the parties interested in such a project to reach a common understanding, in order to support a proposal that meets their needs and those of the Nation. To that end, the Commission urges the parties to expend their efforts in negotiation, compromise, and project development, such that this vital project can become a reality.

3. Under the Act, Congress mandated the expedited processing by the Commission of any application for an Alaska natural gas transportation project, namely any natural gas pipeline that carries natural gas derived from that portion of Alaska lying north of 64 degrees north latitude to the border between Alaska and Canada. The Act specifically directs the Commission to prescribe the rules which will apply to any open season held for the purpose of acquiring capacity on any Alaska natural gas transportation project, including the criteria for allocating capacity among competing bidders.

4. In response to the Act's directive, on November 15, 2004, the Commission issued in Docket No. RM05-1-000 a Notice of Proposed Rulemaking (NOPR) containing the Commission's proposed Alaska natural gas transportation project open season regulations as a new subpart B to part 157 of the Commission's regulations (69 FR 68106, Nov. 23, 2004). The NOPR stated that comments were to be filed by December 17, 2004, and that the Commission intended to issue the final regulations by February 10, 2005, in order to comply with the Act's 120-day deadline.

5. The Commission held a public technical conference in Anchorage, Alaska on December 3, 2004 to develop a record in this proceeding. At the conference, speakers including Alaska elected officials, Alaskan Natives, representatives of potential project sponsors, representatives of potential shippers, and representatives from other agencies or affected enterprises or the general public presented their views on the NOPR and related issues. A transcript of the technical conference was filed in the record in this proceeding. 2

6. Before the NOPR was issued, the Commission received comments and suggested open season requirements from several interested parties, including BP, ConocoPhillips, and ExxonMobil (North Slope Producers), 3 other natural gas producers, potential project sponsors, and members of the Alaska legislature. In addition to the pre-NOPR comments and technical conference presentations, comments were filed by 25 interested parties. 4 One group of commenters, including the North Slope Producers, who together own the majority of proven gas reserves on Alaska's North Slope at Prudhoe Bay and Point Thomson, and several pipeline companies (TransCanada, MidAmerican/AGTA, and Enbridge) are potential sponsors of an Alaska natural gas transportation project. Another group of commenters is made up of entities with Alaska-based interests  5 , including elected officials. Yet another definable group consists of potential shippers, including explorers and producers other than the North Slope Producers, marketers, local distribution companies, power generators, and industrial end users.

7. The comments filed in response to the NOPR are discussed at length below, broken down by specific issues. However, broadly speaking, several commenters, led by the North Slope Producers, MidAmerican/AGTA, and TransCanada, expressed general support for the Commission's approach in developing the proposed regulations in the NOPR. 6 These commenters perceive the proposed regulations as being not overly prescriptive, yet providing a fair and open process to obtain capacity on an Alaska pipeline on a non-discriminatory, non-preferential basis. As potential shippers, these commenters are encouraged that the proposed rules permit the sponsors the flexibility to design and conduct the initial and expansion open seasons. They claim that such flexibility is important in helping a project sponsor properly size the pipeline and satisfy the demands of financers.

8. A number of the commenters, however, fault the Commission for not proposing detailed rules regarding certain elements of the open season, including timing of the open season, and the criteria for evaluating bids and allocating capacity in the event capacity on the proposed project is oversubscribed. These commenters claim that the Commission has deferred to the project sponsors too much of the responsibility of establishing the criteria for and timing of open seasons for Alaska projects. In addition, commenters whose interests are tied to the State of Alaska claim that the proposed rules ignore the requirements of section 103(g) regarding in-state needs for natural gas. 7 Potential project sponsors favor the flexibility they believe is provided in the proposed rules in order to appropriately develop an Alaska natural gas transportation project. Other interested parties express concern that the North Slope Producers, either as project sponsors or as producers whose reserves will support the initial development of the project, will use that flexibility to develop open season rules to accommodate their own interests, to the exclusion and detriment of other explorers, developers and producers of Alaska natural gas, as well as of those seeking access to the pipeline for in-state natural gas demands.

9. As explained in the NOPR, there are no current Commission regulations respecting open seasons. To date, the Commission's policy, developed through its orders and opinions, is that all new interstate pipeline construction be preceded by a non-discriminatory “open season” process through which potential shippers may seek and obtain firm capacity rights. Congress has determined that it is necessary to formalize this Commission policy with specific regulations governing the conduct of open seasons for an Alaska natural gas transportation project. Indeed, the tremendous size, scope, and cost of an Alaskan pipeline, the long lead-time needed for such a project, environmental sensitivities, and the competitive conditions that are unique to such a project warrant special consideration and oversight. In addition, Congress specifically required that the open season regulations promote competition in the exploration, development, and production of Alaska natural gas and, as to any open season for expansion of the initial capacity of any Alaska natural gas transportation project, the Commission's regulations are to specifically provide the opportunity for gas other than Prudhoe Bay and Point Thomson production to have access to the pipeline.

10. As revealed in detail in the comments to the NOPR, there are complex, competitive conditions surrounding an Alaska natural gas transportation project, which are intensified by the generally agreed upon fact that there will be only one such pipeline for the foreseeable future. The North Slope Producers hold the proven reserves that may be able to support the initial construction of the project, and may now be in a position to make long-term capacity commitments to the project. Other producers and explorers, whose potential gas reserves are not yet commercially developed, may not currently be in a position to do so. Instead, they anticipate a need for capacity some time in the future, and express reluctance to make the large investment required to explore for and develop Alaska gas without being reasonably assured that they will have access to pipeline capacity when their gas is ready to move to market. Shippers seeking to move gas only within the State of Alaska for in-state uses may also seek pipeline capacity. While the North Slope Producers anticipate paying rates covering the costs of transportation through the entire project, shippers planning to make deliveries in Alaska likely will seek mileage-based or zone rates.

11. We have striven in this rule to balance the need to allow project sponsors the flexibility to develop and bring to market Alaska natural gas with the equally compelling needs to ensure fair competition in the transportation and sale of natural gas, promote the development of natural gas resources in addition to those in the North Slope, and consider Alaskan in-state requirements. As discussed in more detail below, we are not inclined to impose open season rules that prescribe such details as when open seasons must occur and precise criteria to be used in evaluating bids and allocating capacity. To do so could potentially unduly limit a prospective sponsor's ability to design and finance a viable project, and thereby add to the already-daunting challenges that face an Alaska natural gas transportation project sponsor.

12. At the same time, however, we are well aware of the risks to competition imposed by a project that is owned or primarily sponsored by a small group. Thus, we are imposing strict requirements on all proposals, and particularly on affiliate-owned projects, with respect to the public disclosure of information, to ensure that there is a level playing-field. As we discuss below, we will require applicants for an Alaska pipeline project to provide detailed information as to project design, how capacity is to be allocated, and proposed rates, terms and conditions. This will allow us to be in a position to monitor whether competition for capacity is fair. In addition, while we are permitting pre-subscription for “anchor” shippers, 8 we are requiring that contracts with such shippers be made publicly available, and that all shippers seeking the same type of capacity be offered service on the same terms and conditions. We will keep these considerations in mind, not only during an open season, but also during our consideration of any application for an Alaska natural gas transportation project placed before us.

13. Furthermore, we will bear in mind the concerns expressed by the non-North Slope producers in considering expansion issues. Thus, we will look to see whether a proposed pipeline is designed not only to meet immediate needs, but also to provide a reasonable opportunity for access to low-cost expansion capacity. Also, as discussed below, we will look, with the constraints of the Act in mind, to determine that rates for expansion capacity are set at levels that will promote competition in exploration and development of Alaska natural gas, not just protect the interests of initial shippers.

14. In addition to the careful scrutiny we will give to any Alaska pipeline proposal, the need to provide explorers and developers of Alaska natural gas with reasonable assurances that they will have access to capacity on any Alaska natural gas pipeline can be met through existing Commission oversight authority and certificate authorization authority, as supplemented, enhanced, and guided by the findings and requirements of this final rule, the NGA, and the Act. Any complaints regarding these Alaska project issues can be addressed through several ways, including the Commission's Dispute Resolution Service, the Enforcement Hotline, or the Commission's Fast Track complaint process which, under the final rule, will have automatic application to complaints involving any Alaska natural gas transportation open season.

15. Moreover, under section 157.33, any application for a certificate of public convenience and necessity for a proposed Alaska natural gas transportation project must include a demonstration that the applicant has conducted an open season for capacity on its proposed project in accordance with the requirements of this subpart, and failure to provide the requisite demonstration will result in an application being rejected as incomplete. This provision will provide a strong disincentive to discriminatory or unduly preferential conduct. Finally, although not required, project sponsors have the option of seeking Commission pre-approval of a proposed notice of open season.

16. The Commission stated in the NOPR that its goal was to design an open season process that provides non-discriminatory access to capacity on any Alaska natural gas transportation project and, at the same time, allows sufficient economic certainty to support the construction of the pipeline and thereby provide a stimulus for exploration, development, and production of Alaska natural gas. It has been suggested that the Commission's stated goal improperly emphasizes the importance of providing certainty to project sponsors to facilitate construction of the project, when instead the Commission should focus on providing as much regulatory certainty as possible to natural gas explorers. 9 However, providing the economic certainty to support the building of an Alaska natural gas transportation project and promoting competition in the exploration and development and production of Alaska natural gas are not mutually exclusive goals. We conclude that emphasizing economic certainty to explorers, without balancing the similar needs of potential project sponsors, would overlook the Act's overall objective of facilitating the timely development of an Alaska natural gas transportation project, and to bring Alaskan natural gas to markets in Alaska and in the lower 48 states. Thus, we believe that the balanced approach we are taking here is appropriate.

17. In the Commission's view, exploration, development, and production of Alaska natural gas are best served by having a pipeline built and by ensuring that all potential initial and future shippers are able to obtain access on that pipeline under non-discriminatory, non-preferential terms. This rule will provide the framework for an open season process that will provide reasonable flexibility to pipeline sponsors, while ensuring sufficient exchange of information and regulatory oversight to ensure that the goal of fair, open competition in the transportation and sale of natural gas is met.

18. Proposed § 157.30 sets out the purpose of subpart B. That purpose is to establish rules for the conduct of any open season on any Alaska natural gas transportation project. Section 103(e)(2) of the Act provides that these regulations must include the criteria for and timing of any open season, promote competition in the exploration, development, and production of Alaska natural gas, and, for any open seasons for capacity exceeding the initial capacity, provide for the opportunity for the transportation of natural gas other than from the Prudhoe Bay and Point Thomson units. 10

19. The Commission is adopting § 157.30 with certain changes recommended by Alaska for purposes of clarity. Specifically, the revised section makes clear that the regulations apply to open seasons “for the purpose of making binding commitments for the acquisition of initial or voluntary expansion capacity” on any Alaska natural gas transportation project. We see no need to change the description of the purpose of the subpart from being “to establish the procedures for” an open season to being to “prescribe the rules,” as recommended by Alaska.

20. Proposed § 157.31 defines the terms “Alaska natural gas transportation project” and “Commission.” ANGDA maintains that the definition of “Alaska natural gas transportation project” should be expanded to include a project involving “a liquid natural gas project to transport liquefiable natural gas from Southcentral Alaska to the West Coast states.” ANGDA bases its proposed amendment on a November 18, 2004 amendment to section 116 of the Act whereby Congress included an entity determined to be qualified to construct and operate a liquefied natural gas project to transport liquefied natural gas from Southcentral Alaska to the West Coast states as a “qualified infrastructure project” for purposes of obtaining a loan guarantee. The amendment ANGDA relies on did not expand, much less refer to, the definition of an “Alaska natural gas transportation project.” Consequently, the Commission finds no basis to conclude that Congress intended to include any liquefied natural gas project within the meaning of “Alaska natural gas transportation project.”

21. While the NOPR's definition of “Alaska natural gas transportation project” is consistent with the Act's definition of that term, it does not fully define that term as it is defined in the Act. To be precise, the Commission is revising § 157.31 at § 157.31(a) to adopt the full statutory definition of that term. Additionally, the Commission is including for clarity new § 157.31(c), defining the term “voluntary expansion.”

22. The NOPR proposes that the open season regulations are to apply to any application to the Commission for a certificate of public convenience and necessity or other authorization for an Alaska natural gas transportation project, whether filed pursuant to the Natural Gas Act, the Alaska Natural Gas Transportation Act of 1976, or the Alaska Natural Gas Pipeline Act, and to applications for expansion of such projects. The proposed regulation also provides that the open season regulations do not apply to involuntary expansions pursuant to section 105, unless the Commission expressly so provides.

23. Alaska proposes language in the final rule that provides that the open season regulations will apply “to any Alaska Natural Gas Transportation Project for which a certificate of public convenience and necessity is sought pursuant to section 7 of the NGA and section 103 of the Alaska Natural Gas Pipeline Act.”  11 However, Alaska does not explain the basis for its proposed definition.

24. Section 102(2) of the Act defines an Alaska natural gas transportation project to include projects authorized under either the Alaska Natural Gas Transportation Act of 1976 or the Alaska Natural Gas Pipeline Act. Since the proposed regulation is consistent with this definition, the Commission sees no reason to amend it.

25. Proposed § 157.33 requires that any application for a certificate of public convenience and necessity for a proposed Alaska natural gas transportation project include a showing that the applicant conducted an open season for capacity on its proposed project that fully complies with the requirements of this subpart. To ensure compliance with this requirement, proposed § 157.33 provides that any application lacking such a showing will be dismissed as deficient.

26. One of the questions that the Commission posed in its NOPR was whether the Commission should allow pre-subscribed, reserved capacity such as was allowed in connection with open seasons for certain new Outer Continental Shelf (OCS) pipeline facilities.

27. Several commenters, including TransCanada, Alliance, the North Slope Producers, Enbridge, Doyon, and MidAmerican/AGTA state that the Commission should allow pre-subscribed capacity for an Alaska natural gas transportation project. TransCanada and the North Slope Producers state that the open season rules should allow for options such as pre-subscription agreements that will encourage or facilitate the successful development of an Alaska pipeline project. They believe that pre-subscription might grant the flexibility to sponsors and shippers that is required in view of the size, expense, risk, and long lead time involved in an Alaska project. Enbridge is convinced that these factors call for pre-subscription.

28. However, the supporters of pre-subscription also comment that steps can or should be taken in order to ensure that other shippers have the opportunity to obtain capacity on a non-discriminatory basis through an open season process. TransCanada, for instance, describes a situation where the sponsor enters into binding prearranged precedent agreements with “backstop” or “transition” shippers who commit to sign firm transportation agreements if no other shipper comes forward, but who agree to lower their capacity commitments to pre-agreed levels to allow the inclusion of other shippers who tender qualifying bids during the open season. In a similar fashion, MidAmerican/AGTA states that the open season rules should permit transportation commitments allowing pre-subscribed capacity to be prorated down to a minimum threshold level to allow others to obtain capacity in the event the total requested capacity exceeds design capacity.

29. Enbridge is confident that, even with pre-subscription, an open season conducted under the safeguards and transparency provided by the Commission's proposed rules will result in a pipeline designed to enable every creditworthy shipper to obtain the long-term capacity it needs. However, Enbridge claims that there can be no Alaska natural gas transportation project without the full, binding commitment of the North Slope Producers. Alliance is also a strong believer in the potential usefulness of pre-subscribed capacity in facilitating the development of an Alaska pipeline. However, also recognizing that the open season rules must promote competition in the exploration, development and production of Alaska gas, Alliance claims that limits could be placed on the amount of capacity available for pre-subscription, or that pre-subscription could be reserved for initial open seasons only.

30. Another group of commenters prefers that the Commission not allow pre-subscription of capacity and asks that if it is permitted, limitations and conditions be imposed in order to ensure that capacity is still available to prospective shippers which do not participate in pre-arranged agreements. These commenters include Anadarko, Alaska, Calpine and ChevronTexaco.

31. Anadarko argues that if the final rule approves the use of pre-subscription agreements, they must be subject to the outcome of the open season, and that potential bidders in the open season should be offered the same terms and conditions as the pre-subscribing shippers. Anadarko states that there are two distinct types of prospective shippers on an Alaska natural gas transportation project—the North Slope Producers and the explorers and producers of unproven or undeveloped Alaska natural gas—who are in long-term competition for the pipeline's capacity, and that pre-subscription favors the major producers to the detriment of those developing competing reserves. Second, Anadarko contends that there are circumstances that distinguish the situation in Alaska from that existing in the OCS cases cited in the NOPR, including the fact that the OCS cases involved the transportation of specific reserves and entailed unusual costs and risks, whereas the situation in Alaska calls for a pipeline that will access all Alaska gas, and that risk has been substantially reduced by a massive federal loan guarantee. Moreover, states Anadarko, the Act calls for mandatory open seasons for capacity on an Alaska natural gas transportation project. Consequently, Anadarko asserts that the final open season rules must require that pre-subscribed capacity must be subject to the outcome of the open season, and if the proposed project is oversubscribed, the project sponsors must either revise the project's capacity to accommodate all bids or fairly prorate all the capacity.

32. Alaska would also prefer that the final open season rules prohibit pre-subscribed capacity because of its potential to limit the amount of capacity in the open season. If pre-subscription is permitted, Alaska, like Anadarko, states that all parties should be able to obtain capacity on the same terms and conditions, and if the project is oversubscribed, all capacity should be pro-rated equally. ChevronTexaco has a similar view, stating that so long as the pre-subscription represents only a minimum commitment needed to construct a project, with the understanding that the project will be enlarged as a result of matching bids in the open season, and so long as pre-subscribed capacity and open season capacity are allocated on the same basis, the Act's open season goals are met. Calpine points out the same circumstances as Anadarko did in distinguishing an Alaska natural gas transportation project from the OCS facilities referred to the NOPR. However, to facilitate the ultimate development of an Alaska natural gas transportation project, Calpine is agreeable to allowing pre-subscribed capacity that will be subject to an allocation procedure in the event capacity is oversubscribed.

33. Alaska Legislators and Arctic Slope oppose any pre-subscription. Arctic Slope asserts that 100 percent of the capacity of an Alaska natural gas transportation project must be made available on a non-discriminatory, open access basis to all potential shippers; therefore, the open season rules should prohibit pre-subscriptions. Alaska Legislators state that the Act requires the Commission alone to establish the open season procedures for awarding initial and expansion capacity on an Alaska natural gas transportation project. Moreover, since Congress mandates that these open season regulations promote competition in the exploration, development, and production of Alaska natural gas, Alaska Legislators contend that the project must be developed in a manner that maximizes the number of exploration and production companies able to participate in an open season and compete for capacity on the pipeline. The only way this can be done, according to Alaska Legislators, is by requiring that 100 percent of the initial and expansion capacity be awarded solely through a public open season. Alaska Legislators support their view by stating, like Anadarko and Calpine, that the OCS cases cited in the NOPR involved specific instances of individual pipeline construction proposals, and citing cases in which the Commission disapproved procedures outside of an open season and required transparent open seasons as the vehicle by which new pipeline capacity is obtained. 12

34. The Commission recognizes that the expense, risk, and long lead time involved in developing an Alaska natural gas transportation project justify allowing project sponsors the flexibility to enter into pre-subscription agreements with the North Slope Producers and any other shippers who are currently in a position to support the project with long-term capacity commitments. We do not view the federal loan guarantees as reducing the risk of an Alaska project to a level where pre-subscription should not be allowed, nor do we see pre-subscription as inherently anti-competitive.

35. Based on the foregoing, we will permit pre-subscription in order to facilitate the development of an Alaska natural gas transportation project. In order to ensure that all other potential shippers will have an equal opportunity to obtain access to capacity on the project in the open season, we are requiring in the final rule that any and all pre-subscription agreements be made public within ten days of their execution, and that capacity on the proposed project will be offered to all prospective qualifying shippers on the same rates, terms and conditions as contained in the pre-subscription agreements. In the event that there are pre-subscription agreements with varying rates, terms and conditions, all prospective qualifying shippers shall have the option of choosing among the several agreements which one they wish to accept. We note, however, that the justification for allowing pre-subscription may not be as compelling in the case of any expansion, since the major hurdles to developing the project in the first instance will have been overcome. Therefore, we will limit our authorization to provide for pre-subscribed initial capacity only. 13

36. Much attention is given in the comments to concerns over potential discrimination and preference in allocating capacity in the event that the proposed Alaska pipeline project is oversubscribed, whether or not pre-subscription is allowed. While these concerns can best be addressed by designing a proposed project such that it meets the capacity needs of all shippers who are prepared to enter into binding agreements, we nonetheless will use our regulatory authority to protect against undue discrimination or undue preference in capacity allocation.

37. As discussed below, the Commission is holding to the regulatory approach taken in the NOPR which allows project sponsors to (subject to our subsequent review) develop the methodology by which they will allocate capacity in the event of oversubscription of a project not supported by precedent agreements. However, in the case of pre-subscribed capacity, the Commission will require that the project sponsors must either revise the project's capacity to accommodate all qualified bids or prorate only the capacity that was subject to the pre-subscription agreements or was bid for in the open season on the same rates, terms and conditions as any of the pre-subscription agreements. The Commission has chosen this solution for several reasons. First, the parties most certain to be pre-subscription shippers are the North Slope Producers, who will be in a position of control over the proposed project's design, either as project sponsors or as owners of the reserves that support the project. Second, by their own estimate, the North Slope Producers assert that the initial pipeline can be designed to accommodate all qualified bids. 14 Consequently, the Commission believes that it is appropriate that entities involved in pre-subscription bear the risk that their capacity will be reallocated in the event that the project is undersized.

38. Anadarko proposes to add to this section a provision that, when read in the context of its other proposed rules, would prohibit any pre-subscription agreements. Alaska also proposes language that would lead to that result. As discussed herein, the Commission is, with appropriate limitations, allowing pre-subscription, and is amending § 157.33 accordingly. Moreover, the Commission is satisfied that modifying § 157.33 to provide that any application lacking a showing that the open season regulations have been fully complied with will be rejected as deficient will ensure compliance with the open season requirements. Alaska proposes to also include in this section a provision requiring that open seasons be conducted without undue discrimination or preference in the rates, terms, or conditions of service. The Commission is expanding § 157.35 to include language similar to that suggested by Alaska.

39. The criteria for and timing of Alaska natural gas transportation project open seasons are spelled out in proposed § 157.34. This proposed regulation received the most attention in comments. For clarity and convenience, the comments are broken down and grouped by the topics listed below.

40. Proposed § 157.34 sets forth the criteria for and timing of Alaska project open seasons. Proposed § 157.34(a) provides for public notice of an open season at least 30 days prior to the commencement of the open season through methods including postings on Internet websites, press releases, direct mail solicitations, and other advertising. The Commission believes that such prior notice would serve several purposes. First, it would reduce, if not eliminate, any advantage that one potential shipper might have as a result of prior knowledge of the open season. Second, it would afford both project sponsors and prospective shippers a period of time prior to the actual open season period in which they could address and possibly resolve any questions or problems regarding the terms and conditions of the open season. Third, it would afford potential shippers time to prepare submissions in response to the open season.

41. Proposed § 157.34(c) provides that an open season for an Alaska natural gas transportation project must remain open for a period of at least 90 days. This minimum 90-day period for prospective shippers to examine the open season materials and make service requests to the pipeline is intended to establish some parity among shippers, given that certain shippers, primarily the “anchor” shippers, may have had advance information relating to the pipeline's proposed services, tariff provisions, and cost projections. Ninety days is proposed as an adequate amount of time in which to conduct a reasoned evaluation of the open season materials and to help level the playing field.

42. Alaska Legislators state that the notice period established in the NOPR needs clarification. Specifically, they state that the proposed regulations are unclear whether the 30-day notice period precedes and is computed separately from the 90-day open season period. In any event and for several reasons, state Alaska Legislators, an initial open season will require a duration of a minimum of six months, and any subsequent open seasons should remain open for a minimum of four months. First, Alaska Legislators assert that this additional time is needed to offset the fact that shippers affiliated with the pipeline will have advance information. Second, the substantial capital commitment that will be required of any prospective shipper warrants a much longer period within which to evaluate whether to contract for capacity on the project.

43. ANGDA agrees that a 180-day period to review and assess the open season information is required in order to account for the huge information gap between the information now available to potential intra-state shippers and the information they would need to make multi-year commitments for capacity on an Alaska natural gas transportation project. ANGDA states that such a commitment would equal or exceed the asset base of potential shippers on a spur line. Moreover, public hearings and Regulatory Commission of Alaska (RCA) approval of contract terms is required for several potential shippers. The due diligence and expert advice required to make decisions of this magnitude require a minimum of 180 days, according to ANGDA. Additionally, ANGDA states that many shippers' contract terms require RCA approval, which could take one to two years. Anadarko also believes 180 days is required due to the magnitude of the commitment and to offset the informational advantages that the major producers have over other potential shippers. For example, Anadarko estimates that a 500 MMcf/d commitment for 20 years' capacity on an Alaska natural gas transportation project translates into a $7 billion demand charge, and a 30-year contract would involve a $10 billion commitment.

44. AOGCC, Shell, Pacific Star, Doyon, and Alaska share the belief that the NOPR's 90-day open season period should be extended. Pacific Star could support a 120-day open season, with a prior 90-day review period. Alaska recommends a “safe harbor” range of 90 to 120 days, with no preference given based on when bids are received.

45. MidAmerican/AGTA, Alliance and Enbridge find the 30-day notice and 90-day open seasons to be adequate. In particular, Enbridge and MidAmerican/AGTA find these time frames to strike an appropriate balance between meeting prospective shippers' informational needs and the need to expedite the development of an Alaska natural gas transportation project. Enbridge states that because there have been years of developmental work on an Alaskan natural gas pipeline, with many prior public hearings and discussions on the subject having occurred and continuing dialog between potential sponsors and shippers taking place, it is unnecessary to lengthen the proposed open season period. 15 Enbridge adds that extending the open season could result in long delays in the project's overall schedule due to the narrow, seasonal windows associated with environmental studies and preliminary field work.

46. Another timing issue raised in comments involves when any open seasons for an Alaska natural gas transportation project should be held. The NOPR has no requirements on the subject of when project sponsors must hold the open season. According to Anadarko, the Commission's silence on this issue will allow sponsors to hold open seasons early in the project's developmental process. As a result, explorers will be unable to commit to capacity on the project because of the present uncertainties surrounding their reserves. This sentiment is shared by others, including Arctic Slope, DOI, Doyon, and Shell. As a solution, these commenters state that the open season regulations should include a requirement that any open seasons must remain open until the last practical point in time, which according to Anadarko and Shell is the time when the sponsors must close on their financing arrangements. These commenters state that in this way, some potential shippers, other than the major producers who are in a better position to commit early in the process, might be able to resolve the uncertainties currently prohibiting them from participation. Shell also states that the open season regulations should preclude any open season for an expansion project prior to one calendar year after the in-service date of the pipeline unless the open season is specifically requested by a shipper other than a major producer.

47. In addition, some commenters urge the Commission to require that the study of in-state needs provided for in section 103(g) of the Act precede any open season. Although the language of the Act requires that “the holder of the certificate” demonstrate that it has conducted the required study, the Act does not state when such study should be conducted; nor does the Act require that the study be made public. Alaska states that contrary to the intent of the Act, the NOPR is silent on the subject of ensuring that in-state needs for gas are met. 16 According to Alaska, the only logical way for this to be done is to require that the in-state study be conducted prior to the open season in order for the project sponsor to design the capacity, routing and expansibility of the project facilities to accommodate those needs. The Alaska Legislators argue that an in-state study is “virtually meaningless unless concluded and the results made public by the pipeline operator prior to any open season.”  17 Chevron Texaco, TransCanada, and ANGDA agree that, in order to determine where tie-in points are needed to meet Alaska's domestic gas needs, the studies should precede any open season.

48. The Alaska Legislators further argue that the Commission should spell out the type of study that the pipeline will be required to undertake. ANGDA's comments address the need for two major gas trunk-line interconnect points in Alaska, most critically a spur line to make North Slope gas available to the Cook Inlet area, where two-thirds of the state's population resides, and which has less than a 10-year reserve life for current gas supply. United States Senator Murkowski, State Senator Therriault, and Mr. Izzo, representing Enstar, among others at the technical conference also stressed various in-state needs for natural gas. ChevronTexaco states that it could be a simple matter of identifying most logical tie-in points to address future needs and the most economic methods to expand the capacity to meet those needs when they arise. Alaska Legislators suggest that a January 2003 study conducted on behalf of Alaska's Department of Natural Resources might serve as a useful example to model in fashioning the requirements of the in-State study. 18

49. The Commission is adopting the NOPR's 30-day notice period and 90-day open season period of “at least 90 days” for open seasons, and clarifies that the 30-day notice period will precede the 90-day open season and that the notice of open season is to contain all of the information detailed in § 157.34(b). Therefore, all interested persons will have a period of a minimum of 120 days in total to examine the information pertaining to any open season in order to assess whether they are willing and able to participate in the process and proffer bids. The Commission understands that on day one of the open season process, any shippers affiliated with the pipeline or who have entered into pre-subscription agreements may have certain information not available to other entities. However, that information is required to be disclosed at the beginning of the minimum 120-day period.

50. The Commission also appreciates that, due to the substantial capital commitment that will be required, any prospective shipper will need a sufficient period of time within which to evaluate whether to make multi-year commitments for capacity on the project. However, we also understand that in order to timely develop a pipeline proposal, size the facilities, secure financing and otherwise finalize the proposal in detail sufficient to file a certificate application, time is of the essence. This is accentuated by the fact that under section 109 the Act, if an application for an Alaska natural gas transportation project is not filed within 18 months after the October 2004 enactment of the Act, the Secretary of Energy is required to conduct a study of alternative approaches to an Alaska natural gas transportation project. 19 While the Act does not preclude the filing of an application after the 18-month period and the initiation of such a study, it is clear that the Act contemplates that an applicant will proceed with all deliberate speed.

51. The minimum 120-day open season period we are establishing is substantially longer than any open season heretofore held for a major pipeline project. While no other project equals or nears the size and complexity of an Alaska natural gas transportation project, this will be a project with many years of evaluation, information-gathering and private and public debate behind it. While there may currently be some disparity in the amount of information various interested parties have, most have been assessing their situations, at least conceptually, for many years. The Commission, on balance, believes a 120-day period is adequate to substantially level the playing field, particularly given the extensive information requirements imposed in the open season regulations. We are not convinced that an open season lasting as long as six months is necessary.

52. The Commission, for several reasons, will not impose a requirement that any open season must remain open until a particular point in time tied to other project activities. This requirement was requested in order to allow as much time as possible for potential shippers to put themselves in a position to bid for capacity. The Commission is providing that the effective date of this final rule shall be 90 days from its publication in the Federal Register , which will prevent any open seasons for the first three months. Any specific point in time that the Commission might select (such as a year before an application was filed) might not be suitable under all circumstances, and could, therefore, frustrate efforts in planning project proposals. However, we are adding a new provision in the final rule, § 157.34(d)(2), that a project sponsor must consider any bids tendered after the expiration of the open season by qualified bidders, and may reject them only if they cannot be accommodated due to economic, engineering, or operational constraints, in which case the project sponsor must provide a detailed explanation for the rejection. This requirement is designed to allow reasonable access to those shippers whose circumstances prohibit them from participating during the established open season period. Nonetheless, our expectation is that the pipeline can and will be designed and built to accommodate all qualified shippers who are ready to sign firm agreements. On balance, this should be of benefit to late-developing shippers and at the same time provide the sponsor with flexibility in the timing of its open season.

53. In light of the concerns expressed by Alaska entities and Congress' mandate that Alaska in-state needs be given due consideration, we are adding to § 157.34 of the regulations a requirement that open season information include an assessment of in-state needs, based to the extent possible on any available study performed by Alaska, and a listing of prospective delivery points within Alaska. We are also adding a requirement that the open season information include a proposed in-state transportation rate, based on the costs of providing that service. This will give participants in an open season sufficient information to understand what capacity is proposed to be offered to entities within Alaska, where the project proponent proposes to make in-state deliveries, and what the rates for in-state service may be. To the extent possible, we intend that for this assessment to be made based on information provided by the state, so that we, project proponents, and other interested parties can have the benefits of the state's expertise.

54. We do not propose to set aside a specific amount of capacity for in-state service, because we do not now know how much capacity will be sought for that purpose. Similarly, although, as stated immediately above, in-state transportation rates must be based on the costs of providing that service, we cannot at this point determine the appropriate allocation of costs between services for in-state deliveries and for deliveries to the lower 48 States. We will deal with cost allocation issues occasioned by these matters as they arise.

55. We note that section 103(g) of the Act requires the holder of a certificate for an Alaska project to prepare a study of Alaska in-state needs. The open season information we are requiring does not obviate the need to comply with this provision, but the material provided during the open season could later be proffered as the post-certificate study, and, should we determine that there is sufficient agreement by interested parties that the open season information is sufficient, we may accept it as satisfying the statutory requirement.

56. Proposed § 157.34(b) lists the information that any notice of open season for an Alaska natural gas transportation project must contain. The listed information includes technical information such as the route, the proposed receipt and delivery points, the size and design capacity, estimated in-phase dates for expansion capacity, delivery pressure, projected in-service date, estimated unbundled transportation rate, estimated cost of facilities and estimated cost of service, expected return on equity, negotiated rates and other rate options under consideration, quality specifications, terms and conditions of service. In addition, the list includes a detailed methodology for determining the value of bids, the methodology by which capacity will be awarded in the case of over-subscription, a clear statement of all terms that will be considered, including price and contract term, and required bid information. Other listed information includes the form of a precedent agreement and time of execution of the precedent agreement, and definition and treatment of non-conforming bids.

57. The Commission recognized in the NOPR that a potential applicant for an Alaska natural gas transportation project might find it necessary or appropriate to initiate an open season before some of the information can be determined. The NOPR also anticipated that in a given situation, such information cannot be reasonably determined until after an open season is held. As an example, the Commission described a situation where, for purpose of gathering information and assessing demand, a prospective project sponsor might first conduct a non-binding open season. Then, based on its evaluation of the response, the sponsor could conduct a second, binding open season containing information sufficiently detailed to permit prospective shippers to enter into binding precedent agreements.

58. To accommodate these situations, the NOPR provided that the sponsor would be required to include the listed information in the notice of open season “to the extent that such information is known or determined at the time the notice is issued.”  20 Additionally, in order to level the playing field for all potential open season participants, the NOPR required that the sponsor include in the open season notice “[a]ll other information that may be relevant to the open season, including information pertaining to the proposed service to be offered, projected pipeline capacity and design, proposed tariff provision, and cost projections, made available to or in the hands of any potential shipper, including any affiliates of the project sponsor and any shippers with pre-subscribed capacity, prior to the issuance of the public notice of open season.”  21

59. Several commenters, including Anadarko, MidAmerican/AGTA, the North Slope Producers, Alliance, and Enbridge found the NOPR's listed information to be generally sufficient to provide prospective shippers the information needed to decide whether they to make binding, long-term commitments to purchase capacity on an Alaska natural gas transportation project. However, several aspects of the NOPR's informational requirements drew the attention of these commenters.

60. Anadarko and Shell state that limiting the sponsor's obligation to provide the information listed in the NOPR only “to the extent that such information is known or determined at the time the notice is issued” creates a loophole, and this qualifying language should be deleted from the regulations. According to Anadarko and Shell, a pipeline could avoid providing certain vital information simply by claiming that the information was not yet known or by holding the open season prematurely. These commenters state that the open season regulations should require that for any binding open season, pipelines include all the listed information in the notice. While certain physical characteristics of the pipeline will not be known until the pipeline is built, the pipeline can include in the notice the information upon which the open season proposal is based.

61. Alliance suggests that the Commission could reduce the risk of any dispute over the adequacy of the information contained in the notice by making clear that the information contained in the notice does not have to reflect the finalized positions on all elements at the time of notice of open season, and that a notice will not be invalidated by the absence of certain information. Additionally, Alliance recommends that the sponsors should be allowed to modify and update elements of their open season proposal if such modification is acceptable to prospective shippers. Alliance claims that this approach was useful in its own open season. MidAmerican/AGTA, on the other hand, feels that the above-mentioned qualifying language was reasonable.

62. However, MidAmerican/AGTA, together with the North Slope Producers and TransCanada, state that the catchall provision requiring “all other information that may be relevant * * *” is too broadly written. These commenters fear that the provision might be abused by those seeking either to delay the process or to obtain proprietary information. The North Slope Producers are also concerned over protecting proprietary or commercially sensitive information. They contend that this catchall provision is not in line with the Commission's policy against burdensome disclosure of commercially sensitive information. The North Slope Producers state that a notice containing the other sixteen types of information listed in the proposed regulations already provides more information than has been historically shared with shippers.

63. A number of comments on the proposed informational requirements focus on the need or desirability of including information that would inform all proposed shippers with respect to the expandability of the proposed project. Many commenters express, at one point or another in their comments, and all commenters implicitly agree, that it is extremely important to determine the original sizing and future expandability of an Alaska natural gas transportation project, as it will likely be the only pipeline built for the foreseeable future to transport Alaska natural gas for delivery to markets in the lower 48 states. Alaska, Calpine, and the Alaska Legislators all state that more information in the open season is needed to achieve optimal project design parameters. Alaska has proposed language to be included in the final regulations which includes feasibility and estimated cost of pipeline expansions, either through compression or looping, including any physical limitations. 22 Calpine also states that the notice of open season should contain information on the expandability of the project's design capacity, including the design capacity per stage of each expansion and method of achieving expansions, and that rate estimates should cover rates for expansion stages (calculated on a rolled-in basis).

64. The North Slope Producers request that the Commission clarify that proposed § 157.34(b)(6) does not require that capacity must be awarded on an MMBtu basis. Their argument is that, because the gas transported may include higher-Btu components, such as ethanes, which will not ultimately show up as natural gas, Btu-based rates would be unfair. Instead, they state that capacity on an Mcf basis is typical for similar pipelines.

65. ANGDA contends that the open season information should include design requirements for two major gas trunkline interconnect points in Alaska. ANGDA adds that a single tariff clearly would unduly discriminate against intrastate Alaska shippers.

66. Looking beyond the initial open season, Alaska and Alaska Legislators address in their comments additional information requirements needed for potential shippers to evaluate either their own expansion needs or whether there is sufficient demand to support an economic expansion of an Alaska natural gas transportation project. Alaska asserts that in addition to the expanded information it proposes for initial expansions, a notice of open season for expansion capacity should also include specific information identifying the location of the natural gas reserves to which the pipeline relates, although Alaska would permit the pipeline to seek a waiver of any expansion information requirement it considers to be inapplicable. Alaska also states that the regulations should provide that any voluntary expansion design must either accommodate the capacity requests of all open season expansion bidders which are able to satisfy the Pipeline's creditworthiness requirements and willing to execute firm transportation agreements of reasonable duration at maximum recourse rates or demonstrate what technical or economic factors prevent such a design.

67. Alaska Legislators claim that ongoing collection and publication by the pipeline of real-time information necessary for non-pipeline owners to evaluate on an ongoing basis the potential for pipeline expansions is required. Alaska Legislators suggest alternative methods of accomplishing this. Either the pipeline should conduct periodic, non-binding open seasons, or it should maintain a publicly-available log or queue of capacity requests. In all events, Alaska Legislators state that the Commission should also require that the pipeline keep a regularly-updated schedule on its website that includes: (1) Good faith estimates by the pipeline operator as to the possible and probable expansion increments to at least twice the original design capacity of the then-existing pipeline; (2) pipe characteristics of the then-existing pipeline, including wall thickness, diameter, and metallurgy; (3) compressor descriptions (manufacturer and model number, site rated horsepower and capacity, suction and discharge pressure and milepost locations of all existing and planned or prospective compressor stations); (4) an elevation profile of the then-existing pipeline; (5) known limitations on potential receipt and delivery points and a good-faith statement as to the bases for those limitations; (6) any other known limitations that would constrain or preclude expansions and a good-faith statement as to the bases for those limitations; and (7) any other expansion-related information of whatever nature which the pipeline owners or operators have made available to potential shippers (including any producing affiliates).

68. DOI states that the Commission should not allow decisions regarding the timing of open seasons to be left to the sole discretion of the pipeline and its affiliates. Instead, DOI requests that the Commission establish procedures for conducting future non-discriminatory open seasons that are reasonably responsive to ongoing exploration and development activities.

69. The Commission did not intend to provide project sponsors with a reason not to provide necessary information by qualifying their obligation to provide information in the open season “to the extent that such information is known or determined at the time the notice is issued.” As noted above, this qualification was intended to recognize that a potential Alaska pipeline project applicant might find it necessary or appropriate to initiate an open season before some of the information can be determined. As an example, the Commission described in the NOPR a situation where a prospective project sponsor first conducts a non-binding open season in order to gather information and assess demand, and thereafter, based on its evaluation of the response, conducts a second, binding open season containing information sufficiently detailed to permit prospective shippers to enter into binding precedent agreements.

70. The Commission's thinking at that time was that the open season rules would apply to “non-binding” open seasons, and the above qualification would have utility in such a situation. However, we understand that it may be difficult to draw distinctions between a “non-binding” open season and some other process of assessing interest in or need for capacity to assist the project sponsor in preparing a binding open season notice. Therefore, we are clarifying in the final rule that the open season regulations apply only to open seasons for binding commitments for capacity. The Commission sees no utility or need in imposing the full array of these open season regulations on activities leading up to a binding open season. There are adequate protections built into the open season rules, including the obligation to disclose information, to address any discriminatory and preferential practices through the Commission's oversight and enforcement capabilities.

71. Nonetheless, we understand that optimal design requirements are achieved as a result of an open season and not in advance of it, and we still foresee the possibility that a potential project sponsor might find it necessary or appropriate to conduct an open season before all the information required to be contained in the open season notice can be determined. Therefore, we will clarify in the final rule that the notice of open season must contain at a minimum, a good faith estimate based on the best information available of all items of required information and that the project sponsor must identify the source of information relied on, explain why such information is not presently known, and update the information when and if it is later determined during the open season period.

72. The Commission is also modifying proposed § 157.34(b)(17)  23 to address concerns that, as proposed, the regulations might be used to seek the disclosure of proprietary or commercially sensitive information. The purpose of the information-sharing requirement is to make sure that all interested parties are equally informed on matters essential to their decision whether to bid for capacity on the proposed project, with an eye toward leveling the playing field between affiliated shippers or others with prior knowledge of information to be contained in the open season notice and all other potential shippers. Between the specific information identified in proposed § 157.24(b)(17), namely, information pertaining to the proposed service to be offered, projected pipeline capacity and design, proposed tariff provision, and cost projections, and all the items of information enumerated in § 157.34(b), the Commission has, in essence, defined the information that all shippers will need to participate in an open season for capacity on an Alaska natural gas transportation project. Accordingly, we will delete the reference to “all of information that may be relevant.”

73. However, following review of the comments, the Commission is concerned that the informational requirements of § 157.34(b) alone might not be sufficient to prevent the possibility of discrimination by a project applicant in favor of an affiliate of that applicant. The Commission's goal is to prevent unduly discriminatory behavior and limit the ability of a project applicant to unduly favor its affiliate.

74. Therefore, in order to further the Commission's goal of a non-discriminatory open season, the Commission is applying certain of the Standards of Conduct requirements of Order No. 2004 24 to all project applicants conducting open seasons for an Alaska natural gas transportation project because this will minimize the risk that an affiliate of a project applicant would have an advantage over non-affiliates in obtaining capacity through the open season. The Commission is requiring project applicants to create/designate a unit or division to conduct the open season. The unit or division will be required to function independent of the other non-regulated divisions of the project applicant as well as the project applicant's Marketing and Energy Affiliates and subject to certain provisions of the Standards of Conduct. Specifically, the following provisions of Order No. 2004 will apply to project applicants conducting an open season: separation of functions (18 CFR 358.4(a)(1), (3), (4), (5) and (6) and (b)(e)(3),(5) and (6) (2004)); information access (18 CFR 358.5(a) (2004)); information disclosure (18 CFR 358.5(b) (2004)); prohibitions against discrimination (18 CFR 358.5(c)(5)(2004)) and discounts (18 CFR 358.4(d)(2004).

75. Under section 358.4(a)(1) of the Commission's regulations, the transmission function employees of a transmission provider must function independent of the transmission provider's Marketing affiliate or Energy Affiliates' employees. The employees who are part of the unit/division conducting the open season will be treated as transmission function employees and must function independently. Applying the separation of functions requirement would entail that employees of a project applicant who are involved in the open season may not also perform duties for the Energy Affiliates or Marketing Affiliates (as defined in 18 CFR 358.3(d) and (k) (2004)) of that project applicant. This would prevent Energy Affiliates of the project applicant who participate in the open season from having the advantage of information or strategy that non-affiliated open season participants do not have.

76. The applicable exemptions from the separation of functions would also apply to permit the project applicant to share various categories of employees, including: Support, field and maintenance employees (section 358.4(a)(4)); senior officers and directors who are not “Transmission Function Employees” (as defined by 18 CFR 358.3(j)), provided that they do not participate in directing, organizing, or executing transmission system operations or market functions or act as conduits for sharing prohibited information with a Marketing or Energy Affiliate (§ 358.4(a)(5)); and risk management employees who are not engaged in transmission functions or sales or commodity functions.

77. Consistent with § 358.4(e)(3) of the Standards of Conduct, the Commission will require each project applicant to post on its Internet Web site its written procedures describing how it complies with the applicable provisions of Order No. 2004. The Commission also will require each project applicant to train its employees involved in the open season or part of the open season unit/division, officers, directors and employees with access to transportation information or information concerning gas purchases, sales or marketing functions under § 358.4(e)(5). The project applicant must also designate a Chief Compliance Officer who will be responsible for Standards of Conduct compliance, as required by § 358.4(e)(6). In order to reduce the burden on project applicants, the Commission will not apply some of the posting requirements of Order No. 2004 to the open season ( e.g. , posting organizational charts and transfers of employees). However, project applicants must be able to verify that they have followed the organizational separation requirements.

78. The application of the information access (18 CFR 358.5(a)) and disclosure (18 CFR 358.5(b)) requirements will ensure that employees of Marketing/Energy Affiliates participating in the Open Season would not have access to any transmission information that is not publicly available to non-affiliated participants and require that any disclosure of non-public transmission information to a Marketing/Energy Affiliate be immediately disclosed to all other actual and potential open season participants by posting that information on the project applicant's Internet Web site. See 18 CFR 358.5(b)(3). The requirements for written consent before releasing non-affiliated customer information to a Marketing or Energy Affiliate and posting that consent on the Internet would also apply for project applicants. See § 358.5(b)(4).

79. The application of some of the non-discrimination requirements of Order No. 2004 will broadly prohibit discrimination by a project applicant conducting an open season and limiting its ability to unduly favor a Marketing/Energy Affiliate. The applicable non-discrimination provisions include: (1) Section 358.5(c)(3), which requires a Transmission Provider to process all similar requests for transmission in the same manner and within the same period of time; and (2) § 358.5(c)(5), which prohibits transmission providers from giving their Marketing or Energy Affiliates any preference over any other wholesale customer in matters relating to the sale or purchase of transmission service. In the context of an open season, these provisions ensure a project applicant will not provided any preferences to affiliated participants.

80. Finally, the application of the discount provision of § 358.5(d), which requires a Transmission Provider to post an offer of a discount for transmission service at the time an offer is contractually binding, will ensure the transparency of the open season process and discourage undue preferences. We note that if an offer of a discount becomes contractually binding through the execution of a precedent agreement, the offer must be posted at that time, not at the time of the final agreement. 25

81. Applying many of the functional separation, information access, disclosure and non-discrimination provisions of Order No. 2004 to this open season process will ensure that it is conducted in a manner that is non-discriminatory and provides equal access to all participants, particularly those not affiliated with the project applicants. If during or following the open season the Commission determines that the project applicant has violated the terms of the Order No. 2004 requirements that we are making applicable to the open season, the results of the open season with regard to the Energy Affiliates of that project applicant may be voided and a new open season held for that capacity.

82. As noted above, a number of commenters discuss the need for or desirability of requiring disclosure of information relevant to the expandability of the project, both as proposed and on an ongoing basis. In overseeing the open season process and in processing and application for a certificate or other authority to construct and operate an Alaska natural gas transportation project, we will require that every reasonable effort be made to design a project that meets current needs for capacity, and accommodates future needs for capacity through low-cost expansion. The information identified in § 157.34(c)(2), together with the design and engineering information required as part of any application for a certificate, should be sufficient to reasonably inform all interested parties on matters involving the expandability of the project.

83. As noted above, we are providing that the open season information include an assessment of in-state needs, based to the extent possible on any available study performed by Alaska, and a listing of prospective delivery points within Alaska. Moreover, we are requiring that a proposed in-state transportation rate, based on the costs of providing that service, also be included. This should address ANGDA's contention that the open season information should include design requirements for two major gas trunkline interconnect points in Alaska and that a single tariff clearly would unduly discriminate against intrastate Alaska shippers.

84. Also as noted above, the North Slope Producers request that proposed § 157.34(b)(6) clarify that it does not require that capacity must be awarded on an MMBtu basis. The Commission clarifies that this provision was intended to be a mandate that rates for an Alaskan pipeline will eventually have to be stated on a thermal basis, as is long-standing Commission policy. However, the Commission understands that at this stage of project development for an Alaskan pipeline, it will be significantly more complex for project sponsors to estimate rates and award capacity on that basis given the unique features of this project. Thus during the open season process, capacity may be described and rates may be estimated on a volumetric basis. However, as was the case in the two orders cited by the North Slope Producers, 26 the Commission has found that pipelines can meet the Commission's objectives concerning the statement of rates on a thermal basis by proposing methods of rate adjustment at a later time. If during the open season process, a project sponsor chooses that capacity will be described and has its rates estimated on a volumetric basis, then it must notify bidders that final pro forma service agreements and the sponsors proposed tariff will have to be submitted with rate calculated on a thermal basis.

85. As stated above, the NOPR required that the notice of open season contain a detailed methodology for determining the value of bids, 27 and the methodology by which capacity will be awarded in the case of over-subscription, clearly stating all terms that will be considered, including price and contract term. 28 In addition, the NOPR required that capacity allocated as a result of any open season be awarded without undue discrimination or preference of any kind. 29

86. The North Slope Producers contend that the combination of the mandatory non-discrimination/undue preference standard contained in the NOPR's § 157.35, the information disclosure requirements of § 157.34 (b), and § 157.33's provision that any application for a certificate of public convenience and necessity for a proposed Alaska natural gas transportation project must show that the applicant has conducted an open season for capacity in accordance with the open season rules fulfills the Commission's responsibilities under the Act to establish the criteria for conducting an open season, including the procedures for the allocation of capacity. Northwest Industrials, TransCanada, MidAmerican/AGTA, and the AGA all agree that the NOPR's proposed rules are appropriately flexible and provide a reasonably fair and open process that is consistent with the Act's directives.

87. The North Slope Producers stress that the most important, and first step to promoting competition in the exploration, development and production of Alaska natural gas is to get the Alaska natural gas transportation project built. They maintain that the Commission's current policies of allocating capacity in an open season to customers who value it most, and of favoring net present value (NPV) as a basis for awarding capacity will ensure that capacity will be awarded in a non-discriminatory and economically efficient manner. The North Slope Producers assert that through these policies, pipelines and shippers will also be assured that only capacity that is supported by the market and that is economically viable will be constructed.

88. Additionally, the North Slope Producers assert that based on preliminary assessments, there will be enough initial pipeline capacity to accommodate all near-term production from other producers and explorers, in addition to all production from Prudhoe Bay and Point Thomson. Specifically, they state that it will require 50 Tcf of gas to keep a 4 to 4.5 Bcf pipeline full for 30 years. Moreover, the North Slope Producers expect that any Alaska pipeline will be designed to be economically expandable to 6 Bcf/d, which would accommodate an additional 15 Tcf over 30 years.

89. At the same time, the North Slope Producers contend that while it is in a pipeline's interest to build a pipeline designed to carry all the gas shippers are willing to pay to transport, the costs of unused new capacity imposes certain limitations on just how much initial capacity the pipeline can build for a project to be economically viable. In response to suggestions made at the technical conference that, regarding capacity allocation in the event of oversubscription, small shippers should be favored, the North Slope Producers argue that any preferential capacity allocation methodology would be discriminatory, anti-competitive, and contrary to the NGA. The North Slope Producers state that shipper support for the project could be adversely affected if prospective shippers thought their commitments could be reduced. Moreover, they claim that any such undue preference or discriminatory treatment to particular shippers or sources of gas is unnecessary since an expansion under section 105 of the Act is available as a backstop for any shipper.

90. On the other hand, a number of comments are critical of the Commission's approach to addressing bid evaluations and allocation of capacity as represented in the NOPR. Pacific Star, Alaska Legislators, Shell, ChevronTexaco, Anadarko, Alaska, Calpine, Arctic Slope, Alaska Venture Capital/Brook Range, and Doyon all fault the Commission for not taking a pro-active approach in developing the capacity allocation methodologies, and instead leaving it to the pipeline to develop them. These commenters contend that Congress specifically instructed the Commission to detail the criteria to be used in awarding capacity, and to do so in a manner which will promote competition in exploration, development and production of Alaska gas.

91. In the NOPR, the Commission required that the notice of open season contain a detailed methodology for determining the value of bids, 30 and that capacity allocated as result of any open season be awarded without undue discrimination or preference of any kind. 31 We do not read section 103 of the Act to require that we define the methodology with the precision urged by those commenters who advocate a prescriptive regulatory approach. We remain confident, even more so now that we have the expanded scope of the regulatory text prohibiting undue discrimination and undue preference, that the regulations being promulgated in this order fully comply with the directives as well as the intent of the Act. Although the Commission is permitting prospective applicants the flexibility to establish the details of the bid evaluation methodology, any such methodology must meet the criteria imposed in this rule prohibiting undue discrimination, and it is the Commission, not the pipeline applicant who will apply that criteria to any open season claimed not to be in compliance with this rule. In this regard, the Commission notes that NPV has been the standard, but not required, methodology for evaluating bids in open seasons under current Commission policy. Although we are not mandating that methodology here, we will examine carefully any methodology that varies from those heretofore approved by the Commission to ensure that such variations respond to the unique circumstances of an open season for an Alaska project, and that they do not discriminate against any shipper or class of shippers in the evaluation of bids. We will now address specific issues.

92. The Alaska Legislators, ChevronTexaco, Alaska, Anadarko, and Calpine all urge the Commission to establish some uniform cap on the term by which, under the NPV methodology, bids are evaluated. Calpine, for instance, proposes that the contract term for purposes of bid evaluation be 30 years. Anadarko states that any bid term or other terms and conditions that are difficult, if not impossible, for all but a few preferred shippers to meet, should be prohibited if they are not critically required to secure financing. Accordingly, Anadarko proposes a bid cap of 20 years or the length of the financing instrument. ChevronTexaco and Alaska concur that a 20-year cap would be appropriate.

93. The Alaska Legislators also argue that a uniform cap should be placed on the term by which bids are evaluated. Although they do not have a specific cap term in mind, they claim that the Commission should impose some bid evaluation to prevent the major producers from bidding unduly long contract terms in order to squeeze out competitors. Recognizing that previous efforts by the Commission to limit the duration of contracts awarded in Tennessee Gas Pipeline Company's open season did not survive judicial scrutiny, Alaska Legislators state that the circumstances surrounding an open season for an Alaska natural gas transportation project are quite different from the circumstances associated with Tennessee, a pipeline in the lower 48 states. These distinctions, they assert, satisfy the concerns that the Court had in Process Gas Consumers Group v. FERC (Process Gas). 32

94. The Alaska Legislators point out that in the case of an Alaska natural gas transportation project open season, it would be the bid evaluation that is being limited, not the contract term itself, as was the case in Process Gas. Second, they assert that the parties in Process Gas were debating the duration of the cap, not the need for any cap to counter affiliates' attempts to obtain capacity through unjustifiably long bids. Third, they say, the Commission, on remand, concluded that open season caps in Tennessee's tariff were not required to protect captive customers because market forces dictate that pipelines have greater incentive to build new capacity to serve all demand, than to create scarcity by withholding capacity. On this point, Alaska Legislators contend that monopoly forces rather than market forces control the climate in Alaska, and that a producer-owned pipeline would indeed be disinclined to assist competing producers by affording them capacity on the pipeline.

95. The Commission is not persuaded that any cap on contract term bids is necessary or appropriate at this time. Other than general concerns of affiliate abuse, the comments have provided no factual predicate which would warrant the Commission to deviate from current Commission policy, which is to not impose limits on bid terms. However, the Commission will be reviewing the results of any open season processes to determine the appropriateness of any unusually long contract terms ( e.g. , a term exceeding the projected life of the pipe) to determine whether shippers incorporated them in their bids to obtain capacity allocation. For example, it would be in a prospective shipper's economic interest to seek a contract term that would be sufficient to allow the recovery of its revenues. However, it would not be in a shipper's economic interest to bid for capacity beyond its projected reserve's life because it would expose the shipper to reservation charges it may not be able to recover.

96. The Alaska Legislators state that bids for in-state capacity, with lower NPV as a consequence of mileage-based rates, cannot fairly compete with bids for transportation over the full length of the pipeline. Consequently, in order for bids for Alaska deliveries to compete with deliveries to the lower 48 states, Alaska Legislators contend that the final open season rules should contain a mileage-based multiplier to bids for in-state capacity. Alaska Venture Capital also recognizes this potential problem, but offers no solution other than calling on the Commission to address the problem with specific rules.

97. Concerns over length-of-the-pipe versus in-state bids are misplaced in the context of NPV for a new pipeline such as any Alaska natural gas transportation project. The primary purpose of the open season process is to determine the appropriate size of the initial pipeline. In-state capacity bids will not result in stranded capacity, as can be the case with capacity sales on an existing pipeline. We agree with the Alaska Legislators. The purpose of the in-state capacity bids will be to determine whether and to what extent there is interest in developing a telescoped pipeline to service Alaskan needs in the initial capacity allocation. The revised regulations require that the open season include an estimated transportation rate for in-state deliveries, as well as a methodology for determining the value of bids for in-state deliveries and for deliveries outside of the State of Alaska.

98. Other topics raised in the comments include Anadarko's suggestion that prepayments are unnecessary since the pipeline sponsor may already be the recipient of an $18 billion loan guarantee. Anadarko also claims that since prepayments would be much less burdensome to the major North Slope producers than to others, they are unduly preferential and should be prohibited. ChevronTexaco requests that the regulations expressly provide that, in the event more than one sponsor group conducts an open season for an Alaska natural gas transportation project, bidders may bid on the competing proposals. Calpine adds that bids should not exceed the amount of the proposal's design capacity, and that affiliates should be prohibited from making multiple bids, so that there is only one bid from each entity.

99. Although the loan guarantee under the Act will certainly facilitate the sponsor's ability to obtain financing, it cannot be said that such guarantee obviates the need for creditworthiness standards or prepayment requirements where reasonably necessary. Consequently, we will not prohibit prepayments as urged by Anadarko. Such standards must be included in the information contained in the notice, and as such, are subject to the requirement that there be no undue discrimination or undue preference in the terms or conditions of service. ChevronTexaco's request that the regulations expressly provide that, in the event more than one than one sponsor group conducts an open season for an Alaska natural gas transportation project, bidders may bid on the competing proposals is a reasonable one. We have included appropriate language in the regulations. Finally, the Commission takes note of Calpine's requests regarding limitations on the amount of capacity bid and multiple bids from affiliates. Although we are not prohibiting all such bids, we will examine closely any such bids to determine whether they are soundly based on satisfying the legitimate needs of the bidder, or whether they are made to “game” the open season process.

100. On the subject of allocating capacity in the event qualified bids for capacity exceed the amount of design capacity, a number of comments fault the Commission for not proposing requirements that will encourage exploration and development for yet to be discovered Alaska gas resources. This group includes Pacific Star, the Alaska Legislators, ChevronTexaco, Alaska Venture Capital/Brook Range, Alaska, Anadarko,. Shell and Doyon. Consistent with their view that the Commission must take a pro-active approach and adopt detailed rules regarding critical elements of open season, Alaska Legislators contend that the rules governing capacity allocation in the event of oversubscription must provide that small shippers will not be subject to proration. Alaska Legislators claim that a pro rata basis of capacity allocation is not appropriate for an Alaska pipeline, especially a producer-owned pipeline. They assert that the producers' control over the pipeline must be countered by regulations favoring access to capacity by multiple, smaller-volume shippers over single, large-volume shippers. Alaska Legislators state that by providing as many shippers as possible all of the capacity they request, those with market power will be encouraged to ensure that there is enough capacity for their requirements as well.

101. ChevronTexaco claims that in order for any open season to be fairly and reasonably conducted, any project that is too small to accommodate all nominated volumes should be redesigned, if possible. ChevronTexaco states that if the project cannot be redesigned upward, the next step would require that the bidders prove their access to gas supply to support their bids. After that, any unsupported bids would be allocated on a pro rata basis. Doyon also recommends as a first step that the sponsor upwardly revise the project's proposed capacity to accommodate all, and if it cannot be done, all shippers would receive a pro rated minimum volume of capacity. Similarly, Anadarko suggests that in case of oversubscription, the sponsor should either revise upward the proposed capacity to accommodate all shippers or the pipeline should be required to prorate capacity requests in a manner that does not disproportionately affect those shippers who do not have pre-subscribed capacity. Finally, Alaska states that the Commission should require that all bids for 20 or more years at the maximum rate be treated equally and pro rated if necessary. If all such bids can be accommodated but bids under 20 years cannot, then NPV should be applied to award capacity to those bidders. 33

102. Just as the Commission required that the notice of open season contain a detailed methodology for determining the value of bids, the Commission also required in the NOPR that the prospective applicant state the methodology by which capacity will be awarded, clearly stating all the terms that will be considered, 34 and that capacity allocated as a result of any open season be awarded without undue discrimination or preference of any kind. 35 Our justification and reasoning in support of our approach to establishing criteria for purposes of bid evaluation applies here as well. Moreover, to further meet the concerns expressed by parties who are worried about obtaining access to an Alaska pipeline, we have added new §§ 157.36 and 157.37, which make clear that the Commission will examine proposed pipeline designs, as well as expansion proposals, to ensure that all interested shippers are given a fair opportunity to obtain capacity both on an initial project and on any voluntary expansion. As stated elsewhere in this order, we believe it is in both the sponsor's and shippers' best interests to build the pipeline to accommodate all qualified shippers who are ready to sign firm agreements. We will carefully review project design and the documentation relating to the allocation of capacity, with the goal of promoting our open access and pro-competition policies.

103. Another specific issue on which the Commission sought comment was whether it should require that prospective applicants for Alaska natural gas transportation projects, before conducting open seasons, file with the Commission proposals for how the open seasons will be conducted. If so, the Commission asked whether the proposals be filed for notice and comment, or for a decision or pre-determination by the Commission that such proposals conform to the regulations. The Commission concluded its inquiry on this subject by inviting suggestions on what other procedures would be suitable to facilitate the expeditious resolution of objections or concerns regarding any open season for an Alaska natural gas transportation project.

104. The majority of commenters who addressed the subject of requiring that all open season proposals be pre-filed with the Commission were of the opinion that such a requirement is unnecessary and could potentially delay or disrupt the whole open season process. MidAmerican/AGTA and TransCanada propose that, instead, the sponsor should have the option of requesting Commission preapproval, adding that such option should include a 45-day comment period. ChevronTexaco prefers that instead of mandatory prefiling requirements, sponsors should be free to seek informal guidance from the Commission. Neither Alliance, nor Anadarko, nor the North Slope Producers supports any advance pre-approval filing requirement or procedure.

105. Alaska, on the other hand, believes that it is better to resolve any disputes involving the open season process beforehand. To accomplish this, Alaska proposes that the entire proposed open season package be filed with the Commission three months prior to opening date, and the Commission should notice the filing for comments prior to a Commission determination on the sufficiency of the open season notice.

106. Anadarko, ChevronTexaco, Alliance, Enbridge, the North Slope Producers, and MidAmerican/AGTA all stress the need for some form of dispute resolution during the open season process. Anadarko states that the open season rules should specify that the Commission's Fast Track Processing (18 CFR 385.206(h)) will apply to all complaints regarding non-compliance with open season regulations. Moreover, Anadarko maintains that the open season process should be suspended during pendency of the fast track complaint procedures in order to preserve the complainant's rights to acquire capacity. MidAmerican/AGTA and Alliance also refer to the Commission's Fast Track procedures as well as the Enforcement Hotline as useful, available procedures for resolving open season complaints. In addition to expedited complaint procedures, ChevronTexaco states that open season disputes could be resolved by way of a declaratory order.

107. ChevronTexaco also states that the Commission should consider imposing Standards of Conduct-like requirements, such as guidelines for interstate transporters in Order No. 2004. Enbridge and the North Slope Producers are also satisfied that the Commission's existing procedures are sufficient to expeditiously resolve any complaints or disputes over the open season process. Alliance asserts that the best way to address disputes is to minimize them through clear and unambiguous, yet flexible, rules.

108. DOI believes that some form of oversight is needed and suggests that all proposals be filed and publicly reviewed by the Commission or other independent regulatory group. DOI states that the proposed rules are vague and some process should be developed to modify the rules to accommodate changing circumstances in the future as they may arise.

109. On balance, we conclude that it is in the public interest to require pre-approval of open season procedures. This will allow issues to be identified and resolved at the earliest possible time, and, ideally, reduce the possibility of dissatisfaction with open seasons, as well as the risk that the Commission will have to require that deficient open seasons be conducted again. Therefore, the regulations will require that project proponents file open season plans for Commission approval.

110. As detailed above, various approaches to resolving disputes over the open season process are suggested. On review, the Commission believes that its current processes and procedures, combined with the pre-approval requirement, are sufficient to resolve any disputes arising out of the open season process, and in light of the sense of urgency expressed in the provisions of the Act, the Commission is providing in the final rule that any complaints alleging non-compliance with this subpart shall be processed under the Commission's Fast Track procedures. 36 However, the Commission does not find it necessary or appropriate as a rule to suspend the open season process during pendency of a Fast Track complaint in order to preserve the complainant's rights to acquire capacity, as requested by Anadarko. The Commission anticipates that in most cases that might arise, the project sponsor will be able to comply with a Commission order directing that it provide the capacity requested by a prospective shipper who is found to be entitled to capacity. However, just as we will not require that the open season be suspended, nothing in this rule prohibits a complainant from requesting, or the Commission granting, such relief if necessary.

111. As noted above, one of the issues that received substantial attention in the pre-NOPR comments is whether the Commission should require rolled-in rate treatment for Alaska pipeline expansions. Although the NOPR's proposed regulations are silent on this subject, the NOPR requested comment on whether, in the event the Commission issues regulations with respect to the Commission's authority to require expansion of any Alaska natural gas transportation project, those regulations should address the rate treatment (rolled-in or incremental) of any such expansion.

112. Other than the North Slope Producers and Alliance, there is much support for rolling-in the costs of both voluntary and involuntary expansions, although there is disagreement about when the issue should be resolved. ChevronTexaco states that the subject of appropriate rate treatment for expansions is a subject deserving of substantial, detailed consideration that should be addressed after dealing with the more pressing task of issuing the open season rules. Northwest Industrial Gas Users also believes that the issue can be addressed later. Alaska agrees that expansion pricing is a complex subject that should be examined thoroughly, and asserts that instead of addressing the issue in this rulemaking, the Commission should issue a notice regarding expansion rate treatment for Alaska natural gas transportation projects in early 2005. Alaska observes that the arguments in support of rolled-in pricing are strong, but suggests that rolled-in pricing might not be appropriate in all circumstances. Alliance believes that because the appropriateness of rolled-in or incremental rate treatment for any expansion should be made on a fact-specific basis, and not by rule that predetermines, before the circumstances of a given expansion are even known, how that expansion should be priced.

113. Pacific Star and Alaska Venture Capital state that the Commission should give an early indication that it will support rolled-in rates for expansions of any Alaska natural gas transportation project. Pacific Star states that it agrees with the statement at the technical conference by TransCanada, ANGDA, Anadarko, BLM, and MMS that rate uncertainty will discourage exploration and development and that expansions of the pipeline could present widely varying rate consequences. Pacific Star also states that concerns over existing shippers' subsidizing rolled-in expansions should be weighed against the facts that initial shippers are benefiting from substantial subsidies through the $18 billion loan guarantee and a 7-year accelerated depreciation. Alaska Venture Capital/Brook Range similarly believes that the Commission should give an early indication that it will support rolled-in pricing under scenarios outside the Commission's existing policy, under which the Commission approves rolled-in rates only where the rolled-in rate is equal to or less than the existing recourse rate. According to Alaska Venture Capital/Brook Range, a policy calling for different rates for similar services would place explorers and smaller producers at a competitive disadvantage. This would, in turn, discourage exploration and development of Alaska natural gas, contrary to the mandate of the Act.

114. TransCanada, MidAmerican/AGTA, and DOI encourage the Commission to adopt a rebuttable presumption favoring rolled-in rates. TransCanada states that any shippers concerned about the effect of such treatment can seek to avoid it through negotiated rates. MidAmerican/AGTA qualifies its support for this presumption by stating that the presumption should apply only to reasonably-engineered increments of mainline expansions supported by long-term contracts similar to those supporting the initial project. DOI states that rolled-in rate treatment is more equitable to future shippers, and that, because Canada has adopted rolled-in rates for expansions, it would provide rate consistency for the entire system.

115. Alaska Legislators, Anadarko, Shell, Calpine, Arctic Slope, and Doyon all contend that rolled-in pricing should be required for pipeline expansions. Alaska Legislators contend that incremental treatment for expansions would discriminate against expansion shippers who, merely because of the timing of their capacity needs, may pay higher rates than initial shippers. This, according to the Alaska Legislators, ignores the fact that the need for expansion is the consequence of the demands of all shippers. Alaska Legislators state that the Commission must balance the interests of the existing customers against interests of other stakeholders in determining whether or not pre-existing shippers should get the benefit of rate decreases for expansions that lower the average per unit cost of transportation, but face the possibility of rate increases that increase the average per unit cost of transportation. Alaska Legislators also note that the current Commission policy on expansion pricing was developed to address pipeline to pipeline competition, which will not arise in Alaska.

116. In addition to arguing that incremental rates operate to discriminate against expansion shippers, Alaska Legislators argue that the prospect of incremental rates will also act to reduce competition and impede the development of Alaska natural gas. Alaska Legislators state that exploration and development of Alaska reserves requires a long lead-time due to seasonal restrictions and the remoteness of the resource. 37 Alaska Legislators contend that this long lead time makes it difficult for an explorer to judge when it is feasible to commit to capacity on the pipeline. The result, state Alaska Legislators, is that the explorers and developers may be deterred from investing the large sums required to drill for Alaska natural gas, when they are unsure whether their future capacity needs will be met at a time when inexpensive expansion through increased compression will be available, or whether the expansion they require would involve costly looping. The Alaska Legislators also argue that Canada has a long-standing policy of requiring rolled-in rates for expansions which could make exploration in Canada much more attractive to exploration and production companies.

117. Anadarko, also convinced that expansions under section 103 of the Act must be priced on a rolled-in basis, argues that this is critical to avoid a rate structure or policy that discriminates on the basis of time of entry onto the pipeline. Anadarko maintains that it is important to establish this requirement in the initial open season process in order to inform those prospective shippers that their rates might increase as expansions are rolled-in. Alaska Legislators provide a history of the Commission's expansion rate policy, varying over time in order to address different goals as deemed necessary to address changing market dynamics. In short, Alaska Legislators assert that the current Commission policy favoring incremental expansion rates seeks to address issues of competing pipelines, competitive markets, optimal construction, and protecting captive customers, all valid considerations of the market setting in the lower 48 states, but wholly inapplicable to an Alaska natural gas transportation project or the Alaska market. According to Alaska Legislators, the Act instructs the Commission, through its open season regulations, to focus on reducing barriers, not to competitive markets, but rather, to entry in exploration and development of Alaska natural gas. Alaska Legislators conclude that to achieve this mandated goal, the open season regulations must be revised to include rolled-in pricing as one of the criteria for open seasons for pipeline expansions

118. Shell and Calpine also argue that Commission's 1999 pricing policy for expansions has no application to the circumstances of an Alaska natural gas transportation project where there is no element of pipeline competition or preventing overbuilding. Shell is concerned that companies might not invest hundreds of millions in exploration and development costs if they may have to pay for expansions on an incremental basis, while competitors benefited from earlier, inexpensive expansion. Calpine stresses that since an Alaska natural gas transportation project will be called to transport all Alaska gas, not just gas from Prudhoe Bay and Point Thomson reserves, a larger picture is required in assessing any policy against subsidization. Calpine maintains that an Alaska pipeline should be viewed as a 10 Bcf/d pipeline that will be built, in phases, over time, as opposed to a 4.5 Bcf pipeline that might be expanded from time to time. Under this picture, shippers on the first phase facilities will benefit from lower initial rates due to the Act's loan guarantees, however the Act was not only concerned with facilitating the development of a project that carries Prudhoe Bay and Point Thomson production to market, but also the development and transportation of Alaska's unproven reserves.

119. Arctic Slope is also concerned that unless rolled-in rates are mandated, there may never be an expansion of the pipeline beyond capacity created through infill compression and added compression horsepower. Arctic Slope estimates that rolled-in rates for expansions would probably be only a little higher than the initial rates since expansion costs would be borne by the entire pipeline throughput. However, the impact of incrementally-priced expansions on the incremental shippers, which would be based entirely on the incremental throughput quantities, would be very severe.

120. Alliance and the North Slope Producers assert that rates for expansion should be determined on a fact-specific, case-by-case basis, not on a pre-determined, rolled-in basis under the open season rules. The North Slope Producers stress that absent information regarding design, timing, and other project attributes, it would be inappropriate either to require or to favor rolled-in rates. In addition, the North Slope Producers point to section 105(b)(1) of the Act wherein, they state, Congress identified either rolled-in or incremental rates as appropriate for mandatory expansions. They add that if rolled-in rates were made applicable to voluntary expansions in the final open season rule, the result would be that such expansions would become involuntary and they would be discouraged.

121. Additionally, the North Slope Producers state that the Commission's existing, fact-specific policy recognizes the risks inherent in major infrastructure projects and seeks to prevent uneconomic pipeline expansions, as well as subsidization by existing customers, and should not be lightly discarded. Responding to the assertion that the NEB requires rolled-in rates for Canadian expansions, the North Slope Producers state that although NEB has adopted rolled-in rates in expansion cases, NEB addresses the issue on a case-by-case basis.

122. Finally, the North Slope Producers claim that explorers do not require absolute rate certainty in order to decide whether to participate in open seasons; an anticipated range that supports future economics is sufficient. On the other hand, the North Slope Producers state that initial shippers who fear that they may be called on to subsidize future shippers may not bid for initial capacity. In this connection, the North Slope Producers contend that one of the Commission's goals is to protect captive customers from rate increases arising from costs unrelated to their service, resulting in rate uncertainty and increased contractual risk. 38

123. In this rule, the Commission does not adopt a firm pricing policy for future expansions of an Alaska natural gas transportation project, but we do take this opportunity to provide guidance on this important issue, as it will assist participants in the initial open season. We conclude that there should be a rebuttable presumption in favor of rolled-in pricing for project expansions. Our existing lower-48 states policy favoring incremental rates for expansions does not apply in the case of an Alaska natural gas transportation project. There is likely to be only one Alaska pipeline, so there will be little or no opportunity for competition between pipelines. Incremental pricing of expansion could put expansion shippers at a significant rate disadvantage compared with initial shippers, and accordingly could discourage exploration, development and production of Alaska natural gas. Having markedly different rates for similar service could be in conflict with one of the chief objectives of the statute, which is to encourage further exploration and development of Alaska natural gas. On the other hand, consistent with the arguments of a number of commenters, a presumption in favor of rolled-in pricing may spur investment in and development of Alaska reserves, and the ultimate delivery of that gas to the lower 48 states.

124. We cannot at this point, without a specific project proposal or the facts surrounding a proposed expansion before us, define exactly what will be required to overcome the presumption. As a general matter, we have historically not favored requiring existing shippers to subsidize the rates of new shippers. We do not intend to discard this principle, but rather to indicate that we will not lightly authorize expansion rates that would have an unduly negative impact on the exploration and development of Alaska reserves. Witnesses at the technical conference acknowledged that defining subsidization is difficult without specific facts to review, and that fact was restated in several of the comments filed. We agree. But a basic observation may be useful here. For example, a rolled-in expansion rate that is less than or equal to the rate paid by the initial shippers would not be considered a subsidy. Whether a rolled-in expansion rate that is higher than original rates is a “subsidy” is a question that necessarily would have to be reviewed in the context of a future NGA section 7 filing. At that time, Pacific Star's arguments relating to whether the Federal government's loan guarantees and accelerated depreciation amount to a “subsidy” of initial shippers' rates may be raised.

125. In conclusion, to provide guidance to potential shippers in advance of the initial open season that is the subject of this rule, the Commission intends to harmonize both objectives (rate predictability for initial shippers and reduction of barriers to future exploration and production) in designing rates for future expansions of any Alaska natural gas transportation project. It is consistent with our guiding principle that competition favors all of the Commission's customers, as well as with the objectives of the Act, to adopt rolled-in rate treatment up to the point that would cause there to be a subsidy of expansion shippers by initial shippers, if any subsidy were to be found.

126. Anadarko states that the open season regulations must prohibit pipelines from bundling ancillary services with transportation. In particular, Anadarko is concerned that sponsors might include in a tariff and an open season the bundled cost of a gas conditioning plant that would extract CO 2 despite the fact that such extraction would not be required of gas from many new Alaska gas fields which likely will be of pipeline quality. MidAmerican/AGTA and Enbridge agree that the open season process should preclude applicants from tying receipt of capacity to taking ancillary services, such as gas conditioning, treating, or processing. TransCanada simply states that it has no objection to proscription of tying.

127. DOI and MidAmerican/AGTA agree that rates for ancillary services should not be bundled with transportation rates. However, DOI contends that the State of Alaska should address the need for rules concerning non-discriminatory access to gathering and other production-related facilities, whereas MidAmerican/AGTA claims that the Commission should assert and jurisdiction over gas treatment plants and require separate open seasons and cost-based tariff structures for gas processing. On the other hand, the North Slope Producers contend issues of tying or bundling of services can be dealt with through established Commission processes and policies at the appropriate time, and need not be addressed in the open season. Alliance views the tying issue in the context of requiring designated downstream capacity, and suggests that as a practical matter, that should not be prohibited.

128. The Commission is stating in the final rule at § 157.34(c)(6) that the open season notice must contain an unbundled transportation rate. Moreover, § 157.34(c)(10) prohibits a prospective applicant from requiring prospective shippers to process or treat their gas at any designated facility. The Commission is satisfied that it can address any other discriminatory conduct in connection with gas quality requirements or other ancillary services through the provisions of § 157.35 in conjunction with existing Commission policies and procedures.

129. The Office of Management and Budget (OMB) regulations require that OMB approve certain reporting, recordkeeping, and public disclosure (collections of information) imposed by an agency. 39 The following information collection requirements contained in this final rule are being submitted to the Office of Management and Budget (OMB) for review under section 3507(d) of the Paperwork Reduction Act of 1995. 40 The Commission identifies the information disclosed under part 157 as FERC-537. The Commission has submitted this information collection to OMB for review and clearance under emergency processing procedures. 41

130. The Commission did not receive specific comments concerning its burden estimates and uses the same estimates here in the Final Rule. Comments on the substantive issues raised in the NOPR are addressed elsewhere in the Final Rule.

Total Annual Hours for Collection: 2400 hrs. These are mandatory information collection requirements.

Information Collection Costs: The Commission sought comments on the cost to comply with these requirements. No comments were received. The Commission is projecting the average annualized cost for all respondents to be $139,000 (2400 × $58.00).

Title: FERC-537 “Gas Pipeline Certificates: Construction, Acquisition and Abandonment.”

Action: Proposed Information Collection.

OMB Control Nos.: 1902-0060. The applicant shall not be penalized for failure to respond to this collection of information unless the collection of information displays a valid OMB control number.

Respondents: Business or other for profit.

Frequency of Responses: One-time implementation.

131. Necessity of Information: On October 13, 2004, Congress enacted the Alaska Natural Gas Pipeline Act. Section 103(e) (1) of the Act directs the Commission to issue regulations within 120 days from the enactment of the Act. Congress and the Commission consider the issuance of these regulations to be of critical importance to the construction and development of and access to Alaska natural gas transportation projects. The Commission must issue a final rule by February 10, 2005.

132. Interested person may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426 (Attention: Michael Miller, Office of the Executive Director, (202) 502-8415, fax: (202) 273-0873), e -mail: michael.miller@ferc.gov. For submitting comments concerning the collection of information and the associated burden estimate(s) including suggestions for reducing this burden, please send your comments to the contact listed above and to the Office of Management and Budget, Room 10202 NEOB, 725 17th Street, NW., Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory Commission, (202) 395-4650, fax: (202) 395-7285).

133. 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. 42 No environmental consideration is raised by the promulgation of a rule that is procedural in nature or does not substantially change the effect of legislation or regulations being amended. 43 The final rule establishes requirements governing the conduct of open seasons for proposals to construct Alaska natural gas transportation projects and does not substantially change the effect of the underlying legislation or regulations being revised.

134. The Regulatory Flexibility Act of 1980 (RFA)  44 generally requires a description and analysis of final rules that will have significant economic impact on a substantial number of small entities. The Commission is not required to make such an analysis if a rule would not have such an effect.

135. The Commission concludes that this final rule would not have such an impact on small entities. Most companies regulated by the Commission do not fall within the RFA's definition of a small entity. 45

136. In addition to publishing the full text of this document in the Federal Register , the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through FERC's Home Page ( http://www.ferc.gov ) and in FERC's Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Room 2A, Washington DC 20426.

137. From FERC's Home Page on the Internet, this information is available in the Commission's document management system, 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.

138. User assistance is available for eLibrary and the FERC's Web site during normal business hours. For assistance, please contact FERC Online Support at 1-866-208-3676 (toll free) or (202) 502-6652 (e-mail at FERCOnlineSupport@FERC.gov ), or the Public Reference Room at (202) 502-8371, TTY (202) 502-8659 (e-mail at public.referenceroom@ferc.gov ).

139. These regulations are effective May 19, 2005.

140. The Commission has determined, with the concurrence of the Administrator of the Office of Information and Regulatory Affairs of OMB, that this final rule is not a major rule as defined in Section 351 of the Small Business Regulatory Enforcement Fairness Act of 1996.

Phibro Animal Health, 710 Rte. 46 East, suite 401, Fairfield, NJ 07004, has informed FDA of a change of address to 65 Challenger Rd., 3d floor, Ridgefield Park, NJ 07660. Accordingly, the agency is amending the regulations in 21 CFR 510.600(c) to reflect the change.

This rule does not meet the definition of “rule” in 5 U.S.C. 804(3)(A) because it is a rule of “particular applicability.” Therefore, it is not subject to the congressional review requirements in 5 U.S.C. 801-808.

(2) * * *

Boehringer Ingelheim Vetmedica, Inc., 2621 North Belt Hwy., St. Joseph, MO 64506-2002, has informed FDA that it has transferred ownership of, and all rights and interest in, NADA 140-270 for Sulfamethazine Sustained Release Bolus to Phoenix Scientific, Inc., 3915 South 48th St. Terr., St. Joseph, MO 64503.

This rule does not meet the definition of “rule” in 5 U.S.C. 804(3)(A) because it is a rule of “particular applicability.” Therefore, it is not subject to the congressional review requirements in 5 U.S.C. 801-808.

Ivy Laboratories, Division of Ivy Animal Health, Inc., 8857 Bond Street, Overland Park, KS 66214, filed a supplement to ANADA 200-346. The supplemental ANADA provides for the use of COMPONENT TE-200 (trenbolone acetate and estradiol), a subcutaneous implant containing 200 milligrams (mg) trenbolone acetate and 20 mg estradiol in heifers fed in confinement for slaughter for increased rate of weight gain and improved feed efficiency. Ivy Laboratories' COMPONENT TE-200 is approved as a generic copy of Intervet, Inc.'s REVALOR-200, approved under NADA 140-992. The application is approved as of January 14, 2005, and the regulations are amended in 21 CFR 522.2477 to reflect the approval. The basis of approval is discussed in the freedom of information summary.

In accordance with the freedom of information provisions of 21 CFR part 20 and 21 CFR 514.11(e)(2)(ii), a summary of safety and effectiveness data and information submitted to support approval of this application may be seen in the Division of Dockets Management (HFA-305), Food and Drug Administration, 5630 Fishers Lane, rm. 1061, Rockville, MD 20852, between 9 a.m. and 4 p.m., Monday through Friday.

The agency has determined under 21 CFR 25.33(a)(1) that this action is of a type that does not individually or cumulatively have a significant effect on the human environment. Therefore, neither an environmental assessment nor an environmental impact statement is required.

This rule does not meet the definition of “rule” in 5 U.S.C. 804(3)(A) because it is a rule of “particular applicability.” Therefore, it is not subject to the congressional review requirements in 5 U.S.C. 801-808.

Phoenix Scientific, Inc., 3915 South 48th St. Ter., St. Joseph, MO 64503, filed a supplement to ANADA 200-287 for use of TRIPLEMAX (gentamicin sulfate, U.S.P.; betamethasone valerate, U.S.P.; and clotrimazole, U.S.P. ointment) for the treatment of acute and chronic canine otitis externa. The supplement provides for a new container size, a 20-gram dropper bottle. The supplemental ANADA is approved as of January 21, 2005, and the regulations are amended in 21 CFR 524.1044g to reflect the approval. The basis of approval is discussed in the freedom of information summary.

The regulations are also being amended to correct the indications for use to agree with approved product labeling. This action is being taken to improve the accuracy of the regulations.

In accordance with the freedom of information provisions of 21 CFR part 20 and 21 CFR 514.11(e)(2)(ii), a summary of safety and effectiveness data and information submitted to support approval of this application may be seen in the Division of Dockets Management (HFA-305), Food and Drug Administration, 5630 Fishers Lane, rm. 1061, Rockville, MD 20852, between 9 a.m. and 4 p.m., Monday through Friday.

The agency has determined under 21 CFR 25.33(a)(1) that this action is of a type that does not individually or cumulatively have a significant effect on the human environment. Therefore, neither an environmental assessment nor an environmental impact statement is required.

This rule does not meet the definition of “rule” in 5 U.S.C. 804(3)(A) because it is a rule of “particular applicability.” Therefore, it is not subject to the congressional review requirements in 5 U.S.C. 801-808.

Each state has a SIP containing the control measures and strategies used to attain and maintain the national ambient air quality standards (NAAQS). The SIP is extensive, containing such elements as air pollution control regulations, emission inventories, monitoring networks, attainment demonstrations, and enforcement mechanisms.

Each state must formally adopt the control measures and strategies in the SIP after the public has had an opportunity to comment on them and then submit the SIP to EPA. Once these control measures and strategies are approved by EPA, after notice and comment, they are incorporated into the federally approved SIP and are identified in part 52 “Approval and Promulgation of Implementation Plans”, Title 40 of the Code of Federal Regulations (40 CFR part 52). The full text of the state regulation approved by EPA is not reproduced in its entirety in 40 CFR part 52, but is “incorporated by reference.” This means that EPA has approved a given state regulation with a specific effective date. The public is referred to the location of the full text version should they want to know which measures are contained in a given SIP. The information provided allows EPA and the public to monitor the extent to which a state implements a SIP to attain and maintain the NAAQS and to take enforcement action if necessary.

The SIP is a living document which the state can revise as necessary to address the unique air pollution problems in the state. Therefore, EPA from time to time must take action on SIP revisions containing new and/or revised regulations as being part of the SIP. On May 22, 1997, (62 FR 27968), EPA revised the procedures for incorporating by reference (IBR), into the Code of Federal Regulations, materials submitted by states in their EPA-approved SIP revisions. These changes revised the format for the identification of the SIP in 40 CFR part 52, stream-lined the mechanisms for announcing EPA approval of revisions to a SIP, and stream-lined the mechanisms for EPA's updating of the IBR information contained for each SIP in 40 CFR part 52. The revised procedures also called for EPA to maintain “SIP Compilations” that contain the federally-approved regulations and source specific permits submitted by each state agency. These SIP Compilations are contained in 3-ring binders and are updated primarily on an annual basis. Under the revised procedures, EPA is to periodically publish an informational document in the rules section of the Federal Register when updates are made to a SIP Compilation for a particular state. EPA's 1997 revised procedures were formally applied to North Carolina on May 20, 1999 (64 FR 27465).

This action represents EPA's publication of the North Carolina SIP Compilation update, appearing in 40 CFR part 52. In addition, notice is provided of the following typographical corrections to Table 1 of § 52.1770(c), as described below:

1. Correcting typographical errors listed in Table 1 of § 52.1770(c), as described below:

A. Where absent, the addition of Federal Register citations in the “EPA Approval Date” column.

B. Change in Federal Register citation to reflect the beginning page of the preamble as opposed to that of the regulatory text.

C. Change of punctuation within the section Titles.

D. Section 2D.0306 title is revised to read as “Emission Reduction Level-Warning Plan.”

E. Section 2D.0307 title is revised to read as “Emission Reduction Level-Emergency Plan.”

F. Section 2D.0405 State Effective Date is revised to read “05/01/99.”

G. Section 2D.0502 EPA Approval Date is revised to read “07/26/82.”

H. Section 2D.0519 title is revised to read as “Control of Nitrogen Dioxide and Nitrogen Oxides Emissions.”

I. Section 2D.0520 was repealed and replaced by new rules under Section .1900 “Open Burning,” Federal Register (62 FR 41277) dated July 01, 1997.

J. Section 2D.0535 title is revised to read as “Excess Emission Reporting and Malfunctions.”

K. Section 2D.0952 title is revised to read as “Petition for Alternative Controls for RACT.”

L. Section 2D.0953 removing the duplicate rule “Vapor Return Piping for Stage II Vapor Recovery.”

M. Section 2Q.0605 title is revised to read as “Final Action on Permit Applications.”

EPA has determined that today's action falls under the “good cause” exemption in the section 553(b)(3)(B) of the Administrative Procedure Act (APA) which, upon finding “good cause,” authorizes agencies to dispense with public participation and section 553(d)(3) which allows an agency to make an action effective immediately (thereby avoiding the 30-day delayed effective date otherwise provided for in the APA). Today's administrative action simply codifies provisions which are already in effect as a matter of law in Federal and approved State programs and corrects typographical errors appearing the Federal Register . Under section 553 of the APA, an agency may find good cause where procedures are “impractical, unnecessary, or contrary to the public interest.” Public comment for this administrative action is “unnecessary” and “contrary to the public interest” since the codification (and typographical corrections) only reflect existing law. Immediate notice of this action in the Federal Register benefits the public by providing the public notice of the updated North Carolina SIP Compilation and notice of typographical corrections to the North Carolina “Identification of Plan” portion of the Federal Register .

Under Executive Order 12866 (58 FR 51735, October 4, 1993), this administrative action is not a “significant regulatory action” and is therefore not subject to review by the Office of Management and Budget. This action is not subject to Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001) because it is not a significant regulatory action under Executive Order 12866. Because the agency has made a “good cause” finding that this action is not subject to notice-and-comment requirements under the Administrative Procedure Act or any other statute as indicated in the Supplementary Information section above, it is not subject to the regulatory flexibility provisions of the Regulatory Flexibility Act (5 U.S.C 601 et seq. ), or to sections 202 and 205 of the Unfunded Mandates Reform Act of 1995 (UMRA) (Pub. L. 104-4). In addition, this action does not significantly or uniquely affect small governments or impose a significant intergovernmental mandate, as described in sections 203 and 204 of UMRA. This administrative action also does 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), nor will it have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132 (64 FR 43255, August 10, 1999). This administrative action also is not subject to Executive Order 13045 (62 FR 19885, April 23, 1997), because it is not economically significant. This administrative action does not involve technical standards; thus 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. The administrative action also does not involve special consideration of environmental justice related issues as required by Executive Order 12898 (59 FR 7629, February 16, 1994). In this administrative action, EPA has taken the necessary steps to eliminate drafting errors and ambiguity, minimize potential litigation, and provide a clear legal standard for affected conduct, as required by section 3 of Executive Order 12988 (61 FR 4729, February 7, 1996). EPA has complied with Executive Order 12630 (53 FR 8859, March 15, 1998) by examining the takings implications of this administrative action in accordance with the “Attorney General's Supplemental Guidelines for the Evaluation of Risk and Avoidance of Unanticipated Takings” issued under the Executive Order. This administrative action does not impose an information collection burden under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq. ). EPA's compliance with these Statutes and Executive Orders for the underlying rules are discussed in previous actions taken on the State's rules.

The Congressional Review Act (CRA) (5 U.S.C. 801 et seq. ), as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. Section 808 allows the issuing agency to make a rule effective sooner than otherwise provided by the CRA if the agency makes a good cause finding that notice and public procedure is impracticable, unnecessary or contrary to the public interest. Today's administrative action simply codifies (and corrects) provisions which are already in effect as a matter of law in Federal and approved State programs. 5 U.S.C. 808(2). These announced actions were effective when EPA approved them through previous rulemaking actions. EPA will submit a report containing this action and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States prior to publication of this action in the Federal Register . This update to North Carolina's SIP Compilation and correction of typographical errors is not a “major rule” as defined by 5 U.S.C. 804(2).

EPA has also determined that the provisions of section 307(b)(1) of the Clean Air Act pertaining to petitions for judicial review are not applicable to this action. This action is simply an announcement of prior rulemakings that have previously undergone notice and comment rulemaking. Prior EPA rulemaking actions for each individual component of the North Carolina SIP compilation previously afforded interested parties the opportunity to file a petition for judicial review in the United States Court of Appeals for the appropriate circuit within 60 days of such rulemaking action.

The Norman Y. Mineta Research and Special Programs Improvement Act [Pub. L. 108-426, 118 Stat. 2423 (November 30, 2004)] amends title 49, United States Code, by reorganizing the Research and Special Program Administration (RSPA) into two new administrations, the Pipeline and Hazardous Materials Safety Administration (PHMSA) and the Research and Innovative Technology Administration (RITA). PHMSA succeeds to all the authority exercised by RSPA with regard to pipeline and hazardous materials safety. RITA succeeds to substantially all the research authority currently exercised by RSPA, and includes other duties and powers of the Secretary that advance the Department's research, development, and technology objectives. In addition, two existing organizations of the Department, the Bureau of Transportation Statistics and the Office of Intermodalism, are moved to RITA (49 CFR Chapter XI). 49 CFR part 1 enumerates powers and duties that each modal administration within the Department of Transportation is responsible for carrying out. This rule amends 49 CFR part 1 to reflect the Secretary's delegation of authority to the Administrators of PHMSA and RITA, respectively.

The Administrators of PHMSA and RITA may redelegate their respective powers and duties described in this document if not inconsistent with statute, departmental regulations, policies, and orders governing delegations.

As this rule relates to Departmental organization, procedures, and practice, notice and comment on it are unnecessary under 5 U.S.C. 553(b). In addition, the Secretary finds that prior notice and opportunity to comment are unnecessary, and good cause exists to dispense with the 30-day delay in the effective date requirement so that PHMSA and RITA may operate pursuant to the changes noted above beginning February 20, 2005.

Ministerial amendments to a number of other parts in title 49 of the Code of Federal Regulations that pertain to functions of the new administrations will be issued in the near future.

This final rule is not considered a significant regulatory action under Executive Order 12866 (“Regulatory Planning and Process”), and the Regulatory Policies and Procedures of the Department of Transportation (44 FR 11034). There are no costs associated with this rule.

This final rule has been analyzed in accordance with the principles and criteria contained in Executive Order 13132 (“Federalism”). This final rule does not have a substantial direct effect on, or sufficient federalism implications for, the States, nor would it limit the policymaking discretion of the States. Therefore, the consultation requirements of Executive Order 13132 do not apply.

This final rule has been analyzed in accordance with the principles and criteria contained in Executive Order 13175 (“Consultation and Coordination with Indian Tribal Governments”). Because this final rule does not significantly or uniquely affect the communities of the Indian tribal governments and does not impose substantial direct compliance costs, the funding and consultation requirements of Executive Order 13175 do not apply.

Because no notice of proposed rulemaking is required for this rule under the Administrative Procedure Act (5 U.S.C. 553), the provision of the Regulatory Flexibility Act (5 U.S.C. 601 et seq. ) do not apply.

This final rule contains no information collection requirements under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).

The Department has determined that the requirements of Title II of the Unfunded Mandates Reform Act of 1995 do not apply to this rulemaking.