(a) Whenever appropriate, publication of an initial notice or order in the Federal Register shall be the primary means of informing interested persons and the general public that the proceeding to which the notice or order relates has been instituted before the Commission. The mailing or e-mailing of individual copies shall be confined to that which is required by law, by the Commission's rules and regulations, or by other considerations deemed valid by the Secretary in specific instances.

(1) It is the policy of the Commission to publish notice in the Federal Register upon the institution of the following proceedings before the Commission:

(i) Natural gas pipeline companies and public utility rate schedules and tariffs. (A) Initial rate schedule filings and changes in rates schedules proposed by public utilities and changes in rate schedules or tariffs proposed by natural gas pipeline companies, including purchased gas adjustment clauses.

(B) Changes in rates proposed by natural gas pipeline companies for field sales.

(C)-(D) [Reserved]

(E) Tracking rate schedule or tariff filings made pursuant to settlement agreements.

(F) Rate schedule or tariff filings made by natural gas pipeline companies or public utilities in compliance with Commission orders.

(G) Reports of refunds by natural gas pipeline companies and public utilities.

(H) [Reserved]

(I) Complaints against natural gas pipeline companies and public utilities, unless otherwise directed.

(ii) Interconnections, service and exportation pursuant to the Federal Power Act. (A) Applications for interconnection and service under section 202(b).

(B)-(C) [Reserved]

(D) Applications pursuant to section 207.

(E) [Reserved]

(iii) Hydroelectric, Federal Power Act. (A) Applications for preliminary permits pursuant to section 4(f).

(B) Applications for licenses for constructed or unconstructed projects, or notice of declaration of intention, sections 4(e), 23(a)(b).

(C) Applications for amendment of license, unless otherwise directed.

(D) Application for relicenses or nonpower licenses, or a recommendation for takeover, sections 14 and 15.

(E) Applications for transfer of license, section 8.

(F) Applications for surrender of license, section 6.

(G) Proceeding for revocation or termination of license, sections 6, 13, 26.

(H) Issuance of annual licenses, section 15.

(I) Lands withdrawn pursuant to an application for preliminary permit or license, and the vacation of such land withdrawals, section 24.

(J) Complaints against licensees, unless otherwise directed.

(iv) Corporate electric. (A) Applications pursuant to sections 203, 204, of the Federal Power Act, and applications or complaints pursuant to section 305 of the Federal Power Act.

(v) Accounting, gas and electric. (A) Applications pursuant to sections 4, 23, 301, and 302 of the Federal Power Act.

(B) Applications pursuant to sections 8 and 9 of the Natural Gas Act.

(vi) Federal rates. (A) Application for confirmation and approval of rate schedules for Federal hydroelectric projects.

(vii) Natural gas pipeline certificates, exportations, and importations, Natural Gas Act. (A) Applications for exemption under section 1(c).

(B) Applications for authorization to import and export gas under section 3.

(C) Applications for orders directing physical connection of facilities and sale of natural gas under section 7(a).

(D) Applications for permission and approval to abandon under section 7(b).

(E) Applications for permanent certificates under section 7(c).

(F) [Reserved]

(G) Complaints against natural gas pipeline companies, filed by individuals and companies, unless otherwise directed.

(viii)-(ix) [Reserved]

(x) Environmental statements. (A) Notice to be published pursuant to Order series 415.

(xi) Miscellaneous, gas and electric. (A) Order instituting an investigation in which hearings are fixed or in which an opportunity is given for filing comments or petitions to intervene.

(B) Show cause order, in which hearings are fixed or in which an opportunity is given for filing comments or petitions to intervene.

(C) Order or notice consolidating proceedings for hearing purposes or severing a proceeding formerly consolidated for hearing purposes.

(D) Applications for declaratory order, disclaimers of jurisdiction, or waiver of Commission regulations, unless otherwise directed.

(E) Requests for redesignation, unless otherwise directed.

(F) Requests for extension of time pursuant to § 385.2008 of this chapter, unless otherwise directed.

(G) Consolidations and severance pursuant to § 375.302(f) of this chapter, unless otherwise directed.

(H) Notice of correction of a document in any of the above categories.

(I) Notice of meetings of advisory committees established by the Commission.

(J) Notices of conferences in docketed rulemaking proceedings.

(K) Proposed penalties under section 31 of the Federal Power Act.

(L) Such other notices or orders as may be submitted by the Secretary for publication.

(2) Otherwise directed, as referred to above, shall be interpreted to mean notice given by the discretion of the Secretary.

(b) After notice has been given, the service of formal documents issued in a proceeding shall be confined to the parties of record or their attorneys, and the mailing or e-mailing of information copies shall be confined to that which is required by the Commission's rules and regulations, by courtesy in response to written requests for copies, or by other considerations deemed valid by the Secretary in specific instances.

(a) The Commission by this policy statement explicitly encourages the public, including those persons subject to regulation by the Commission, to submit suggestions, comments, or proposals concerning substantial prospective regulatory policy issues and problems, the resolution of which will have a substantial impact upon those regulated by the Commission or others affected by the Commission's activities. This policy is intended to serve as a means of advising the Commission on a timely basis of potential significant issues and problems which may come before it in the course of its activities and to permit the Commission an early opportunity to consider argument regarding policy questions and administrative reforms in a general context rather than in the course of individual proceedings.

(b) Upon receipt of suggestions, comments, or proposals pursuant to paragraph (a) of this section, the Commission shall review the matters raised and take whatever action is deemed necessary with respect to the filing, including, but not limited to, requesting further information from the filing party, the public, or the staff, or prescribing an informal public conference for initial discussion and consultation with the Commission, a Commissioner, or the Staff, concerning the matter(s) raised. In the absence of a notice of proposed rulemaking, any conferences or procedures undertaken pursuant to this section shall not be deemed by the Commission as meeting the requirements of the Administrative Procedure Act with respect to notice of rulemakings, but are to be utilized by the Commission as initial discussions for advice as a means of determining the need for Commission action, investigation or study prior to the issuance of a notice of proposed rulemaking to the extent required by the Administrative Procedure Act, 5 U.S.C. 553.

(c) [Reserved]

(d) A person may not invoke this policy as a means of advocating ex parte before the Commission a position in a proceeding pending at the Commission and any such filing will be rejected. Comments must relate to general conditions in industry or the public or policies or practices of the Commission which may need reform, review, or initial consideration by the Commission.

Pursuant to the Commission's authority under the Natural Gas Act, particularly subsection (b) of section 8 thereof, and under the Federal Power Act, particularly subsection (b) of section 301 thereof, upon request by a party to the proceedings, or as required in conjunction with the presentation of a Commission staff case of staff's cross-examination of any other presentation therein, all relevant information acquired by Commission staff, including workpapers pursuant to any staff investigation conducted under sections 8, 10, or 14 of the Natural Gas Act, and sections 301, 304 or 307 of the Federal Power Act, shall, without further order of the Commission, be free from the restraints of said subsection (b) of section 8 of the Natural Gas Act, and subsection (b) of section 301 of the Federal Power Act, regarding the divulgence of information, with respect to any matter hereafter set for formal hearing.

(a) The Commission recognizes the unique relationship between the United States and Indian tribes and Alaska Native Claims Settlement Act (ANCSA) Corporations as defined by treaties, statutes, and judicial decisions. Indian tribes have various sovereign authorities, including the power to make and enforce laws, administer justice, and manage and control their lands and resources. Through several Executive Orders and a Presidential Memorandum, departments and agencies of the Executive Branch have been urged to consult with federally-recognized Indian tribes in a manner that recognizes the government-to-government relationship between these agencies and tribes. In essence, this means that consultation should involve direct contact between agencies and tribes and should recognize the status of the tribes as governmental sovereigns.

(b) The Commission acknowledges that, as an independent agency of the federal government, it has a trust responsibility to Indian tribes and this historic relationship requires it to adhere to certain fiduciary standards in its dealings with Indian tribes.

(c) The Commission will endeavor to work with Indian tribes on a government-to-government basis, and with ANCSA Corporations in a similar manner, and will seek to address the effects of proposed projects on tribal rights and resources through consultation pursuant to the Commission's trust responsibility, the Federal Power Act, the Natural Gas Act, the Public Utility Regulatory Policies Act, section 32 of the Public Utility Holding Company Act, the Interstate Commerce Act, the Outer Continental Shelf Lands Act, section 106 of the National Historic Preservation Act, and in the Commission's environmental and decisional documents.

(d) As an independent regulatory agency, the Commission functions as a neutral, quasi-judicial body, rendering decisions on applications filed with it, and resolving issues among parties appearing before it, including Indian tribes. Therefore, the provisions of the Administrative Procedure Act and the Commission's rules concerning off-the-record communications, as well as the nature of the Commission's licensing and certificating processes and of the Commission's review of jurisdictional rates, terms and conditions, place some limitations on the nature and type of consultation that the Commission may engage in with any party in a contested case. Nevertheless, the Commission will endeavor, to the extent authorized by law, to reduce procedural impediments to working directly and effectively with tribal governments.

(e) The Commission, in keeping with its trust responsibility, will assure that tribal concerns and interests are considered whenever the Commission's actions or decisions have the potential to adversely affect Indian tribes, Indian trust resources, or treaty rights. The Commission will use the agency's environmental and decisional documents to communicate how tribal input has been considered.

(f) The Commission will seek to engage tribes in high-level meetings to discuss general matters of importance, such as those that uniquely affect the tribes. Where appropriate, these meetings may be arranged for particular tribes, by region, or in some proceedings involving hydroelectric projects, by river basins.

(g) The Commission will strive to develop working relationships with tribes and will seek to establish procedures to educate Commission staff about tribal governments and cultures and to educate tribes about the Commission's various statutory functions and programs. To assist in this effort, the Commission is establishing the position of tribal liaison. The tribal liaison will provide a point of contact and a resource for tribes for any proceeding at the Commission.

(h) Concurrently with this policy statement, the Commission is issuing certain new regulations regarding the licensing of hydroelectric projects. In this connection, the Commission sets forth the following additional policies for the hydroelectric licensing process.

(i) The Commission believes that the hydroelectric licensing process will benefit by more direct and substantial consultation between the Commission staff and Indian tribes. Because of the unique status of Indian tribes in relation to the Federal government, the Commission will endeavor to increase direct communications with tribal representatives in appropriate circumstances, recognizing that different issues and stages of a proceeding may call for different approaches, and there are some limitations that must be observed.

(j) The Commission will seek to notify potentially-affected tribes about upcoming hydroelectric licensing processes, to discuss the consultation process and the importance of tribal participation, to learn more about each tribe's culture, and to establish case-by-case consultation procedures consistent with our ex parte rules.

(k) In evaluating a proposed hydroelectric project, the Commission will consider any comprehensive plans prepared by Indian tribes or inter-tribal organizations for improving, developing, or conserving a waterway or waterways affected by a proposed project. The Commission will treat as a comprehensive plan, a plan that:

(1) Is a comprehensive study of one or more of the beneficial uses of a waterway or waterways;

(2) Includes a description of the standards applied, the data relied upon, and the methodology used in preparing the plan; and

(3) Is filed with the Secretary of the Commission. See generally 18 CFR 2.19.

In a public statement dated March 7, 1941, the Commission announced its determination that transmission lines which are not primary lines transmitting power from the power house or appurtenant works of a project to the point of junction with the distribution system or with the interconnected primary transmission system as set forth in section 3(11) of the Act are not within the licensing authority of the Commission, and directed that future applications filed with it for such licenses be referred for appropriate action to the Federal department having supervision over the lands or waterways involved.

The Commission approved and adopted on May 29, 1945, the following conclusions as to its powers of suspension of rate schedules under section 205 of the act:

(a) The Commission cannot suspend a rate schedule after its effective date.

(b) The Commission can suspend any new schedule making any change in an existing filed rate schedule, including any rate, charge, classification, or service, or in any rule, regulation, or contract relating thereto, contained in the filed schedule.

(c) Included in such changes which may be suspended are:

(1) Increases.

(2) Reductions.

(3) Discriminatory changes.

(4) Cancellation or notice of termination.

(5) Changes in classification, service, rule, regulation or contract.

(d) Immaterial, unimportant or routine changes will not be suspended.

(e) During suspension, the prior existing rate schedule continues in effect and should not be changed during suspension.

(f) Changes under escalator clauses may be suspended as changes in existing filed schedules.

(g) Suspension of a rate schedule, within the ambit of the Commission's statutory authority is a matter within the discretion of the Commission.

The Commission will evaluate the recreational resources of all projects under Federal license or applications therefor and seek, within its authority, the ultimate development of these resources, consistent with the needs of the area to the extent that such development is not inconsistent with the primary purpose of the project. Reasonable expenditures by a licensee for public recreational development pursuant to an approved plan, including the purchase of land, will be included as part of the project cost. The Commission will not object to licensees and operators of recreational facilities within the boundaries of a project charging reasonable fees to users of such facilities in order to help defray the cost of constructing, operating, and maintaining such facilities. The Commission expects the licensee to assume the following responsibilities:

(a) To acquire in fee and include within the project boundary enough land to assure optimum development of the recreational resources afforded by the project. To the extent consistent with the other objectives of the license, such lands to be acquired in fee for recreational purposes shall include the lands adjacent to the exterior margin of any project reservoir plus all other project lands specified in any approved recreational use plan for the project.

(b) To develop suitable public recreational facilities upon project lands and waters and to make provisions for adequate public access to such project facilities and waters and to include therein consideration of the needs of persons with disabilities in the design and construction of such project facilities and access.

(c) To encourage and cooperate with appropriate local, State, and Federal agencies and other interested entities in the determination of public recreation needs and to cooperate in the preparation of plans to meet these needs, including those for sport fishing and hunting.

(d) To encourage governmental agencies and private interests, such as operators of user-fee facilities, to assist in carrying out plans for recreation, including operation and adequate maintenance of recreational areas and facilities.

(e) To cooperate with local, State, and Federal Government agencies in planning, providing, operating, and maintaining facilities for recreational use of public lands administered by those agencies adjacent to the project area.

(f)(1) To comply with Federal, State and local regulations for health, sanitation, and public safety, and to cooperate with law enforcement authorities in the development of additional necessary regulations for such purposes.

(2) To provide either by itself or through arrangement with others for facilities to process adequately sewage, litter, and other wastes from recreation facilities including wastes from watercraft, at recreation facilities maintained and operated by the licensee or its concessionaires.

(g) To ensure public access and recreational use of project lands and waters without regard to race, color, sex, religious creed or national origin.

(h) To inform the public of the opportunities for recreation at licensed projects, as well as of rules governing the accessibility and use of recreational facilities.

(a) The Commission has approved several sets of standard conditions for normal inclusion in preliminary permits or licenses for hydroelectric developments. In a special situation, of course, the Commission in issuing a permit or license for a project will modify or eliminate a particular article (condition). For reference purposes the sets of conditions are designated as “Forms”—those for preliminary permits are published in Form P-1, and those for licenses are published in Form L's. There are different Form L's for different types of licenses, and the forms have been revised from time to time. Thus at any given time there will be several series of standard forms applicable to the various vintages of different types of licenses. The forms and their revisions are published on the Commission's Web site (www.ferc.gov/industries/hydropower/gen-info/comp-admin/l-forms.asp).

(b) Forms currently in use may be obtained on the Commission's Web site or from Federal Energy Regulatory Commission, Washington, DC 20426.

Pursuant to the provisions of section 441(a)(4)(A) of the Tax Reform Act of 1969, 83 Stat. 487, 625, public utilities and licensees regulated by the Commission under the Federal Power Act which have exercised the option provided by that section to change from flow through accounting will be permitted by the Commission, with respect to liberalized depreciation, to employ a normalization method for computing federal income taxes in their accounts and annual reports with respect to property constructed or acquired after January 1, 1970, to the extent with which such property increases the productive or operational capacity of the utility and is not a replacement of existing capacity. Such normalization will also be permitted for ratemaking purposes to the extent such rates are subject to the Commission's ratemaking authority. As to balances in Account 282 of the Uniform System of Accounts, “Accumulated deferred income taxes—Other property,” it will remain the Commission's policy to deduct such balances from rate base in rate proceedings.

(a) The Commission recognizes the importance of protecting and enhancing natural, historic, scenic, and recreational values at projects licensed or proposed to be licensed under the Federal Power Act.

(b) In furtherance of these policies, the Commission will not (1) permit the amendment of any license for the purpose of construction of additional facilities or (2) authorize the disposition of any interest in project lands for construction of any type, unless a showing is made that the construction will be designed to avoid or minimize conflict with the natural, historic, and scenic values and resources of the project area.

(a) Pursuant to section 10(d) of the Federal Power Act, the Commission has determined that the specified reasonable rate of return used in computing amortization reserves for hydroelectric project licenses shall be calculated annually based on current capital ratios developed from an average of 13 monthly balances of amounts properly includible in the licensee's long-term debt and proprietary capital accounts, as listed in the Commission's Uniform System of Accounts. The cost rate for such ratios shall be the weighted average cost of long-term debt and preferred stock for the year, and the cost of common equity shall be the interest rate on 10-year government bonds (reported as the Treasury Department's 10-year constant maturity series) computed on the monthly average for the year in question, plus four percentage points (400 basis points).

(b) The Statement of Policy adopted herein shall be effective upon issuance of this order.

(c) The Secretary shall cause prompt publication of this order to be made in the Federal Register.

(d) All requests and suggestions not specifically dealt with herein are hereby denied.

(e) The Secretary is hereby authorized to change the appropriate license article upon application by the licensees to reflect the specified reasonable rate of return as adopted herein.

To implement compliance with the Supreme Court decision in F.P.C. v. Con-Way Corp., 426 U.S. 271 (1976), aff'g 510 F. 2d 1264 (D.C. Cir. 1975) and to expedite the consideration of price squeeze issues in wholesale electric rate proceedings, the Commission adopts the following procedures for raising price squeeze issues which are to be followed unless they are demonstrated in an individual case to be inadequate:

(a) Any wholesale customer, state commission or other interested person may file petitions to intervene alleging price discrimination and anticompetitive effects of the wholesale rates. In order to have the issue of price discrimination considered in the rate proceeding, the intervening customer or other interested person must support its allegation by a prima facie case. The elements of the prima facie case shall include at a minimum:

(1) Specification of the filing utility's retail rate schedules with which the intervening wholesale customer is unable to compete due to purchased power costs;

(2) A showing that a competitive situation exists in that the wholesale customer competes in the same market as the filing utility;

(3) A showing that the retail rates are lower than the proposed wholesale rates for comparable service;

(4) The wholesale customer's prospective rate for comparable retail service, i.e. the rate necessary to recover bulk power costs (at the proposed wholesale rate) and distribution costs;

(5) An indication of the reduction in the wholesale rate necessary to eliminate the price squeeze alleged.

(b) Where price squeeze is alleged, the Commission shall, in the order granting intervention, direct the Administrative Law Judge to convene a prehearing conference within 15 days from the date of the order for the purpose of hearing intervenors' request for data required to present their case, including prima facie showing, on price squeeze issues.

(c) Within 30 days from the date of the conference the filing utility shall respond to the data requests authorized by the Administrative Law Judge.

(d) Within 30 days from the filing utility's response, the intervenors shall file their case-in-chief on price squeeze issues, which shall include their prima facie case, unless filed previously.

(e) The burden of proof (i.e. the risk of nonpersuasion) to rebut the allegations of price squeeze and to justify the proposed rates are on the utility proposing the rates under section 205(e) of the Federal Power Act.

(f) In proceedings where price squeeze is an issue, the Secretary shall include the state commission, agency or body which is responsible for regulation of retail rates in the state affected in the service list maintained under § 385.2010(c) of this chapter.

(a) In general, when a public utility files a phased rate increase, the Commission will determine the appropriate suspension period based on the total increase requested in all phases. If a utility files a rate increase within sixty days after filing another rate increase, the Commission will consider the filings together to be a phased rate increase request.

(b) This policy will not be applied if the increase is phased:

(1) To coordinate with new facilities coming on line;

(2) To implement a rate moderation plan;

(3) To avoid price squeeze;

(4) To comply with a settlement approved by the Commission; or

(5) If the utility makes a convincing showing that application of the policy would be harsh and inequitable and that, therefore, good cause has been shown not to apply the policy in the case.

(a) In determining whether the proposed hydroelectric project is best adapted to a comprehensive plan under section (10)(a)(1) of the Federal Power Act for improving or developing a waterway, the Commission will consider the extent to which the project is consistent with a comprehensive plan (where one exists) for improving, developing, or conserving a waterway or waterways affected by the project that is prepared by:

(1) An agency established pursuant to Federal law that has the authority to prepare such a plan, or

(2) A state agency, of the state in which the facility is or will be located, authorized to conduct such planning pursuant to state law.

(b) The Commission will treat as a state or Federal comprehensive plan a plan that:

(1) Is a comprehensive study of one or more of the beneficial uses of a waterway or waterways;

(2) Includes a description of the standards applied, the data relied upon, and the methodology used in preparing the plan; and

(3) Is filed with the Secretary of the Commission.

(a) General Policy. (1) This Statement of Policy is adopted in furtherance of the goals of sections 211(a) and 213(a) of the Federal Power Act, as amended and added by the Energy Policy Act of 1992.

(2) Under section 211(a), the Commission may issue an order requiring a transmitting utility to provide transmission services (including any enlargement of transmission capacity necessary to provide such services) only if an applicant has made a request for transmission services to the transmitting utility that would be the subject of such order at least 60 days prior to its filing of an application for such order. The requirement in section 211(a) that an applicant make such a request will be met if such an applicant has, pursuant to section 213(a) of the FPA, made a good faith request to a transmitting utility to provide wholesale transmission services and requests specific rates and charges, and other terms and conditions.

(3) It is the Commission's intention to apply the standards of this Statement of Policy when determining whether and when a valid “good faith” request for service was made.

(4) It is the Commission's intention to encourage an open exchange of information that exhibits a reasonable degree of specificity and completeness between the party requesting transmission services and the transmitting utility.

(5) The Commission intends to apply this Statement of Policy so as to carry out Congress' objective that, subject to appropriate terms and conditions and just and reasonable rates, in conformance with section 212 of the FPA, access to the electric transmission system for the purposes of wholesale transactions be more widely available.

(b) The Components of a good faith request. The Commission generally considers the following to constitute the minimum components of a good faith request for transmission services:

(1) The identity, address, telephone number, and facsimile number of the party requesting transmission services, and the same information, if different, for the party's contact person or persons.

(2) A statement that the party requesting transmission services is, or will be upon commencement of service, an entity eligible to request transmission under sections 211(a) and 213(a) of the FPA.

(3) A statement that the request for transmission services is intended to satisfy the “request for transmission services” requirement under sections 211(a) and 213(a) of the FPA, and that the request is not a request for mandatory retail wheeling prohibited under section 212(h) of the FPA.

(4) The party requesting transmission services should specify the character and nature of the services requested. Some types of service may require more detailed information than others. Where point-to-point service is requested, the party requesting transmission services should specify the anticipated point(s) of receipt to the transmitting utility's grid and the anticipated point(s) of delivery from the transmitting utility's grid. Where a party requesting transmission services requests additional flexibility to schedule multiple resources to meet its needs (e.g., network service), the request for services should contain a description of the requested services in sufficient detail to permit the transmitting utility to model the additional services on its transmission system.

(5) The names of any other parties likely to provide transmission service to deliver electric energy to, and receive electric energy from, the transmitting utility's grid in connection with the requested transmission services.

(6) The proposed dates for initiating and terminating the requested transmission services.

(7) The total amount of transmission capacity being requested.

(8) To the extent it is known or can be estimated, a description of the “expected transaction profile” including load factor data describing the hourly quantities of power and energy the party requesting transmission services would expect to deliver to the transmitting utility's grid at relevant points of interconnection. In the event delivery is to multiple points within the transmitting utility's electric control area, the requestor should describe, to the extent it is known or can be estimated, the expected load (over a given duration of time) at each such delivery point.

(9) Whether firm or non-firm service is being requested. Where a party requests non-firm service, it should specify the priority of service it is willing to accept, or the conditions under which it is willing to accept interruption or curtailment, if known.

(10) A statement as to whether the request is being made in response to a solicitation and a copy of the solicitation if publicly available. This will help the transmitting utility determine whether requests for transmission service are duplicative or mutually exclusive of requests filed by other parties.

(11) The proposed rates, terms and conditions for the requested transmission services as required by section 213(a). It is not necessary for the requestor to propose a specific numerical rate. Rather, a party requesting transmission services can fulfill the rates, terms and conditions requirement by specifying a rate methodology (e.g., embedded or incremental cost) or by referencing an existing formula rate, transmission tariff, or transmission contract. The validity of the good faith request will not depend on the rates proposed by the party requesting transmission services. This requirement is not intended to allow utilities to delay responses to requests for transmission services, or to deny requests for transmission services on the basis of an overly rigid or technical approach to the “rates, terms and conditions” element of the request.

(12) Any other information to facilitate the expeditious processing of its request. Such information will improve the negotiation process, reduce costs, and will improve chances to arrange the requested transmission without resorting to section 211 application procedures before the Commission.

(c) Components of a Reply to a Good Faith Request. The Commission generally considers the following to constitute the minimum components of a reply to a good faith request for transmission services under section 213(a):

(1) Unless the parties agree to a different time frame, the transmitting utility must acknowledge the request within 10 days of receipt. The acknowledgement must include a date by which a response will be sent to the party requesting transmission services and a statement of any fees associated with responding to the request (e.g., initial studies).

(2) The transmitting utility may ask the applicant to provide clarification of only the information needed to evaluate and process a “good faith” request. If the person requesting transmission services believes the transmitting utility is attempting to frustrate the process by making excessive requests for clarification, it may raise this issue if, and when, it files a request for a section 211 order with the Commission.

(3) The transmitting utility must respond to a request within 60 days of receipt or some other mutually agreed upon response date. If both parties agree to an alternative schedule, the agreement must be in writing and signed by both parties.

(4) If the transmitting utility determines that it can provide all the requested services from existing capacity, it should respond by offering the party requesting transmission services an executable service agreement that at a minimum contains the following information:

(i) A description of the proposed transmission rate and any other costs. It is not necessary for the proposed service agreement to contain a fully developed cost-of-service. However, the agreement should explain the basis for the charges for each component of service, including the unbundled components of any transmission rate as well as any other charges.

(ii) The proposed service agreement should explicitly describe all of the applicable terms and conditions of the transmission services provided under the agreement.

(iii) The transmitting utility should accompany the proposed service agreement with a clear statement of the time during which the offer to provide the transmission services will remain open. An open agreement offer may obligate the seller while imposing no countervailing obligation on the purchaser, and an unexecuted contract potentially ties up transmission facilities, thus jeopardizing the availability and price for subsequent requests that would use the same facilities. However, at a minimum, a transmitting utility should permit the party requesting transmission services sufficient time to review service agreements and coordinate multiple stages of joint transactions.

(5) If the transmitting utility determines that it must construct additional facilities or modify existing facilities to provide all or part of the requested services, it must:

(i) Identify the specific constraints and their duration that prevent it from providing all the requested services and explain how these constraints prevent it from providing all the requested services or the desired level of firmness.

(ii) Provide to the applicant all studies, computer input and output data, planning, operating and other documents, work papers, assumptions and any other material that forms the basis for determining the constraints.

(iii) Offer to the applicant an executable agreement under which the applicant agrees to reimburse the transmitting utility for all costs of performing any studies necessary to determine what changes to the transmitting utility's grid are needed to overcome the constraint and provide the requested services, their cost, and the estimated time to complete them. At a minimum, the proposed agreement should contain the following:

(A) An estimate of the cost of the study and the time required to complete it, and

(B) A commitment to supply to the party requesting transmission services all computer input and output data, planning, operating and other documents, work papers, assumptions and any other material used to perform the study.

(iv) If a transmitting utility determines that it can provide part but not all of the requested services without building new facilities, it should inform the applicant of any portion of the requested services that can be performed without constructing additional facilities or modifying existing facilities. In effect, the transmitting utility may be able to treat such a request as two separate transactions—one for service on existing facilities and the other as a request involving expansion decisions. Furthermore, where there are alternative, less expensive means of satisfying all or a portion of a transmission request, the Commission expects the transmitting utility to explore such alternatives (e.g., redispatching certain generating units to alleviate a constraint).

(a) General policy. The Commission encourages Regional Transmission Groups (RTGs) as a means of enabling the market for electric power to operate in a more competitive and efficient way. The Commission believes that RTGs can provide a means of coordinating regional planning of the transmission system and assuring that system capabilities are always adequate to meet system demands. RTG agreements that contain components that satisfy paragraphs (b) and (c) of this section generally will be considered to be just, reasonable, and not unduly discriminatory or preferential under the Federal Power Act (FPA). The Commission encourages RTG agreements that contain as much detail as possible in all of the components listed, particularly if the RTG participants will be seeking Commission deference to decisions reached under an RTG agreement.

(b) Organizational components. (1) An RTG agreement should provide for broad membership and, at a minimum, allow any entity that is subject to, or eligible to apply for, an order under section 211 of the FPA to be a member. An RTG agreement should encompass an area of sufficient size and contiguity to enable members to provide transmission services in a reliable, efficient, and competitive manner.

(2) An RTG agreement should provide a means of adequate consultation and coordination with relevant state regulatory, siting, and other authorities.

(3) An RTG agreement should include fair and nondiscriminatory governance and decision making procedures, including voting procedures.

(c) Other components. (1) An RTG agreement should impose on member transmitting utilities an obligation to provide transmission services for other members, including the obligation to enlarge facilities, on a basis that is consistent with sections 205, 206, 211, 212 and 213 of the FPA. To the extent practicable and known, the RTG agreement should specify the terms and conditions under which transmission services will be offered.

(2) An RTG agreement should require, at a minimum, the development of a coordinated transmission plan on a regional basis and the sharing of transmission planning information, with the goal of efficient use, expansion, and coordination of the interconnected electric system on a grid-wide basis. An RTG agreement should provide mechanisms to incorporate the transmission needs of non-members into regional plans. An RTG agreement should include as much detail as possible with regard to operational and planning procedures.

(3) An RTG agreement should include voluntary dispute resolution procedures that provide a fair alternative to resorting in the first instance to section 206 complaints or section 211 proceedings.

(4) An RTG agreement should include an exit provision for RTG members that leave the RTG, specifying the obligations of a departing member.

(d) Filing procedures. Any proposed RTG agreement that in any manner affects or relates to the transmission of electric energy in interstate commerce by a public utility, or rates or charges for such transmission, must be filed with the Commission. Any public utility member of a proposed RTG may file the RTG agreement with the Commission on behalf of the other public utility members under section 205 of the FPA.

(a) The Commission has adopted a Policy Statement on its pricing policy for transmission services provided under the Federal Power Act. That Policy Statement can be found at 69 FERC 61,086. The Policy Statement constitutes a complete description of the Commission's guidelines for assessing the pricing proposals. Paragraph (b) of this section is only a brief summary of the Policy Statement.

(b) The Commission endorses transmission pricing flexibility, consistent with the principles and procedures set forth in the Policy Statement. It will entertain transmission pricing proposals that do not conform to the traditional revenue requirement as well as proposals that conform to the traditional revenue requirement. The Commission will evaluate “conforming” transmission pricing proposals using the following five principles, described more fully in the Policy Statement.

(1) Transmission pricing must meet the traditional revenue requirement.

(2) Transmission pricing must reflect comparability.

(3) Transmission pricing should promote economic efficiency.

(4) Transmission pricing should promote fairness.

(5) Transmission pricing should be practical.

(c) Under these principles, the Commission will also evaluate “non-conforming” proposals which do not meet the traditional revenue requirement, and will require such proposals to conform to the comparability principle. Non-conforming proposals must include an open access comparability tariff and will not be allowed to go into effect prior to review and approval by the Commission under procedures described in the Policy Statement.

The Commission will address and consider cumulative impact issues at original licensing and relicensing to the fullest extent possible consistent with the Commission's statutory responsibility to avoid undue delay in the relicensing process and to avoid undue delay in the amelioration of individual project impacts at relicensing. To the extent, if any, that it is not possible to explore and address all cumulative impacts at relicensing, the Commission will reserve authority to examine and address such impacts after the new license has been issued, but will define that reserved authority as narrowly and with as much specificity as possible, particularly with respect to the purpose of reserving that authority. The Commission intends that such articles will describe, to the maximum extent possible, reasonably foreseeable future resource concerns that may warrant modifications of the licensed project. Before taking any action pursuant to such reserved authority, the Commission will publish notice of its proposed action and will provide an opportunity for hearing by the licensee and all interested parties. Hydropower licenses also contain standard “reopener” articles (see § 2.9 of this part) which reserve authority to the Commission to require, among other things, licensees of projects located in the same river basin to mitigate the cumulative impacts of those projects on the river basin. In light of the policy described above, the Commission will use the standard “reopener” articles to explore and address cumulative impacts only (except in extraordinary circumstances) where such impacts were not known at the time of licensing or are the result of changed circumstances. The Commission has authority under the Federal Power Act to require licensees, during the term of the license, to develop and provide data to the Commission on the cumulative impacts of licensed projects located in the same river basin. In issuing both new and original licenses, the Commission will coordinate the expiration dates of the licenses to the maximum extent possible, to maximize future consideration of cumulative impacts at the same time in contemporaneous proceedings at relicensing. The Commission's intention is to consider to the extent practicable cumulative impacts at the time of licensing and relicensing, and to eliminate the need to resort to the use of reserved authority.

The Commission issued a statement of policy on project decommissioning at relicensing in Docket No. RM93-23-000 on December 14, 1994.

(a) General Policy. This Statement of Policy is adopted in furtherance of the goals of Title IV of the Clean Air Act Amendments of 1990, Pub. L. 101-549, Title IV, 104 Stat. 2399, 2584 (1990).

(b) Costing Emissions Allowances in Coordination Sales. If a public utility's coordination rate on file with the Commission provides for recovery of variable costs on an incremental basis, the Commission will allow recovery of the incremental costs of emissions allowances associated with a coordination sale. If a coordination rate does not reflect incremental costs, the public utility should propose alternative allowance costing methods or demonstrate that the coordination rate does not produce unreasonable results. The Commission finds that the cost to replace an allowance is an appropriate basis to establish the incremental cost.

(c) Use of Indices. The Commission will allow public utilities to determine emissions allowance costs on the basis of an index or combination of indices of the current price of emissions allowances, provided that the public utility affords purchasing utilities the option of providing emissions allowances. Public utilities should explain and justify any use of different incremental cost indices for pricing coordination sales and making dispatch decisions.

(d) Calculation of Amount of Emissions Allowances Associated With Coordination Transactions. Public utilities should explain the methods used to compute the amount of emissions allowances included in coordination transactions.

(e) Timing. (1) Public utilities should provide information to purchasing utilities regarding the timing of opportunities for purchasers to stipulate whether they will purchase or return emissions allowances. A public utility may require a purchasing utility to declare, no later than the beginning of the coordination transaction:

(i) Whether it will purchase or return emissions allowances; and

(ii) If it will return emissions allowances, the date on which those allowances will be returned.

(2) Public utilities may include in agreements with purchasing utilities non-discriminatory provisions for indemnification if the purchasing utility fails to provide emissions allowances by the date on which it declares that the allowances will be returned.

(f) Other Costing Methods Not Precluded. The ratemaking treatment of emissions allowance costs endorsed in this Policy Statement does not preclude other approaches proposed by individual utilities on a case-by-case basis.

(a) The Commission has adopted a Policy Statement on its policies for reviewing transactions subject to section 203. That Policy Statement can be found at 77 FERC ¶ 61,263 (1996). The Policy Statement is a complete description of the relevant guidelines. Paragraphs (b)-(e) of this section are only a brief summary of the Policy Statement.

(b) Factors Commission will generally consider. In determining whether a proposed transaction subject to section 203 is consistent with the public interest, the Commission will generally consider the following factors; it may also consider other factors:

(1) The effect on competition;

(2) The effect on rates; and

(3) The effect on regulation.

(c) Effect on competition. Applicants should provide data adequate to allow analysis under the Department of Justice/Federal Trade Commission Merger Guidelines, as described in the Policy Statement and Appendix A to the Policy Statement.

(d) Effect on rates. Applicants should propose mechanisms to protect customers from costs due to the merger. If the proposal raises substantial issues of relevant fact, the Commission may set this issue for hearing.

(e) Effect on regulation. (1) Where the affected state commissions have authority to act on the transaction, the Commission will not set for hearing whether the transaction would impair effective regulation by the state commissions. The application should state whether the state commissions have this authority.

(2) Where the affected state commissions do not have authority to act on the transaction, the Commission may set for hearing the issue of whether the transaction would impair effective state regulation.

(f) Under section 203(a)(4) of the Federal Power Act (16 U.S.C. 824b), in reviewing a proposed transaction subject to section 203, the Commission will also consider whether the proposed transaction will result in cross-subsidization of a non-utility associate company or pledge or encumbrance of utility assets for the benefit of an associate company, unless that cross-subsidization, pledge, or encumbrance will be consistent with the public interest.

The Commission informationally lists the following NAESB Business Practices Standards as non-mandatory guidance:

(a) WEQ-016, Specifications for Common Electricity Product and Pricing Definition, WEQ Version 003, July 31, 2012;

(b) WEQ-017, Specifications for Common Schedule Communication Mechanism for Energy Transactions, WEQ Version 003, July 31, 2012;

(c) WEQ-018, Specifications for Wholesale Standard Demand Response Signals (WEQ Version 003.2, Dec. 8, 2017);

(d) WEQ-019, Customer Energy Usage Information Communication (WEQ Version 003.1, Sep. 30, 2015); and

(e) WEQ-020, Smart Grid Standards Data Element Table, WEQ Version 003, July 31, 2012.

(f) Copies of these standards may be obtained from the North American Energy Standards Board, 801 Travis Street, Suite 1675, Houston, TX 77002, Tel: (713) 356-0060. NAESB's website is at https://www.naesb.org/. Copies may also be obtained from the Federal Energy Regulatory Commission's website, https://www.ferc.gov.

The interpretation stated in § 2.4 applies as well to the suspension of rate schedules under section 4 of the Natural Gas Act.

For the purposes of section 7(c) of the Natural Gas Act, as amended, the word facilities as used therein shall be interpreted to exclude:

(a) Auxiliary installations. (1) Installations (excluding gas compressors) which are merely auxiliary or appurtenant to an authorized or proposed transmission pipeline system and which are installations only for the purpose of obtaining more efficient or more economical operation of the authorized or proposed transmission facilities, such as: Valves; drips; pig launchers/receivers; yard and station piping; cathodic protection equipment; gas cleaning, cooling and dehydration equipment; residual refining equipment; water pumping, treatment and cooling equipment; electrical and communication equipment; and buildings. The auxiliary installations must be located within the existing or proposed certificated permanent right-of-way or authorized facility site and must be constructed using the temporary work space used to construct the existing or proposed facility (see Appendix A to this Part 2 for guidelines on what is considered to be the appropriate work area in this context).

(2) Advance notification. One of the following requirements will apply to any specified auxiliary installation. If auxiliary facilities are to be installed:

(i) On existing transmission facilities, then no notification is required;

(ii) On, or at the same time as, certificated facilities which are not yet in service (except those authorized under the automatic procedures of part 157 of subpart F of this chapter), then a description of the auxiliary facilities and their locations must be provided to the Commission at least 30 days in advance of their installation; or

(iii) On, or at the same time as facilities that are proposed, then the auxiliary facilities must be described in the environmental report specified in § 380.12 or in a supplemental filing while the application is pending.

(3) Abandonment or replacement of auxiliary installations. Authorization to abandon or replace auxiliary facilities that were or could be installed under paragraph (a)(1) of this section is pre-granted under section 7(b) of the Natural Gas Act, and no reporting is required, provided that:

(i) All activities will be confined to areas, including temporary work space, previously authorized by the Commission for the construction and operation of facilities at that location;

(ii) All activities will comply with applicable conditions on certificate authorizations for the construction and operation of facilities at that location; and

(iii) The abandonment or replacement will have no adverse impact on customers' certificated services.

(b) Replacement of facilities. (1) Facilities which constitute the replacement of existing facilities that have or will soon become physically deteriorated or obsolete, to the extent that replacement is deemed advisable, if:

(i) The replacement will not result in a reduction or abandonment of service through the facilities;

(ii) The replacement facilities will have a substantially equivalent designed delivery capacity, will be located in the same right-of-way or on the same site as the facilities being replaced, and will be constructed using the temporary work space used to construct the existing facility (see Appendix A to Part 2 for guidelines on what is considered to be the appropriate work area in this context);

(iii) Except as described in paragraph (b)(2) of this section, the company files notification of such activity with the Commission at least 30 days prior to commencing construction.

(2) Advance notification not required. The advance notification described in paragraph (b)(1)(iii) of this section is not required if:

(i) The cost of the replacement project does not exceed the cost limit specified in Column 1 of Table I of § 157.208(d) of this chapter; or

(ii) U.S. Department of Transportation safety regulations require that the replacement activity be performed immediately;

(3) Contents of the advance notification. The advance notification described in paragraph (b)(1)(iii) of this section must include the following information:

(i) A brief description of the facilities to be replaced (including pipeline size and length, compression horsepower, design capacity, and cost of construction);

(ii) Current U.S. Geological Survey 7.5-minute series topographic maps showing the location of the facilities to be replaced; and

(iii) A description of the procedures to be used for erosion control, revegetation and maintenance, and stream and wetland crossings.

(4) Annual report. On or before May 1 of each year, a company must file (in accordance with filing procedures posted on the Commission's Web site at http://www.ferc.gov.) an annual report that lists for the previous calendar year each replacement project that was completed pursuant to paragraph (b)(1) of this section and that was exempt from the advance notification requirement pursuant to paragraph (b)(2) of this section. For each such replacement project, the company must include all of the information described in paragraph (b)(3) of this section. Exception. A company does not have to include in this annual report any above-ground replacement project that did not involve compression facilities or the use of earthmoving equipment.

(c) Landowner notification. (1)(i) No activity described in paragraphs (a) and (b) of this section that involves ground disturbance is authorized unless a company makes a good faith effort to notify in writing each affected landowner, as noted in the most recent county/city tax records as receiving the tax notice, whose property will be used and subject to ground disturbance as a result of the proposed activity, at least five days prior to commencing any activity under this section. A landowner may waive the five-day prior notice requirement in writing, so long as the notice has been provided. No landowner notice under this section is required:

(A) If all ground disturbance will be confined entirely to areas within the fence line of an existing above-ground site of facilities operated by the company; or

(B) For activities done for safety, DOT compliance, or environmental or unplanned maintenance reasons that are not foreseen and that require immediate attention by the company.

(ii) The notification shall include at least:

(A) A brief description of the facilities to be constructed or replaced and the effect the activity may have on the landowner's property;

(B) The name and phone number of a company representative who is knowledgeable about the project; and

(C) A description of the Commission's Landowner Helpline, which an affected person may contact to seek an informal resolution of a dispute as explained in § 1b.22(a) of this chapter and the Landowner Helpline number.

(2) “Affected landowners” include owners of interests, as noted in the most recent county/city tax records as receiving tax notice, in properties (including properties subject to rights-of-way and easements for facility sites, compressor stations, well sites, and all above-ground facilities, and access roads, pipe and contractor yards, and temporary work space) that will be directly affected by (i.e., used) and subject to ground disturbance as a result of activity under this section.

(d) [Reserved]

The Federal Energy Regulatory Commission will exercise the emergency powers set forth in the second proviso of section 7(c) of the Natural Gas Act to authorize in appropriate cases, by issuance of temporary certificates, comparatively minor enlargements or extensions of an existing pipeline system. It will not be the policy of the Commission, however, to proceed summarily, i.e., without notice or hearing, in cases where the proposed construction is of major proportions. Pipeline companies are accordingly urged to conduct their planning and to submit their applications for authority sufficiently early so that compliance with the requirements relating to issuance of permanent certificates of public convenience and necessity (when those requirements are deemed applicable by the Commission) will not cause undue delay in the commencement of necessary construction.

The Commission, cognizant of the need of the natural gas industry for advice with respect to the applicability of the Natural Gas Act and the Commission's regulations thereunder regarding activities and operations of natural gas companies taking security measures in preparation for a possible national emergency, sets forth the following interpretation and statement of policy:

(a) Facilities. The definition of auxiliary installations in § 2.55(a) for which no certificate authority is necessary includes such defense-related facilities as (1) fallout shelters at compressor stations and other operating and maintenance camps; (2) emergency company headquarters or other similar installations; and (3) emergency communication equipment.

(b) The Commission will consider reasonable investment in defense-related facilities, such as those described in paragraph (a) of this section, to be prudent investment for ratemaking purposes.

(c) When a person, not otherwise subject to the jurisdiction of the Commission, files an application for a certificate of public convenience and necessity authorizing the construction of facilities to be used solely for operation in a national emergency for the delivery of gas to, or receipt of gas from, a person subject to the Commission's jurisdiction, the Commission will consider a request by such applicant for waiver of the requirement to keep and maintain its accounts in accordance with the Uniform System of Accounts for Natural Gas Companies (parts 201 and 204 of this chapter) or to file the annual reports to the Commission required by §§ 260.1 and 260.2 of this chapter.

Pursuant to the provisions of section 441(a)(4)(A) of the Tax Reform Act of 1969, 83 Stat. 487, 625, natural gas pipeline companies which have exercised the option provided by that section to change from flow through accounting will be permitted by the Commission, with respect to liberalized depreciation, to employ a normalization method for computing Federal income taxes in their accounts and annual reports with respect to property constructed or acquired after January 1, 1970, to the extent to which such property increases the productive or operational capacity of the utility and is not a replacement of existing capacity. Such normalization will also be permitted for ratemaking purposes. As to balances in Account No. 282 of the Uniform System of Accounts, “Accumulated deferred income taxes—Other property,” it will remain the Commission's policy to deduct such balances from the rate base of natural gas pipeline companies in rate proceedings.

With respect to payments made to a first seller of natural gas as consideration for waiving or revising any agreement for the first sale of natural gas, as defined by section (2)(21) of the Natural Gas Policy Act (NGPA), the Commission sets forth the following statement of general policy and interpretation of law.

(a) Payments in consideration. A first seller of natural gas that receives payments as consideration for amending or waiving the take-or-pay or similar minimum payment provisions of a contract for the first sale of natural gas is not in violation of section 504(a) of the NGPA.

(b) Recovery in rates. A pipeline that makes any payments referred to under paragraph (a) of this section, to first sellers may file to recover such costs in any section 4(e) rate filing other than a filing to recover purchased gas costs.

(c) Case-specific review. A pipeline's method of recovering these costs and how it should apportion them among customers will be addressed on a case-by-case basis in the context of individual rate case filings.

(d) Customers' rights. When a pipeline seeks to recover payments referred to under paragraph (a) of this section, its customers will have the full opportunity contemplated by section 4 of the Natural Gas Act to raise questions as to the prudence of such payments, the apportionment of costs among customers proposed by the filing pipeline, and any other reasonably related matters.

(e) Certificate amendments and abandonment. With regard to natural gas the sale of which is subject to the Commission's jurisdiction under the Natural Gas Act, if any payments referred to under paragraph (a) of this section are accompanied by a change in or a termination of, the first seller's contractual obligation to provide natural gas service, the Commission will, as a general policy under sections 7(c) and 7(b) of the Natural Gas Act, expeditiously grant any certificate amendments or abandonment authorizations, required to effectuate such contractual or service modifications.

In cases where a producer abandonment application is based on payments made pursuant to this policy statement, the interstate pipeline making the payments will be deemed to have waived any right to oppose the abandonment.

(a)(1) The national interests in the development and utilization of natural gas resources throughout the United States will be served by recognition and implementation of the following priority-of-service categories for use during periods of curtailed deliveries by jurisdictional pipeline companies:

(i) Residential, small commercial (less than 50 Mcf on a peak day).

(ii) Large commercial requirements (50 Mcf or more on a peak day), firm industrial requirements for plant protection, feedstock and process needs, and pipeline customer storage injection requirements.

(iii) All industrial requirements not specified in paragraph (a)(1)(ii), (iv), (v), (vi), (vii), (viii), or (ix) of this section.

(iv) Firm industrial requirements for boiler fuel use at less than 3,000 Mcf per day, but more than 1,500 Mcf per day, where alternate fuel capabilities can meet such requirements.

(v) Firm industrial requirements for large volume (3,000 Mcf or more per day) boiler fuel use where alternate fuel capabilities can meet such requirements.

(vi) Interruptible requirements of more than 300 Mcf per day, but less than 1,500 Mcf per day, where alternate fuel capabilities can meet such requirements.

(vii) Interruptible requirements of intermediate volumes (from 1,500 Mcf per day through 3,000 Mcf per day), where alternate fuel capabilities can meet such requirements.

(viii) Interruptible requirements of more than 3,000 Mcf per day, but less than 10,000 Mcf per day, where alternate fuel capabilities can meet such requirements.

(ix) Interruptible requirements of more than 10,000 Mcf per day, where alternate fuel capabilities can meet such requirements.

(2) The priorities-of-deliveries set forth above will be applied to the deliveries of all jurisdictional pipeline companies during periods of curtailment on each company's system; except, however, that, upon a finding of extraordinary circumstances after hearing initiated by a petition filed under § 385.207 of this chapter, exceptions to those priorities may be permitted.

(3) The above list of priorities requires the full curtailment of the lower priority category volumes to be accomplished before curtailment of any higher priority volumes is commenced. Additionally, the above list requires both the direct and indirect customers of the pipeline that use gas for similar purposes to be placed in the same category of priority.

(4) The tariffs filed with this Commission should contain provisions that will reflect sufficient flexibility to permit pipeline companies to respond to emergency situations (including environmental emergencies) during periods of curtailment where supplemental deliveries are required to forestall irreparable injury to life or property.

(b) Request for relief from curtailment shall be filed under § 385.1501 of this chapter. Those petitions shall use the priorities set forth in (paragraph (a)(1) of this section) above, the definitions contained in paragraph (b)(3) of this section and shall contain the following minimal information:

(1) The specific amount of natural gas deliveries requested on peak day and monthly basis, and the type of contract under which the deliveries would be made.

(2) The estimated duration of the relief requested.

(3) A breakdown of all natural gas requirements on peak day and monthly bases at the plant site by specific end-uses.

(4) The specific end-uses to which the natural gas requested will be utilized and should also reflect the scheduling within each particular end-use with and without the relief requested.

(5) The estimated peak day and monthly volumes of natural gas which would be available with and without the relief requested from all sources of supply for the period specified in the request.

(6) A description of existing alternate fuel capabilities on peak day and monthly bases broken down by end-uses as shown in paragraph (b)(3) of this section.

(7) For the alternate fuels shown in paragraph (b)(5) of this section, provide a description of the existing storage facilities and the amount of present fuel inventory, names and addresses of existing alternate fuel suppliers, and anticipated delivery schedules for the period for which relief is sought.

(8) The current price per million Btu for natural gas supplies and alternate fuels supplies.

(9) A description of efforts to secure natural gas and alternate fuels, including documentation of contacts with the Federal Energy Office and any state or local fuel allocation agencies or public utility commission.

(10) A description of all fuel conservation activities undertaken in the facility for which relief is sought.

(11) If petitioner is a local natural gas distributor, a description of the currently effective curtailment program and details regarding any flexibility which may be available by effectuating additional curtailment to its existing industrial customers. The distributor should also provide a breakdown of the estimated disposition of its natural gas estimated to be available by end-use priorities established in paragraph (a)(1) of this section for the period for which relief is sought.

(c) When used in paragraphs (a) and (b) of this section, the following terms will be defined as follows:

(1) Residential. Service to customers which consists of direct natural gas usage in a residential dwelling for space heating, air conditioning, cooking, water heating, and other residential uses.

(2) Commercial. Service to customers engaged primarily in the sale of goods or services including institutions and local, state, and federal government agencies for uses other than those involving manufacturing or electric power generation.

(3) Industrial. Service to customers engaged primarily in a process which creates or changes raw or unfinished materials into another form or product including the generation of electric power.

(4) Firm service. Service from schedules or contracts under which seller is expressly obligated to deliver specific volumes within a given time period and which anticipates no interruptions, but which may permit unexpected interruption in case the supply to higher priority customers is threatened.

(5) Interruptible service. Service from schedules or contracts under which seller is not expressly obligated to deliver specific volumes within a given time period, and which anticipates and permits interruption on short notice, or service under schedules or contracts which expressly or impliedly require installation of alternate fuel capability.

(6) Plant protection gas. Is defined as minimum volumes required to prevent physical harm to the plant facilities or danger to plant personnel when such protection cannot be afforded through the use of an alternate fuel. This includes the protection of such material in process as would otherwise be destroyed, but shall not include deliveries required to maintain plant production. For the purposes of this definition propane and other gaseous fuels shall not be considered alternate fuels.

(7) Feedstock gas. Is defined as natural gas used as raw material for its chemical properties in creating an end product.

(8) Process gas. Is defined as gas use for which alternate fuels are not technically feasible such as in applications requiring precise temperature controls and precise flame characteristics. For the purposes of this definition propane and other gaseous fuels shall not be considered alternate fuels.

(9) Boiler fuel. Is considered to be natural gas used as a fuel for the generation of steam or electricity, including the utilization of gas turbines for the generation of electricity.

(10) Alternate fuel capabilities. Is defined as a situation where an alternate fuel could have been utilized whether or not the facilities for such use have actually been installed; Provided, however, Where the use of natural gas is for plant protection, feedstock, or process uses and the only alternate fuel is propane or other gaseous fuel then the consumer will be treated as if he had no alternate fuel capability.

(a) It will be the general policy of the Federal Energy Regulatory Commission to adopt and to adhere to the objectives and aims of the National Environmental Policy Act of 1969 (NEPA) in its regulations promulgated for statutes under the jurisdiction of the Commission, including the Federal Power Act, the Natural Gas Act and the Natural Gas Policy Act. The National Environmental Policy Act of 1969 requires, among other things, all Federal agencies to include a detailed environmental statement in every recommendation or report on proposals for legislation and other major Federal actions significantly affecting the quality of the human environment.

(b) Therefore, in compliance with the National Environmental Policy Act of 1969, the Commission staff will make a detailed environmental statement when the regulatory action taken by the Commission under the statutes under the jurisdiction of the Commission will have a significant environmental impact. The specific regulations implementing NEPA are contained in part 380 of the Commission's regulations.

(a) Recognizing that take or pay contract obligations may be shielding the prices of deregulated and other higher cost gas from market constraints, the Commission sets forth its general policy regarding prepayments for natural gas pursuant to take or pay provisions in gas contracts and amendments thereto between producers and interstate pipelines which become effective December 23, 1982. The provisions of this policy statement do not establish a binding norm but instead provide general guidance. In particular cases, both the underlying validity of the policy and its application to particular facts may be challenged and are subject to further consideration.

(b) With respect to gas purchase contracts entered into on or after December 23, 1982, the Commission intends to apply a rebuttable presumption in general rate cases that prepayments to producers will not be given rate base treatment if the prepayments are made pursuant to take or pay requirements in such gas purchase contracts or amendments which exceed 75 percent of annual deliverability.

(a) General Policy. The Commission as a matter of policy will provide two distinct mechanisms for passthrough of take-or-pay buyout and buydown costs of interstate natural gas pipelines. The first is pursuant to existing Commission policy and practice. Under this method, pipelines may pass through prudently incurred take-or-pay buyout and buydown costs in their sales commodity rates. The second method is available to pipelines which agree to an equitable sharing of take-or-pay costs and which transport under part 284 of this chapter. Qualifying pipelines may utilize the alternative passthrough mechanisms described in this section. Where a pipeline agrees to absorb from 25 to 50 percent of take-or-pay buyout and buydown costs, the Commission will permit the pipeline to recover through a fixed charge an amount equal to (but not greater than) the amount absorbed. Any remaining costs up to 50 percent of total buyout and buydown costs may be recovered either through a commodity rate surcharge or a volumetric surcharge on total throughput.

(b) Cost allocation procedures. A pipeline's volume-based surcharges must be based on the volumes which underlie its most recent Commission-approved rates. Fixed charges must be based on each customer's cumulative deficiency in purchases in recent years (during which the current take-or-pay liabilities of the pipelines were incurred) measured in relation to that customer's purchases during a representative period during which take-or-pay liabilities were not incurred. The allocation formula employed must incorporate the following guidelines:

(1) A representative base period must be selected. The base period must reflect a representative level of purchases by the pipeline's firm customers during a period preceding the onset of changed conditions which resulted in reduced purchases and growth of the take-or-pay problem.

(2) Firm purchases by each customer during the base year under firm rate schedules or contracts for firm service must be determined.

(3) Firm sales purchase deficiency volumes for each subsequent year must be determined.

(4) A fixed charge based on each customer's cumulative deficiencies as compared to total cumulative deficiencies must be derived. The filing pipeline will be free to select for rate calculation and filing purposes a reasonable amortization period for buyout and buydown costs being recovered through fixed charges or volumetric surcharges. The pipeline will be entitled to interest at the rate set forth in part 154 of this chapter on unamortized amounts.

(c) Implementing procedures. (1) Pipelines acting pursuant to this section may submit on or before December 31, 1990, a non-PGA rate filing under section 4(e) of the Natural Gas Act. Pipelines may include in their filings a fixed charge and a volumetric surcharge to recover buyout and buydown costs actually paid as of the date of filing plus similar costs which are known and measurable within the following nine months. Detailed support for the amounts claimed and for the calculation of customer surcharges must be provided. In addition, the pipeline must disclose and describe all consideration, both cash and noncash, given to producers in exchange for take-or-pay relief.

(2) In any filings made under this section, pipelines must include proposals for periodic (preferably annual) adjustments to customer surcharges, together with any necessary accounting procedures, designed to assure that revenues recovered by the pipeline remain in balance with buyout and buydown costs covered by the filing and actually incurred by the pipeline.

(d) Prudence. (1) The Commission will examine the issue of prudence if it is raised by a party in an individual proceeding. If it is raised, the pipeline will be required to demonstrate the prudence of take-or-pay buyout and buydown costs which it seeks to recover from its customers through both fixed and volume-based charges.

(2) The Commission intends to exercise its authority to the full extent permitted by the Natural Gas Act to approve take-or-pay settlements. The Commission intends to approve uncontested take-or-pay settlements which are consistent with this section and found to be in the public interest. The Commission will also, if it appears reasonable and permissible to do so, approve contested settlements as to all consenting parties and initiate separate hearings to establish the rates for opposing parties. Alternatively, the Commission will approve contested settlements on the merits if supported by substantial evidence in the record. In any case where hearings are held as to the prudence of take-or-pay buyout and buydown costs, the Commission will permit the pipeline the opportunity to recover all take-or-pay costs found to be prudent from the contesting parties on a proportional basis, even if the amount allowed is greater than the amounts initially sought to be recovered by the pipeline.

(e) Flowthrough by downstream pipelines. Downstream pipelines must flow through approved take-or-pay fixed charges based on the cumulative purchase deficiencies of their customers. Volumetrically-based surcharges must be flowed through on a volumetric basis. Customers of downstream pipelines have the right in connection with either PGA or general rate filings to challenge the purchasing practices of such pipelines. Remedies for purchasing practices found by the Commission to be imprudent will be determined on a case-by-case basis.

(f) Ongoing proceedings. Pipeline rate proceedings pending September 15, 1987 may be utilized as a forum for implementing the approved cost recovery mechanisms set forth in this section. Permission will be granted in cases where implementation of this policy in pending proceedings appears feasible, will not result in inordinate delay, or can be expected to result in unnecessary or cumulative rate filings with the Commission. In the event permission is granted, the presiding judge(s) will allow pipelines to supplement their filings to the extent necessary to assure compliance with the filing and data requirements set forth herein. The presiding judges shall also establish any procedures necessary to protect the rights of all parties. Any rates established pursuant to this section will be permitted to become effective only prospectively upon Commission approval.

(g) Scope. This section does not go beyond the Commission's determination in the April 10, 1985, policy statement (Docket No. PL85-1-000) that take-or-pay buyout and buydown costs do not violate the pricing provision of the Natural Gas Policy Act of 1978 (NGPA). It is not intended to affect take-or-pay prepayments made by pipelines and included in account 165 and in their rate bases. Nor does it address the issue of whether take-or-pay prepayments to a producer for gas not taken and which cannot be made up violate the Title I pricing provisions of the NGPA. This policy statement applies only to buyout and buydown costs paid by pipelines that are transporting under part 284 of this chapter, under existing contracts, and is not intended to disturb in any way take-or-pay settlements previously entered into between pipelines and their producer suppliers.

An interstate natural gas pipeline that transports under part 284 of this chapter may include in its tariff a charge, not related to facilities, for standing ready to supply gas to sales customers in accordance with the following principles:

(a) The pipeline may not recover take-or-pay or similar charges from suppliers by any other means.

(b) The pipeline must allow its sales customers to nominate levels of service freely within their firm sales entitlements or otherwise employ a mechanism for the renegotiation of levels of service at regular intervals.

(c) The pipeline must announce prior to nominations by the customers a firm price or pricing formula for the service, and hold that price or pricing formula firm during the interval arranged in paragraph (b) of this section.

(d) By nominating a new level of service lower than its current level, a customer has consented to any abandonment sought by the pipeline commensurate with the difference between the current level of service and the nominated level.

Recognizing the potential for an increasing number of intervenor complaints predicated on the fraud, abuse, or similar grounds exception to guaranteed passthrough, the Commission sets forth the elements of a cognizable claim under section 601(c)(2) which it expects to apply in cases in which fraud, abuse, or similar grounds is raised. The provisions of this policy statement do not establish a binding norm but instead provide general guidance. In particular cases, both the underlying validity of the policy and its application to particular facts may be challenged and are subject to further consideration. The procedure prescribed conforms with the NGPA's general guarantee of passthrough by placing the burden of pleading the elements and proving the elements of a case on intervenors who would allege fraud, abuse, or similar grounds as a basis for denying passthrough of gas prices incurred by an interstate pipeline.

(a) In order for the issue of fraud, as that term is used in section 601(c) of the NGPA, to be considered in a proceeding, an intervenor or intervenors must file a complaint alleging that:

(1) The interstate pipeline, any first seller who sells natural gas to the interstate pipeline, or both acting together, have made a fraudulent misrepresentation or concealment; and

(2) Because of that fraudulent misrepresentation or concealment, the amount paid by the interstate pipeline to any first seller of natural gas was higher than it would have been absent the fraudulent conduct.

(b) In order for the issue of abuse, as that term is used in section 601(c) of the NGPA, to be considered in a proceeding, an intervenor or intervenors must file a complaint alleging that:

(1) The interstate pipeline, a first seller who sells to the interstate pipeline, or both acting together, have made a negligent misrepresentation or concealment, or other misrepresentation or concealment in disregard of a duty; and

(2) Because of that negligent misrepresentation or concealment, or other misrepresentation or concealment in disregard of a duty, the amount paid by the interstate pipeline to any first seller of natural gas was higher than it would have been absent the negligent misrepresentation or concealment, or other misrepresentation or concealment made in disregard of a duty.

(c) In order for the issue of similar grounds, as that term is used in section 601(c) of the NGPA, to be considered in a proceeding, an intervenor or intervenors must file a complaint alleging that:

(1) The interstate pipeline, any first seller who sells natural gas to the interstate pipeline, or both acting together, have made an innocent misrepresentation of fact; and

(2) Because of that innocent misrepresentation of facts, the amount paid by the interstate pipeline to any first seller of natural gas was higher than it would have been absent the innocent misrepresentation of fact.

For purposes of deciding whether natural gas may be considered as waste as the primary energy source pursuant to § 292.204(b)(1)(i) of this chapter, the Commission will use the criteria described in paragraphs (a), (b) and (c) of this section.

(a) Category 1. Except as provided in paragraph (b) of this section, natural gas with a heating value of 300 Btu per standard cubic foot (scf) or below will be considered unmarketable.

(b) Category 2. In determining whether natural gas with a heating value above 300 Btu but not more than 800 Btu per scf and natural gas produced in the Moxa Arch area is unmarketable, the Commission will consider the following information:

(1) The percentages of the chemical components of the gas, the wellhead pressure, and the flow rate;

(2) Whether the applicant offered the gas to all potential buyers located within 20 miles of the wellhead under terms and conditions commensurate with those prevailing in the region and that such potential buyers refused to buy the gas; and

(3) A study, which may be submitted by an applicant, that evaluates the economics of upgrading the gas for sale and transporting the gas to a pipeline. The study should include estimates of the revenues which could be derived from the sale of the gas and the fixed and variable costs of upgrading.

(c) Category 3. In determining whether natural gas with a heating value above 800 Btu per scf is marketable, the Commission will consider the information included in paragraph (b) of this section and whether:

(1) The gas has actually been flared, vented to the atmosphere, or continuously injected into a non-producing zone for a period of one year, pursuant to legal authority; or

(2) The gas has been certified as waste, i.e., suitable for disposal, by an appropriate state authority.

(a) It is the policy of the Commission that any small entity is eligible to be considered for a reduction or waiver of a civil penalty if it has no history of previous violations, and the violations at issue are not the product of willful or criminal conduct, have not caused loss of life or injury to persons, damage to property or the environment or endangered persons, property or the environment. An eligible small entity will be granted a waiver if it can also demonstrate that it performed timely remedial efforts, made a good faith effort to comply with the law and did not obtain an economic benefit from the violations. An eligible small entity that cannot meet the criteria for waiver of a civil penalty may be eligible for consideration of a reduced penalty. Upon the request of a small entity, the Commission will consider the entity's ability to pay before assessing a civil penalty.

(b) Notwithstanding paragraph (a) of this section, the Commission reserves the right to waive or reduce civil penalties in appropriate individual circumstances where it determines that a waiver or reduction is warranted by the public interest.

These guidelines shall be followed to determine what area may be used to construct the auxiliary or replacement facility. Specifically, they address what areas, in addition to the permanent right-of-way, may be used.

An auxiliary or replacement facility must be within the existing right-of-way or facility site as specified by § 2.55(a)(1) or § 2.55(b)(1)(ii). Construction activities for the auxiliary or replacement facility can extend outside the current permanent right-of-way if they are within the temporary and permanent right-of-way and associated work spaces authorized for the construction of the existing installation.

If documentation is not available on the location and width of the temporary and permanent rights-of-way and associated work spaces that were used to construct the existing facility, the company may use the following guidance for the auxiliary installation or replacement, provided the appropriate easements have been obtained:

a. Construction should be limited to no more than a 75-foot-wide right-of-way including the existing permanent right-of-way for large diameter pipeline (pipe greater than 12 inches in diameter) to carry out routine construction. Pipeline 12 inches in diameter and smaller should use no more than a 50-foot-wide right-of-way.

b. The temporary right-of-way (working side) should be on the same side that was used in constructing the existing pipeline.

c. A reasonable amount of additional temporary work space on both sides of roads and interstate highways, railroads, and significant stream crossings and in side-slope areas is allowed. The size should be dependent upon site-specific conditions. Typical work spaces are:

d. The auxiliary or replacement facility must be located within the permanent right-of-way or, in the case of nonlinear facilities, the cleared building site. In the case of pipelines this is assumed to be 50 feet wide and centered over the pipeline unless otherwise legally specified.

However, use of the above guidelines for work space size is constrained by the physical evidence in the area. Areas obviously not cleared during the existing construction, as evidenced by stands of mature trees, structures, or other features that exceed the age of the facility being replaced, should not be used for construction of the auxiliary or replacement facility.

If these guidelines cannot be met, the company should consult with the Commission's staff to determine if the exemption afforded by § 2.55 may be used. If the exemption may not be used, construction authorization must be obtained pursuant to another regulation under the Natural Gas Act.