Title 18—Conservation of Power and Water Resources--Volume 2

§ 125.1 Promulgation.

This Part is prescribed and promulgated as the regulations governing the preservation of records by public utilities subject to the jurisdiction of the Commission and by licensees holding licenses issued by the Commission, to the extent and in the manner set forth therein.

[Order 617, 65 FR 48155, Aug. 7, 2000]

§ 125.2 General instructions.

(a) Scope of this part. (1) The regulations in this part apply to all books of account and other records prepared by or on behalf of the public utility or licensee. See item 40 of the schedule (§ 125.3) for those records that come into possession of the public utility or licensee in connection with the acquisition of property, such as purchase, consolidation, merger, etc.

(2) The regulations in this part should not be construed as excusing compliance with other lawful requirements of any other governmental body, Federal or State, prescribing other record keeping requirements or for preservation of records longer than those prescribed in this part.

(3) To the extent that any Commission regulations may provide for a different retention period, the records should be retained for the longer of the retention periods.

(4) Records other than those listed in the schedule may be destroyed at the option of the public utility or licensee: Provided, however, That records which are used in lieu of those listed shall be preserved for the periods prescribed for the records used for substantially similar purposes. And, provided further, That retention of records pertaining to added services, functions, plant, etc., the establishment of which cannot be presently foreseen, shall conform to the principles embodied herein.

(5) Notwithstanding the provisions of the Records Retention Schedule, the Commission may, upon the request of the Company, authorize a shorter period of retention for any record listed therein upon a showing by the Company that preservation of such record for a longer period is not necessary or appropriate in the public interest or for the protection of investors or consumers.

(b) Designation of supervisory official. Each public utility or licensee subject to the regulations in this part shall designate one or more persons with official responsibility to supervise the utility's or licensee's program for preservation and the authorized destruction of its records.

(c) Protection and storage of records. The public utility or licensee shall provide reasonable protection for records subject to the regulations in this part from damage by fire, floods, and other hazards and, in the selection of storage spaces, safeguards the records from unnecessary exposure to deterioration from excessive humidity, dryness, or lack of proper ventilation.

(d) Record storage media. Each public utility and licensee has the flexibility to select its own storage media subject to the following conditions.

(1) The storage media must have a life expectancy at least equal to the applicable record retention period provided in § 125.3 unless there is a quality transfer from one media to another with no loss of data.

(2) Each public utility and licensee is required to implement internal control procedures that assure the reliability of, and ready access to, data stored on machine readable media. Internal control procedures must be documented by a responsible supervisory official.

(3) Each transfer of data from one media to another must be verified for accuracy and documented. Software and hardware required to produce readable records must be retained for the same period the media format is used.

(e) Destruction of records. At the expiration of the retention period, public utilities and licensees may use any appropriate method to destroy records.

(f) Premature destruction or loss of records. When records are destroyed or lost before the expiration of the prescribed period of retention, a certified statement listing, as far as may be determined, the records destroyed and describing the circumstances of accidental or other premature destruction or loss must be filed with the Commission within ninety (90) days from the date of discovery of the destruction.

(g) Schedule of records and periods of retention. (1) Records related to plant in service must be retained until the facilities are permanently removed from utility service, all removal and restoration activities are completed, and all costs are retired from the accounting records unless accounting adjustments resulting from reclassification and original costs studies have been approved by the regulatory commission having jurisdiction. If the plant is sold, the associated records or copies thereof, must be transferred to the new owners.

(2) Records related to hydroelectric facilities and additions, retirements, and betterments thereto must be retained until:

(i) The Commission has determined the actual legitimate original cost of the facilities, or the licenses are surrendered. If the plant is sold, the associated records or copies thereof, must be transferred to the new owners.

(ii) Records related to the determination of amortization reserves pursuant to section 10(d) of the Federal Power Act must be retained until a final determination and adjudication of the amortization reserves are made.

(h) Retention periods designated “Destroy at option”. “Destroy at option” constitutes authorization for destruction of records at managements' discretion if it does not conflict with other legal retention requirements or usefulness of such records in satisfying pending regulatory actions or directives.

(i) Records of services performed by associated companies. Public utilities and licensees must assure the availability of records of services performed by and for associated or affiliated companies with supporting cost information for the periods indicated in § 125.3 as necessary to be able to readily furnish detailed information as to the nature of the transaction, the amounts involved, and the accounts used to record the transactions.

(j) Index of records. Public utilities and licensees must arrange, file, and index records so records may be readily identified and made available to Commission representatives.

(k) Rate case. Notwithstanding the minimum retention periods provided in these regulations, if a public utility or licensee wants to reflect costs in a current, future, or pending rate case, or if a public utility or licensee has abandoned or retired a plant subsequent to the test period of the utility's rate case, the utility must retain the appropriate records to support the costs and adjustments proposed in the current or next rate case.

(l) Pending complaint litigation or governmental proceedings. Notwithstanding the minimum requirements, if a public utility or licensee is involved in pending litigation, complaint procedures, proceedings remanded by the court, or governmental proceedings, it must retain all relevant records.

(m) Life or mortality study data. Life or mortality study data for depreciation purposes must be retained for 25 years or for 10 years after plant is retired, whichever is longer.

(Secs. 3, 4, 15, 16, 308; 41 Stat. 1063-1066, 1068, 1072, 1075; 49 Stat. 838-841; 82 Stat. 617 (16 U.S.C. 796, 797, 803, 808, 809, 816, 825b, 825g, 826i); secs. 8, 10, 16; 52 Stat. 825, 826, 830 (15 U.S.C. 717g, 717i, 717o))

[Order 450, 37 FR 6293, Mar. 28, 1972, as amended by Order 567, 42 FR 30615, June 16, 1977; Order 258, 47 FR 42724, Sept. 29, 1982; Order 335, 48 FR 44483, Sept. 29, 1983; Order 617, 65 FR 48155, Aug. 7, 2000]

§ 125.3 Schedule of records and periods of retention.

Table of Contents Corporate and General 1. Reports to stockholders. 2. Organizational documents. 3. Contracts including amendments and agreements. 4. Accountants' and auditors' reports. Information Technology Management 5. Automatic data processing records. General Accounting Records 6. General and subsidiary ledgers. 7. Journals: General and subsidiary. 8. Journal vouchers and entries. 9. Cash books. 10. Voucher registers. 11. Vouchers. Insurance 12. Insurance records. Operations and Maintenance 13.1. Production—Public utilities and licensees (less nuclear). 13.2 Production—Nuclear. 14. Transmission and distribution—Public utilities and licensees. 15. Maintenance work orders and job orders. Plant and Depreciation 16. Plant ledgers. 17. Construction work in progress ledgers. 18. Retirement work in progress ledgers. 19. Summary sheets. 20. Appraisals and valuations. 21. Engineering records. 22. Contracts relating to utility plant. 23. Reclassification of utility plant account records. 24. Accumulated depreciation and depletion of utility plant account records. Purchase and Stores 25. Procurement. 26. Material ledgers. 27. Materials and supplies received and issued. 28. Records of sales of scrap and materials and supplies. Revenue Accounting and Collection 29. Customers' service applications and contracts. 30. Rate schedules. 31. Maximum demand and demand meter record cards. 32. Miscellaneous billing data. 33. Revenue summaries. Tax 34. Tax records. Treasury 35. Statements of funds and deposits. 36. Records of deposits with banks and others. Miscellaneous 37. [Reserved] 38. Statistics. 39. Budgets and other forecasts. 40. Records of predecessors companies. 41. Reports to Federal and State regulatory commissions. 42. Advertising.

Schedule of Records and Periods of Retention

Item No. and description | Retention period

Corporate and General

1. Reports to stockholders: Annual reports or statements to stockholders | 5 years.

2. Organizational documents:

(a) Minute books of stockholders', directors', and directors' committee meetings | 5 years or termination of the corporation's existence, whichever occurs first.

(b) Titles, franchises, and licenses: Copies of formal orders of regulatory commissions served upon the utility | 6 years after final non-appealable order.

3. Contracts, including amendments and agreements (except contracts provided for elsewhere):

(a) Service contracts, such as for management, accounting, and financial services | All contracts, related memoranda, and revisions should be retained for 4 years after expiration or until the conclusion of any contract disputes pertaining to such contracts, whichever is later.

(b) Contracts with others for transmission or the purchase, sale or interchange of product | All contracts, related memoranda, and revisions should be retained for 4 years after expiration or until the conclusion of any contract disputes or governmental proceedings pertaining to such contracts, whichever is later.

(c) Memoranda essential to clarifying or explaining provisions of contracts listed above, including requests for discounts | For the same periods as contracts to which they relate.

(d) Card or book records of contracts, leases, and agreements made, showing dates of expirations and of renewals, memoranda of receipts, and payments under such contracts | For the same periods as contracts to which they relate.

4. Accountants' and auditors' reports:

(a) Reports of examinations and audits by accountants and auditors not in the regular employ of the utility (such as reports of public accounting firms and commission accountants) | 5 years after the date of the report.

(b) Internal audit reports and working papers | 5 years after the date of the report.

Information Technology Management

5. Automatic data processing records (retain original source data used as input for data processing and data processing report printouts for the applicable periods prescribed elsewhere in the schedule): Software program documentation and revisions thereto | Retain as long as it represents an active viable program or for periods prescribed for related output data, whichever is shorter.

General Accounting Records

6. General and subsidiary ledgers:

(a) Ledgers:

(1) General ledgers | 10 years.

(2) Ledgers subsidiary or auxiliary to general ledgers except ledgers provided for elsewhere | 10 years.

(b) Indexes:

(1) Indexes to general ledgers | 10 years.

(2) Indexes to subsidiary ledgers except ledgers provided for elsewhere | 10 years.

(c) Trial balance sheets of general and subsidiary ledgers | 2 years.

7. Journals: General and subsidiary | 10 years.

8. Journal vouchers and journal entries including supporting detail:

(a) Journal vouchers and journal entries | 10 years.

(b) Analyses, summarization, distributions, and other computations which support journal vouchers and journal entries:

(1) Charging plant accounts | 25 years. See § 125.2(g).

(2) Charging all other accounts | 6 years.

9. Cash books: General and subsidiary or auxiliary books | 5 years after close of fiscal year.

10. Voucher registers: Voucher registers or similar records when used as a source document | 5 years. See § 125.2(g).

11. Vouchers:

(a) Paid and canceled vouchers (one copy-analysis sheets showing detailed distribution of charges on individual vouchers and other supporting papers) | 5 years. See § 125.2(g).

(b) Original bills and invoices for materials, services, etc., paid by vouchers | 5 years. See § 125.2(g).

(c) Paid checks and receipts for payments of specific vouchers | 5 years.

(d) Authorization for the payment of specific vouchers | 5 years. See § 125.2(g).

(e) Lists of unaudited bills (accounts payable), list of vouchers transmitted, and memoranda regarding changes in audited bills | Destroy at option.

(f) Voucher indexes | Destroy at option.

Insurance

12. Insurance records:

(a) Records of insurance policies in force, showing coverage, premiums paid, and expiration dates | Destroy at option after expiration of such policies.

(b) Records of amounts recovered from insurance companies in connection with losses and of claims against insurance companies, including reports of losses, and supporting papers | 6 years. See § 125.2(g).

Operations and Maintenance

13.1 Production—Public utilities and licensees (less Nuclear):

(a) Boiler-tube failure report | 3 years.

(b) Generation and output logs with supporting data: | 3 years.

(c) Station and system generation reports and clearance logs:

(1) Hydro-electric | 25 years. See § 125.2(g).

(2) Steam and others | 6 years. See § 125.2(g).

(d) Generating high-tension and low-tension load records | 3 years.

(e) Load curves, temperature logs, coal, and water logs | 3 years.

(f) Gauge-reading reports | 2 years, except river flow data collected in connection with hydro operation must be retained for life of corporation.

(g) Recording instrumentation charts | 1 year, except where the basic chart information is transferred to another record, the charts need only be retained 6 months provided the record containing the basic data is retained 1 year.

13.2 Production—Nuclear:

For informational purposes, refer to the document retention requirements of the Nuclear Regulatory Commission.

14. Transmission and distribution—Public utilities and licensees.

(a) Substation and transmission line logs | 3 years.

(b) System operator's daily logs and reports of operation | 3 years.

(c) Transformer history records | For life of transformer.

(d) Records of transformer inspections, oil tests, etc. | Destroy at option.

15. Maintenance work orders and job orders:

(a) Authorizations for expenditures for maintenance work to be covered by work orders, including memoranda showing the estimates of costs to be incurred | 5 years.

(b) Work order sheets to which are posted in detail the entries for labor, material, and other charges in connection with maintenance, and other work pertaining to utility operations | 5 years.

(c) Summaries of expenditures on maintenance and job orders and clearances to operating other accounts (exclusive of plant accounts) | 5 years.

Plant and Depreciation

16. Plant ledgers:

(a) Ledgers of utility plant accounts including land and other detailed ledgers showing the cost of utility plant by classes | 25 years. See § 125.2(g).

(b) Continuing plant inventory ledger, book or card records showing description, location, quantities, cost, etc., of physical units (or items) of utility plant owned | 25 years. See § 125.2(g).

17. Construction work in progress ledgers, work orders, and supplemental records:

(a) Construction work in progress ledgers | 5 years after clearance to plant account, provided continuing plant inventory records are maintained; otherwise 5 years after plant is retired.

(b) Work orders sheets to which are posted in summary form or in detail the entries for labor, materials, and other charges for utility plant additions and the entries closing the work orders to utility plant in service at completion | 5 years after clearance to plant account, provided continuing plant inventory records are maintained; otherwise 5 years after plant is retired.

(c) Authorizations for expenditures for additions to utility plant, including memoranda showing the detailed estimates of cost, and the bases therefor (including original and revised or subsequent authorizations) | 5 years after clearance to plant account except where there are ongoing Commission proceedings.

(d) Requisitions and registers of authorizations for utility plant expenditures | 5 years after clearance to plant account except where there are ongoing Commission proceedings.

(e) Completion or performance reports showing comparison between authorized estimates and actual expenditures for utility plant additions | 5 years after clearance to plant account except where there are ongoing Commission proceedings.

(f) Analysis or cost reports showing quantities of materials used, unit costs, number of man-hours etc., in connection with completed construction project | 5 years after clearance to plant account except where there are ongoing Commission proceedings.

(g) Records and reports pertaining to progress of construction work, the order in which jobs are to be completed, and similar records which do not form a basis of entries to the accounts | Destroy at option.

18. Retirement work in progress ledgers, work orders, and supplemental records:

(a) Work order sheets to which are posted the entries for removal costs, materials recovered, and credits to utility plant accounts for cost of plant retirement | 5 years after plant is retired.

(b) Authorizations for retirement of utility plant, including memoranda showing the basis for determination to be retired and estimates of salvage and removal costs | 5 years after plant is retired.

(c) Registers of retirement work | 5 years.

19. Summary sheets, distribution sheets, reports, statements, and papers directly supporting debits and credits to utility plant accounts not covered by construction or retirement work orders and their supporting records | 5 years.

20. Appraisals and valuations:

(a) Appraisals and valuations made by the company of its properties or investments or of the properties or investments of any associated companies. (Includes all records essential thereto.) | 3 years after appraisal.

(b) Determinations of amounts by which properties or investments of the company or any of its associated companies will be either written up or written down as a result of:

(1) Mergers or acquisitions | 10 years after completion of transaction or as ordered by the Commission.

(2) Asset impairments | 10 years after recognition of asset impairment.

(3) Other bases | 10 years after the asset was written up or down.

21. The original or reproduction of engineering records, drawings, and other supporting data for proposed or as-constructed utility facilities: Maps, diagrams, profiles, photographs, field survey notes, plot plan, detail drawings, records of engineering studies, and similar records showing the location of proposed or as-constructed facilities | Retain until retired.

22. Contracts relating to utility plant:

(a) Contracts relating to acquisition or sale of plant | 6 years after plant is retired or sold.

(b) Contracts and other agreements relating to services performed in connection with construction of utility plant (including contracts for the construction of plant by others for the utility and for supervision and engineering relating to construction work) | 6 years after plant is retired or sold.

23. Records pertaining to reclassification of utility plant accounts to conform to prescribed systems of accounts including supporting papers showing the bases for such reclassifications | 6 years.

24. Records of accumulated provisions for depreciation and depletion of utility plant and supporting computation of expense:

(a) Detailed records or analysis sheets segregating the accumulated depreciation according to functional classification of plant | 25 years.

(b) Records reflecting the service life of property and the percentage of salvage and cost of removal for property retired from each account for depreciable utility plant | 25 years.

Purchase and Stores

25. Procurement:

(a) Agreements entered into for the acquisition of goods or the performance of services. Includes all forms of agreements not specifically set forth in Subsection 7 such as but not limited to: Letters of intent, exchange of correspondence, master agreements, term contracts, rental agreements, and the various types of purchase orders:

(1) For goods or services relating to plant construction | 6 years. See § 125.2(g).

(2) For other goods or services | 6 years.

(b) Supporting documents including accepted and unaccepted bids or proposals (summaries of unaccepted bids or proposals may be kept in lieu of originals) evidencing all relevant elements of the procurement | 6 years. See § 125.2(g).

26. Material ledgers: Ledger sheets of materials and supplies received, issued, and on hand | 6 years after the date the records/ledgers were created.

27. Materials and supplies received and issued: Records showing the detailed distribution of materials and supplies issued during accounting periods | 6 years. See § 125.2(g).

28. Records of sales of scrap and materials and supplies:

(a) Authorization for sale of scrap and materials and supplies | 3 years.

(b) Contracts for sale of scrap materials and supplies | 3 years.

Revenue Accounting and Collecting

29. Customers' service applications and contracts: Contracts, including amendments for extensions of service, for which contributions are made by customers and others | 4 years after expiration.

30. Rate schedules: General files of published rate sheets and schedules of utility service. Including schedules suspended or superseded | 6 years after published rate sheets and schedules are superseded or no longer used to charge for utility service.

31. Maximum demand, and demand meter record cards | 1 year, except where the basic chart information is transferred to another record the charts need only be retained 6 months, provided the basic data is retained 1 year.

32. Miscellaneous billing data: Billing department's copies of contracts with customers (other than contracts in general files) | Destroy at option.

33. Revenue summaries: Summaries of monthly operating revenues according to classes of service. Including summaries of forfeited discounts and penalties | 5 years.

Tax

34. Tax records:

(a) Copies of tax returns and supporting schedules filed with taxing authorities, supporting working papers, records of appeals of tax bills, and receipts for payment. See Subsection 11(b) for vouchers evidencing disbursements:

(1) Income tax returns | 2 years after final tax liability is determined.

(2) Property tax returns | 2 years after final tax liability is determined.

(3) Sales and other use taxes | 2 years.

(4) Other taxes | 2 years after final tax liability is determined.

(5) Agreements between associate companies as to allocation of consolidated income taxes | 2 years after final tax liability is determined.

(6) Schedule of allocation of consolidated Federal income taxes among associate companies | 2 years after final tax liability is determined.

(b) Filings with taxing authorities to qualify employee benefit plans | 5 years after discontinuance of plan.

(c) Information returns and reports to taxing authorities | 3 years after final tax liability is determined.

Treasury

35. Statements of funds and deposits | For nuclear decommissioning funds, retain records for all items listed for 3 years after final decommissioning is completed. If amortization reserve funds related to licensed projects are maintained, retain until the Commission makes a final determination of the disposition of amortization reserves.

(a) Statements of periodic deposits with fund administrators or trustees | Retain records for the most recent 3 years.

(b) Statements of periodic withdrawals from fund | Retain records for the most recent 3 years.

(c) Statements prepared by fund administrator or trustees of fund activity including: | Retain records until the fund is dissolved or terminated.

(1) Beginning of the year balance of fund;

(2) Deposits with the fund;

(3) Acquisition of investments held by the fund;

(4) Disposition of investments held by the fund;

(5) Disbursements from the fund, including party to whom disbursement was made;

(6) End of year balance of fund.

36. Records of deposits with banks and others:

(a) Statements from depositories showing the details of funds received, disbursed, transferred, and balances on deposit | Destroy at option after completion of audit by independent accountants.

(b) Check stubs, registers, or other records of checks issued | 3 years.

Miscellaneous

37. [Reserved]

38. Statistics: Financial, operating and statistical reports used for internal administrative or operating purposes | 5 years.

39. Budgets and other forecasts (prepared for internal administrative or operating purposes) of estimated future income, receipts and expenditures in connection with financing, construction and operations, including acquisitions and disposals of properties or investments | 3 years.

40. Records of predecessor companies | Retain consistent with the requirements for the same types of records of the utility.

41. Reports to Federal and State regulatory commissions including annual financial, operating and statistical reports | 5 years.

42. Advertising: Copies of advertisements by or for the company on behalf of itself or any associate company in newspapers, magazines, and other publications, including costs and other records relevant thereto (excluding advertising of appliances, employment opportunities, routine notices, and invitations for bids all of which may be destroyed at option) | 2 years.

[Order 617, 65 FR 48156, Aug. 7, 2000; 65 FR 50638, Aug. 21, 2000]

§ 131.20 Application for approval of transfer of license.

(See §§ 9.1 through 9.10 of this chapter.)

(This application and all accompanying documents shall be submitted in quadruplicate, together with one additional copy for each interested State commission) Before the Federal Energy Regulatory Commission application for approval of transfer of license

(1)__________________, licensee under the license for Project No. ______, issued by the Commission on __________________ (Month, day, year) and

(2) __________________, (hereinafter referred to as the Transferee).

(3) Hereby jointly and severally apply for the written approval by the Federal Energy Regulatory Commission of the transfer of the aforesaid license from the transferor to the transferee and request that the instrument of such approval by the Commission be made effective as of the date of conveyance of the project properties; and in support thereof show the Commission as follows:

(4) The said transferee is:

(a) 4 A citizen of the United States, whereof proof is submitted herewith as Exhibit A, which is hereby incorporated herein and made a part hereof;

4 In par. 4 include only the subparagraph which is applicable.

(b) 4 An association of citizens under articles of association, a certified copy of which as now in effect is attached hereto as exhibit A and hereby incorporated herein and made a part hereof;

(c) 4 A municipality organized under the following statutes: __________________, proof of such organization being submitted herewith as Exhibits A-1, A-2, etc., which is [are] hereby incorporated herein and made a part hereof;

(d) 5 A __________________ (e.g., private, nonprofit, etc.) corporation, organized under the laws of the State of __________________, and domesticated in the States of __________________, __________________; certified copies of its charter or certificate or incorporation, articles of incorporation, corporate by-laws, and certificates of authority to do business, with all amendments of each to date, being submitted herewith as exhibits A-1, A-2, etc., said exhibits being hereby incorporated herein and made a part hereof;

5 This form for application contemplates the filing of the application and Commission action thereon prior to any conveyance of the project properties. If the Commission acts favorably upon the application, it will issue to the applicants an order approving the transfer of the license. Applicants may then consummate the conveyance of the project properties and transferee shall submit to the Commission certified copies of the instruments of such conveyance (see par. 6 of this form). The transferor shall at the same time make payment of annual charges to the date of the conveyance (see par. 6 of this form). The transferor shall at the same time make payment of annual charges to the date of the conveyance (see par. 8 of this form). The transferee shall at the same time submit to the Commission final proofs showing its compliance with state laws. See par. 5 of this form. The transferor shall at the same time turn over to the transferee all license instruments and all maps, plans, specifications, contracts, reports of engineers, accounts, books, records, and all other papers and documents, relating to the original project and to all additions thereto and betterments thereof.

(5) The transferee submits as [partial] evidence of its compliance with all applicable State laws as required by section 9(a)(2) of the Federal Power Act __________________ submitted herewith as exhibits B-1, B-2, etc., and proposes to complete its showing of such compliance by submitting ____________

to be submitted as exhibits B-3, B-4, etc., at the time it submits proof of the conveyance to it of the project properties as hereinafter provided for; 5

5 See footnote 5 on preceding page.

(6) The transferee will submit certified copies of all instruments of conveyance whereby title to the project properties is conveyed to it, upon the completion of such conveyance, if and when the Commission shall have given its approval to the proposed transfer;

(7) If and when the Commission shall have given its approval to the proposed transfer, and upon completion of conveyance of the project properties to the transferee, the transferor will deliver to the transferee and the transferee will accept and permanently retain all license instruments and all maps, plans, specifications, contracts, reports of engineers, accounts, books, records, and all other papers and documents relating to the original project and to all additions thereto and betterments thereof;

(8) The transferor certifies that it has fully complied with the terms and conditions of its license, as amended, and that it has fully satisfied and discharged all of its liabilities and obligations thereunder to the date hereof, and obligates itself to pay all annual charges accrued under the license to the date of transfer;

(9) Contingent upon the final written approval by the Commission of the transfer of the license, the transferee accepts all the terms and conditions of the said license [as amended] and the act, and agrees to be bound thereby to the same extent as though it were the original licensee thereunder;

(10) The name, title, and post-office address of the person or persons to whom correspondence in regard to this application shall be addressed are as follows:

In witness whereof the transferor has caused its name to be hereunto signed by ________________________ (Name), its ________________________ (Title—chief executive officer), and its corporate seal to be hereunto affixed by ________________________ (Name), its ________________________ (Title—custodian of seal), thereunto duly authorized, this ________________ day of ________________, 19____; and the transferee has caused its name to be hereunto signed by __________________ (Name), its __________________ (Title—chief executive officer), and its corporate seal to be hereunto affixed by __________________ (Name), its __________________ (Title—custodian of seal), thereunto duly authorized this ______________ day of ________________, 19____. 6

6 If applicant is a natural citizen modify final paragraph.

______________________________ (Exact name of transferor) By (Name) ______________________________ (Title) (Exact name of transferee) By ______________________________ (Name) ______________________________ (Title) Attest: ______________________________ (Secretary) verification 7

7 To be separately executed by each of the persons signing the foregoing application.

State of County of ____________, ss: ________________________ being duly sworn deposes and says: That he is the (Title of person signing the application) of the ________________________ (Name of one of applicants), one of the applicants for approval of transfer of license; that he has read the foregoing application and knows the contents thereof; and that the same are true to the best of his knowledge and belief. __________________________ (Signature)

Subscribed and sworn to before me, a notary public of the State of ______________ this ______________ day of ______________, 19____.

Exhibit A proof of citizenship 8

8 If the applicant is a natural person or an association of citizens, proof of citizenship is required. Such proof may be made by affidavit in the form indicated.

State of County of ______________, ss:

____________________, ____________________ and ____________________, being duly sworn, each for himself, deposes and says that he is a citizen of the United States of America.

Subscribed and sworn to before me, a notary public of the State of ______________ this ______________ day of ______________, 19____.

[Order 141, 12 FR 8588, Dec. 19, 1947, as amended by Order 175, 19 FR 5218, Aug. 18, 1954; Order 541, 57 FR 21734, May 22, 1992; Order 699, 72 FR 45325, Aug. 14, 2007]

§ 131.31 FERC Form No. 561, Annual report of interlocking positions.

(See section 46.4 of this chapter.)

INSTRUCTIONS FOR COMPLETING ANNUAL REPORT OF INTERLOCKING POSITIONS GENERAL INFORMATION: Purpose of Report The data collected by this report will be used by the Federal Energy Regulatory Commission's staff for the review and oversight of interlocking positions between public utilities and certain other entities as described below. Who Must Submit This report must be completed by all persons holding interlocking positions between public utilities and certain other entities (described in the specific instructions) during any portion of the calendar year. When to Submit Submit this report on or before April 30 of each year for the preceding calendar year. (For example, the report for the year 1999 would be filed on or before April 30, 2000.) What and Where to Submit Submit an original and one (1) copy of this report to: Federal Energy Regulatory Commission, Office of the Secretary, Attention FERC 561, 888 First Street NE, Washington, DC 20426 Sanctions This report is mandatory and is prescribed by Section 305(c)(1) of the Federal Power Act and 18 CFR 46.4. Failure to report may result in certain penalties and other sanctions as provided by law. Where to Send Comments on Public Reporting Burden The public reporting burden for this collection of information is estimated to average 0.25 hours per response, including the time for reviewing the instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding this burden estimate or any other aspect of this collection of information to: Federal Energy Regulatory Commission, Attn: Federal Energy Regulatory Commission Information Clearance Officer, 888 First Street NE., Washington, DC 20426. You shall not be penalized for failure to respond to this collection of information unless the collection of information displays a valid OMB control number. GENERAL INSTRUCTIONS

1. Prepare this report in conformity with the requirements prescribed in 18 CFR 46.4.

2. Leave blank any columns that are not applicable.

SPECIFIC INSTRUCTIONS Item and Instruction Respondent Information 1 and 2 Enter your full name and your business address. 3 Enter the calendar year for which this report is filed. 4 and 5 If you are authorized by this Commission to hold the position of officer or director in accordance with Part 45 of the Commission's regulations: enter in space 4 the complete FERC docket number of such authorization; enter in space 5 the latest date of such authorization. Otherwise, leave these spaces blank. 6 Enter the public utility or public utility holding company to which you want next year's Form 561 sent. Public Utility Data Col (1) and Col (2) Enter in column (1) the name of each public utility in which you hold an executive position. In column (2) enter the appropriate code for each such position, according to the list below: Code and Name Dir Director CEO Chief Executive Officer PRES President VP Vice President SEC Secretary TREA Treasurer GM General Manager COMP Comptroller PURA Chief Purchasing Agent OEP Other Executive Position Interlocking Entity Data Col (3) and Col (4) Enter in Column (3) the name of each entity in which you hold an interlocking position. Enter the appropriate code for each executive position you hold in the entity named in Column (3), using the list below: Code and Name DIR Director CEO Chief Executive Officer PRES President VP Vice President SEC Secretary TREA Treasurer GM General Manager COMP Comptroller PURA Chief Purchasing Agent PART Partner APPT Appointee REP Representative OEP Other Executive Position Col (5) Enter in Column (5) the appropriate code type for each entity listed in Column (3), using the list below: Code and Name FIN Investment bank; bank holding company; foreign bank or subsidiary thereof doing business in the United States; other organization primarily engaged in the business of providing financial services or credit; mutual savings bank; or savings and loan association FINI Insurance company SECU Entity authorized by law to underwrite or participate in the marketing of securities of a public utility ELEQ Entity which produces/supplies electric equipment for the use of any public utility FUEL Entity which produces/supplies coal, natural gas, nuclear fuel, or other fuel for the use of any public utility 20CL Entity specified in 18 CFR 46.3 (one of the 20 largest purchasers of electric energy from a utility) CNEN Entity which is controlled by any one of the above named entities 305B Entity referred to in Section 305(b) of the Federal Power Act (not otherwise identified above) Col (6) For each entity that supplies electric equipment (ELEQ) named in Column (3) enter the aggregate amount of revenues from producing or supplying electrical equipment to any public utility named in column (1) in the subject calendar year, rounded to the nearest $100,000. Otherwise, leave this column blank. Signature The original of this report must be dated and signed. The copy must bear the date that appeared on the original. The signature on the copy may be stamped or typed on the copy.

[Order 601, 63 FR 72169, Dec. 31, 1998]

§ 131.43 Report of securities issued.

(See § 34.10 of this chapter.)

(Submit an original and four copies.)

[Name of respondent]

Report of Securities Issued

Description of security....................................

Description | Amount

1. Face value or principal amount

2. Plus premium or less discount

3. Gross proceeds

4. Underwriter's spread or commission

5. Securities and Exchange Commission registration fee

6. State mortgage registration tax

7. State commission fee

8. Fee for recording indenture

9. United States document tax

10. Printing and engraving expenses

11. Trustee's charges

12. Counsel fees

13. Accountant's fees

14. Cost of listing

15. Miscellaneous expenses of issue

(Describe large items)

16. Total deductions

17. Net amount realized

[Order 141, 12 FR 8591, Dec. 19, 1947, as amended by Order 182, 46 FR 50517, Oct. 14, 1981]

Effective Date Note: At 70 FR 35375, June 20, 2005, § 131.43 introductory text was revised, effective at the time of the next e-filing release during the Commission's next fiscal year. For the convenience of the user, the revised text follows:

§ 131.43 Report of securities issued.

(See § 34.10 of this chapter)

(Submit in electronic format in accordance with § 385.2003 of this chapter.)

§ 131.50 Reports of proposals received.

No later than 30 days after the sale or placement of long-term debt or equity securities or the entry into guarantees or assumptions of liabilities (collectively referred to as “placement”) pursuant to authority granted under Part 34 of this chapter, the applicant must file a summary of each proposal or proposals received for the placement. The proposal or proposals accepted must be indicated. The information to be filed must include:

(a) Par or stated value of securities;

(b) Number of units (shares of stock, number of bonds) issued;

(c) Total dollar value of the issue;

(d) Life of the securities, including maximum life and average life of sinking fund issue;

(e) Dividend or interest rate;

(f) Call provisions;

(g) Sinking fund provisions;

(h) Offering price;

(i) Discount or premium;

(j) Commission or underwriter's spread;

(k) Net proceeds to company for each unit of security and for the total issue;

(l) Net cost to the company for securities with a stated interest or dividend rate.

(m) This section shall cease to have effect on December 5, 2026, unless the Commission determines that the cessation deadline should be extended to a date not more than 5 years in the future after offering the public an opportunity to provide input on the costs and benefits of this section and considering that input. The Commission will publish a document in the Federal Register announcing its determination and revising or removing this section accordingly.

[Order 575, 60 FR 4855, Jan. 25, 1995, as amended by Order 914, 90 FR 48402, Oct. 21, 2025]

Effective Date Note: At 70 FR 35375, June 20, 2005, § 131.50 paragraphs (a) and (b) were revised, effective at the time of the next e-filing release during the Commission's next fiscal year. For the convenience of the user, the revised text follows:

§ 131.50 Report of proposals received.

(a) No later than 30 days after the sale or placement of long-term debt or equity securities or the entry into guarantees or assumptions of liabilities (collectively referred to as “placement”) pursuant to authority granted under Part 34 of this chapter, the applicant must file, in electronic format, a summary of each proposal or proposals received for the placement. The proposal or proposals accepted must be indicated. The information to be filed must include:

(1) Par or stated value of securities;

(2) Number of units (shares of stock, number of bonds) issued;

(3) Total dollar value of the issue;

(4) Life of the securities, including maximum life and average life of sinking fund issue;

(5) Dividend or interest rate;

(6) Call provisions;

(7) Sinking fund provisions;

(8) Offering price;

(9) Discount or premium;

(10) Commission or underwriter's spread;

(11) Net proceeds to company for each unit of security and for the total issue;

(12) Net cost to the company for securities with a stated interest or dividend rate.

(b) This report must be filed with the Commission as prescribed in § 385.2003 of this chapter and as indicated in the instructions set out in this report. This report is an electronic file that is classified as a “qualified document” in accordance with § 385.2003(c)(1) and (2). As a qualified document, no paper copy version of the filing is required unless there is a request for privileged or protected treatment or the document is combined with another document as provided in § 385.2003(c)(3) or (4).

§ 131.51 [Reserved]

§ 131.52 Certificate of concurrence.

(See §§ 35.1 through 35.21 of this chapter.)

This is to certify that__________________

(Name of public utility concurring) assents to and concurs in the rate schedule (rate schedule supplement) described below, which the____________________________ (Name of public utility filing rate schedule) has filed, and hereby files this certificate of concurrence in lieu of the filing of the rate schedule (rate schedule supplement) specified. (Here give exact description of rate schedule or supplement, including F.E.R.C. number) (Name of public utility) By (Title)

Dated __________________ 19____.

Note 1 to § 131.52:

This section shall cease to have effect on December 5, 2026, unless the Commission determines that the cessation deadline should be extended to a date not more than 5 years in the future after offering the public an opportunity to provide input on the costs and benefits of this section and considering that input. The Commission will publish a document in the Federal Register announcing its determination and revising or removing this section accordingly.

[Order 141, 12 FR 8591, Dec. 19, 1947, as amended by Order 271, 28 FR 11404, Oct. 24, 1963; Order 541, 57 FR 21734, May 22, 1992; Order 714, 73 FR 57533, Oct. 3, 2008; Order 914, 90 FR 48403, Oct. 21, 2025]

§ 131.53 [Reserved]

§ 131.70 Form 12 of application by State and municipal licensees for exemption from payment of annual charges.

12 Copies of this form may be obtained upon request from the Federal Energy Regulatory Commission.

(See § 11.6 of this chapter.) Application by State and municipal licensees for exemption from payment of annual charges must be prepared on this form. The form specifies that in filing application for exemption, the following data and schedules shall be submitted:

1. Name and address of correspondent;

2. Basis for claimed exemption;

3. Generating plants owned or operated by licensee;

4. Transmission lines and distribution lines;

5. KWH of power generated, purchased and interchanged;

6. Power sold or otherwise disposed of (kwh);

7. Power interchange (in detail);

8. Statement of unusual conditions attending the disposition of electric power;

9. Book cost of electric property;

10. Operating revenues;

11. Operating expenses and other deductions from revenues;

12. Affidavit.

[Order 143, 13 FR 6682, Nov. 13, 1948, as amended by Order 756, 77 FR 4894, Feb. 1, 2012]

§ 131.80 FERC Form No. 556, Certification of qualifying facility (QF) status for a small power production or cogeneration facility.

(a) Who must file. Any person seeking to certify a facility as a qualifying facility pursuant to sections 3(17) or 3(18) of the Federal Power Act, 16 U.S.C. 796(3)(17), (3)(18), unless otherwise exempted or granted a waiver by Commission rule or order pursuant to § 292.203(d), must complete and file the Form of Certification of Qualifying Facility (QF) Status for a Small Power Production or Cogeneration Facility, FERC Form No. 556. Every Form of Certification of Qualifying Status must be submitted on the FERC Form No. 556 then in effect and must be prepared in accordance with the instructions incorporated in that form.

(b) Availability of FERC Form No. 556. The currently effective FERC Form No. 556 shall be made available for download from the Commission's Web site.

(c) How to file a FERC Form No. 556. All applicants must file their FERC Forms No. 556 electronically via the Commission's eFiling Web site.

[Order 732, 75 FR 15965, Mar. 30, 2010]

§ 141.1 FERC Form No. 1, Annual report of Major electric utilities, licensees and others.

(a) Prescription. The Form of Annual Report for Major electric utilities, licensees and others, designated herein as FERC Form No. 1, is prescribed for the reporting year 1981 and each year thereafter.

(b) Filing requirements—(1) Who must file—(i) Generally. Each Major and each Nonoperating (formerly designated as Major) electric utility (as defined in part 101 of Subchapter C of this chapter) and each licensee as defined in section 3 of the Federal Power Act (16 U.S.C. 796), including any agency, authority or other legal entity or instrumentality engaged in generation, transmission, distribution, or sale of electric energy, however produced, throughout the United States and its possessions, having sales or transmission service equal to Major as defined above, must prepare and file electronically with the Commission the FERC Form 1 pursuant to the General Instructions as provided in that form.

(ii) Exceptions. This report form is not prescribed for any agency, authority or instrumentality of the United States, nor is it prescribed for municipalities as defined in section 3 of the Federal Power Act; (i.e., a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the laws thereof to carry on the business of developing, transmitting, utilizing, or distributing power).

(2) When to file and what to file. (i) The annual report for the year ending December 31, 2004, must be filed on April 25, 2005.

(ii) The annual report for each year thereafter must be filed on April 18.

(iii) This report must be filed with the Federal Energy Regulatory Commission as prescribed in § 385.2011 of this chapter and as indicated in the General Instructions set out in this form, and must be properly completed and verified. Filing on electronic media pursuant to § 385.2011 of this chapter is required.

[Order 200, 47 FR 1280, Jan. 12, 1982, as amended by Order 390, 49 FR 32515, Aug. 14, 1984; Order 574, 60 FR 1718, Jan. 5, 1995; Order 626, 67 FR 36096, May 23, 2002; 69 FR 9043, Feb. 26, 2004; Order 694, 72 FR 20723, Apr. 26, 2007; 73 FR 58736, Oct. 7, 2008]

§ 141.2 FERC Form No. 1-F, Annual report for Nonmajor public utilities and licensees.

(a) Prescription. The form of Annual Report for Nonmajor Public Utilities and Licensees, designated herein as FERC Form No. 1-F, is prescribed for the year 1980 and each year thereafter.

(b) Filing Requirements—(1) Who Must File—(i) Generally. Each Nonmajor and each Nonoperating (formerly designated as Nonmajor) public utility and licensee as defined in Part 101 of this chapter, shall prepare and file with the Commission FERC Form No. 1-F as prescribed in § 385.2011 of this chapter and as indicated in the General Instructions set out in this form, and must be properly completed and verified. Filing on electronic media pursuant to § 385.2011 of this chapter is required.

(ii) Exceptions. FERC Form No. 1-F is not prescribed for any municipality as defined in Section 3 of the Federal Power Act, i.e., a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the laws thereof to carry on the business of developing, transmitting, utilizing, or distributing power.

(2) When to file. (i) The annual report for the year ending December 31, 2004, must be filed on April 25, 2005.

(ii) The annual report for each year thereafter must be filed on April 18.

[Order 101, 45 FR 60899, Sept. 15, 1980, as amended by Order 390, 49 FR 32515, Aug. 14, 1984; 50 FR 5744, Feb. 12, 1985; 69 FR 9043, Feb. 26, 2004; Order 694, 72 FR 20723, Apr. 26, 2007; Order 859, 84 FR 30628, June 27, 2019]

§ 141.15 Annual Conveyance Report.

If a licensee of a hydropower project is required by its license to file with the Commission an annual report of conveyances of easements or rights-of-way across, or leases of, project lands, the report must be filed only if such a conveyance or lease of project lands has occurred in the previous year.

[Order 540, 57 FR 21738, May 22, 1992]

§ 141.51 FERC Form No. 714, Annual Electric Balancing Authority Area and Planning Area Report.

(a) Who must file. (1) Any electric utility, as defined by section 3(4) of the Public Utility Regulatory Policies Act, 16 U.S.C. 2602, operating a balancing authority area, and any group of electric utilities, which by way of contractual arrangements operates as a single balancing authority area, must complete and file the applicable schedules in FERC Form No. 714 with the Federal Energy Regulatory Commission.

(2) Any electric utility, or group of electric utilities that constitutes a planning area and that has a peak load greater than 200 megawatts (MW) based on net energy for load for the reporting year, must complete applicable schedules in FERC Form No. 714.

(b) When to file. FERC Form No. 714 must be filed on or before each June 1 for the preceding calendar year.

(c) What to file. FERC Form No. 714, Annual Electric Balancing Authority Area and Planning Area Report, must be filed with the Federal Energy Regulatory Commission as prescribed in § 385.2011 of this chapter and as indicated in the General Instructions set out in this form.

[58 FR 52436, Oct. 8, 1993, as amended by Order 20723, 72 FR 20725, Apr. 26, 2007]

§ 141.61 [Reserved]

§ 141.100 Original cost statement of utility property.

Any public utility or licensee becoming subject to the jurisdiction of the Commission shall file, insofar as applicable, the following statements properly sworn to by the officer in responsible charge of their compilation:

Statement A

Statement A showing in outline the origin and development of the company including particularly a description (giving names of parties and dates) of each consolidation and merger to which the company, or a predecessor, was a party and each acquisition of an electric operating unit or system.

Statement B

Statement B showing for each acquisition by the reporting company or any of its predecessors of an electric operating unit or system, the original cost, estimated, if not known, the cost of such company and the amount entered in the books in respect thereto as of the date of acquisition. If the depreciation, retirement, or amortization reserve was adjusted as of the date of acquisition and in connection therewith, a full disclosure of the pertinent facts should be made. The difference between the original cost and the amount entered in respect thereto of each acquisition of an electric operating unit or system, as of the date of acquisition, should be clearly stated, and a summary of all transactions affecting such difference through the end of the calendar year prior to the year in which the filing is made, and the resultant amount at the latter date, should be set forth. The amount to be included in account 114, Electric Plant Acquisition Adjustments, shall be subdivided so as to show the amounts applicable to (1) electric plant in service, (2) electric plant leased to others, and (3) electric plant held for future use. Whenever practical, such amount shall be classified according to nature, i.e., going value, structural value, etc.

Where estimates are used in arriving at original cost or the amount to be included in account 114, a full disclosure of the method and underlying facts should be given. The method of determining the original cost of the electric plant acquired as operating units or systems should be described in sufficient detail to permit a clear understanding of the nature of the investigations which were made for that purpose.

Statement C

Statement C showing any amounts arrived at by appraisals in the electric plant accounts (and not eliminated) in lieu of cost to the reporting company. This statement should give the full journal entry at the time the appraisal was originally recorded and if the entry had the effect of appreciating or writing up the electric plant account, the amount of the appreciation of writeup should be traced, by proper description and explanation of changes, from the date recorded through the end of the calendar year prior to the year in which the filing is made.

Statement D

Statement D showing electric plant as classified in the books of account immediately prior to reclassification in accordance with the Uniform System of Accounts, including, under a descriptive heading, any unclassified amounts applicable jointly to the electric department and other departments of the utility.

Statement E

Statement E showing summary of adjustments necessary to state accounts 101, 103-107, 114, and 116, as prescribed in the Uniform System of Accounts.

Statement F

Statement F showing electric plant classified according to the accounts prescribed in the Uniform System of Accounts, and showing also the amount includible in account 116, Other Electric Plant Adjustments.

Statement G

Statement G giving a comparative balance sheet showing the accounts and amounts appearing in the books before the adjusting entries have been made and after such entries shall have been made.

Statement H

Statement H giving a suggested plan for depreciating, amortizing, or otherwise disposing in whole or in part of the amounts includible in account 114, Electric Plant Acquisition Adjustments, and account 116, Other Electric Plant Adjustments.

Statement I

Statement I giving the following statistical information relative to electric plant.

Production Plant

Steam production. Separately for each steam plant: Name of plant, date of construction, nameplate generating capacity (kw.) as originally constructed and as at present, also nameplate capacity and date of installation of each addition to generating capacity. The original cost, where available, by accounts 310 and 316, of each steam production plant.

Hydraulic production. Separately for each hydroplant: Name of plant, date of construction, capacity of reservoirs (acre-feet), nameplate generating capacity (kw.) as originally constructed and as at present, also nameplate capacity and date of installation of each addition to generating capacity. The original cost, where available, by accounts 330 and 336, of each hydraulic production plant.

Internal combustion engine production. For each internal combustion engine plant: Name of plant, date of construction, nameplate generating capacity (kw.) as originally constructed and as at present, also nameplate capacity and date of installation of each addition to generating capacity. The original cost, where available, by accounts 340 to 346, of each internal combustion engine production plant.

Transmission Plant

Overhead transmission lines. For each overhead transmission line or for each group of transmission lines of the same voltage, same general type of construction, and same number of circuits per structure; the voltage, length in miles, type of construction, kind and size of conductor. The original cost, where available, by accounts 350, 352, 354, 355, 356, and 359, of each such line or group of lines.

Underground transmission lines. For each underground transmission line or for each group of transmission lines of the same voltage, same general type of construction and same number of circuits per structure: The voltage length in miles and type of construction. The original cost, where available, by accounts 350, 352, 357, 358, and 359, of each such line or group of lines.

Transmission substations. For each substation: Function, capacity (kva), high and low voltages of transformers, description and capacity of special items of equipment.

Distribution Plant

Overhead system. 1 Number of pole and circuit miles, number of active meters or services connected (if available), description and number of each type of pole or tower.

1 If number of active meters or services is not available separately for overhead and underground systems, report totals.

Underground system. 2 Number of circuit miles, number of active meters or services connected (if available), description of type of construction and general statement of any special construction problem.

2 To be shown on the original when tendered for filing with the Commission of every paper as specified in § 1.17(f) of this chapter.

Distribution substation. General description of number, capacity (kva) and high and low voltages of transformers.

Line transformers. Number and capacity.

Street lighting and signal systems. Description and number of each type of street lighting standard, number and wattage of lamps, and description of signal system.

General Plant

Description of principal structures and improvements.

Number and type of transportation vehicles and appurtenant equipment.

Description of store, shop, and laboratory equipment.

Description of communication equipment.

Description of miscellaneous equipment.

[38 FR 7214, Mar. 19, 1973. Redesignated by Order 541, 57 FR 21734, May 22, 1992]

§ 141.300 FERC Form No. 715, Annual Transmission Planning and Evaluation Report.

(a) Who must file. Any transmitting utility, as defined in § 3(23) of the Federal Power Act, that operates integrated (that is, non-radial) transmission facilities at or above 100 kilovolts must complete FERC Form No. 715.

(b) When to file. FERC Form No. 715 must be filed on or before each April 1.

(c) What to file. FERC Form No. 715 must be filed with the Federal Energy Regulatory Commission in accordance with the instructions on that form.

(d) Critical Energy Infrastructure Information. (1) If the instructions in Form No. 715 require a utility to reveal Critical Energy Infrastructure Information (CEII), as defined in § 388.113(c) of this chapter, to any person, the utility shall omit the CEII from the information made available and insert the following in its place:

(i) A statement that CEII is being withheld;

(ii) A brief description of the omitted information that does not reveal any CEII; and

(iii) This statement: “Procedures for obtaining access to Critical Energy Infrastructure Information (CEII) may be found at 18 CFR 388.113. Requests for access to CEII should be made to the Commission's CEII Coordinator.”

(2) The utility completing Form No. 715, in determining whether information constitutes CEII, shall treat the information in a manner consistent with any filings that utility has made with the Commission and shall to the extent practicable adhere to any previous determinations by the Commission or the CEII Coordinator involving the same or like information.

(3) The procedures contained in §§ 388.112 and 388.113 of this chapter regarding designation of, and access to, CEII, shall apply in the event of a challenge to a CEII designation or a request for access to CEII. If it is determined that information is not CEII or that a requester should be granted access to CEII, the utility will be directed to make the information available to the requester.

(4) Nothing in this section shall be construed to prohibit any persons from voluntarily reaching arrangements or agreements calling for the disclosure of CEII.

[58 FR 52436, Oct. 8, 1993, as amended by Order 643, 68 FR 52095, Sept. 2, 2003]

§ 141.400 FERC Form No. 3-Q, Quarterly financial report of electric utilities, licensees, and natural gas companies.

(a) Prescription. The quarterly report of electric utilities, licensees, and natural gas companies, designated as FERC Form No. 3-Q, is prescribed for the reporting quarter ending March 31, 2004, and each quarter thereafter.

(b) Filing requirements—(1) Who must file—(i) Generally. Each electric utility and each Nonoperating (formerly designated as Major or Nonmajor) electric utility (as defined in part 101 of subchapter C of this chapter) and other entity, i.e., each corporation, person, or licensee as defined in section 3 of the Federal Power Act (16 U.S.C. 792 et seq.), including any agency or instrumentality engaged in generation, transmission, distribution, or sale of electric energy, however produced, throughout the United States and its possessions, having sales or transmission service must prepare and file with the Commission FERC Form No. 3-Q pursuant to the General Instructions set out in that form.

(ii) Exceptions. This report form is not prescribed for any agency, authority or instrumentality of the United States, nor is it prescribed for municipalities as defined in section 3 of the Federal Power Act; (i.e. a city, county, irrigation district, or other political subdivision or agency of a State competent under the laws thereof to carry on the business of developing, transmitting, utilizing, or distributing power).

(2) Each Major and Nonoperating (formerly designated as Major) (as defined in part 101 of subchapter C of this chapter) public utility and licensee must file the quarterly financial report form as follows:

(i) The quarterly financial report for the period January 1 through March 31, 2004, must be filed on or before July 9, 2004.

(ii) The quarterly financial report for the period April 1 through June 30, 2004, must be filed on or before September 8, 2004.

(iii) The quarterly financial report for the period July 1 through September 30, 2004, must be filed on or before December 9, 2004.

(iv) The quarterly financial report for the period January 1 through March 31, 2005, must be filed on or before May 31, 2005.

(v) The quarterly financial report for the period April 1 through June 30, 2005, must be filed on or before August 29, 2005.

(vi) The quarterly financial report for the period July 1 through September 30, 2005 must be filed on or before November 29, 2005.

(vii) Subsequent quarterly financial reports must be filed within 60 days from the end of the reporting quarter.

(3) Nonmajor and Nonoperating (formerly designated as Nonmajor) public utilities and licensees must file the quarterly financial report form as follows:

(i) The quarterly financial report for the period January 1 through March 31, 2004, must be filed on or before July 23, 2004.

(ii) The quarterly financial report for the period April 1 through June 30, 2004, must be filed on or before September 22, 2004.

(iii) The quarterly financial report for the period July 1 through September 30, 2004, must be filed on or before December 23, 2004.

(iv) The quarterly financial report for the period January 1 through March 31, 2005, must be filed on or before June 13, 2005.

(v) The quarterly financial report for the period April 1 through June 30, 2005, must be filed on or before September 12, 2005.

(vi) The quarterly financial report for the period July 1 through September 30, 2005 must be filed on or before December 13, 2005.

(vii) Subsequent quarterly financial reports must be filed within 70 days from the end of the reporting quarter.

(4) This report must be filed as prescribed in § 385.2011 of this chapter and as indicated in the General Instructions set out in the quarterly financial report form, and must be properly completed and verified. Filing on electronic media pursuant to § 385.2011 of this chapter will be required commencing with the quarterly financial report ending March 31, 2004, due on or before July 9, 2004 for major public utilities and licensees, and due on or before July 23, 2004 for nonmajor public utilities and licensees.

[69 FR 9043, Feb. 26, 2004, as amended by Order 646-A, 69 FR 32443, June 10, 2004; Order 646, 69 FR 34568, June 22, 2004; Order 695, 72 FR 20723, Apr. 26, 2007; 73 FR 58736, Oct. 7, 2008]

§ 141.500 Cash management programs.

Public utilities and licensees subject to the provisions of the Commission's Uniform System of Accounts prescribed in part 101 and § 141.1 or § 141.2 of this title that participate in cash management programs must file these agreements with the Commission. The documentation establishing the cash management program and entry into the program must be filed within 10 days of the effective date of the rule or entry into the program. Subsequent changes to the cash management agreement must be filed with the Commission within 10 days of the change.

[Order 634-A, 68 FR 62003, Oct. 31, 2003, as amended at 69 FR 9044, Feb. 26, 2004]

§ 152.1 Exemption applications and blanket certificates.

(a) Application for exemption from the provisions of the Natural Gas Act and the rules and regulations of the Commission issued pursuant thereto may be made by any person as defined in the Natural Gas Act engaged in, or authorized to engage in the transportation in interstate commerce or the sale in interstate commerce for resale, of natural gas received by such applicant from another person within or at the boundary of a State, if all of the natural gas so received is ultimately consumed in such State: Provided, That the natural-gas rates (including rates for sales for resale) and service of the applicant and its natural-gas facilities are subject to regulation by a State Commission, as defined in the Natural Gas Act, and that such State Commission is exercising that jurisdiction.

(b)(1)(i) For purposes of the Commission's regulations implementing the Natural Gas Act, “vehicular natural gas” or “VNG” means natural gas that will be used, in either a gaseous or liquefied state, as fuel in any self-propelled vehicle.

(ii) For purposes of the Commission's regulations implementing the Natural Gas Act, vehicular natural gas, or VNG, is deemed to be ultimately consumed in the state in which the gas is physically delivered into the vehicle's fuel tank regardless of whether the tank is attached to the vehicle at the time it is filled.

(2)(i) Blanket certificates of public convenience and necessity are issued pursuant to section 7(c) of the Natural Gas Act to all persons that engage in sales for resale of VNG that are subject to the Commission's authority under section 1(b) of the NGA, such authorization to be effective upon that person's engagement in the jurisdictional sale. A blanket certificate issued under this paragraph (b)(2)(i) is a certificate of limited jurisdiction which will not subject the certificate holder to any other regulation under the Natural Gas Act jurisdiction of the Commission by virtue of transactions under the certificate. Such certificate will not impair the continued validity of any Natural Gas Act exemption from Commission jurisdiction.

(ii) A blanket certificate issued under paragraph (b)(2)(i) of this section authorizes the holder to make sales of VNG for resale in interstate commerce at market rates.

(iii) Abandonment of the sales service authorized in paragraph (b)(2)(i) of this section is authorized pursuant to section 7(b) of the Natural Gas Act upon the expiration of the contractual term or upon termination of each individual sales arrangement.

(Sec. 1(c), 68 Stat. 36; 15 U.S.C. 717(c))

[Order 306, 30 FR 12729, Oct. 6, 1965, as amended by Order 543, 57 FR 32894, July 24, 1992]

§ 152.2 Form of application; service.

The application must be filed with the Secretary of the Commission in accordance with filing procedures posted on the Commission's Web site at http://www.ferc.gov. A copy of the application shall be served on the State Commission which has jurisdiction over the applicant and upon each wholesale customer of the applicant.

[Order 737, 75 FR 43404, July 26, 2010]

§ 152.3 Contents of application.

Every application shall set forth in the order indicated, the following:

(a) The exact legal name of applicant.

(b) The name, title, and post office address of the person to whom correspondence in regard to the application shall be addressed.

(c) A statement of pertinent facts as to the existing service, if any, or authorized service by applicant, including a showing that all of the natural gas which applicant receives from out-of-State sources is and will be ultimately consumed within the State in which the operations sought to be exempted are conducted.

(Secs. 3, 16, 52 Stat. 822, 830; 15 U.S.C. 717b, 717o)

[Order 173, 19 FR 4276, July 13, 1954, as amended by Order 317, 31 FR 432, Jan. 13, 1966; Order 433, 50 FR 40345, Oct. 3, 1985; Order 737, 75 FR 43404, July 26, 2010]

§ 152.4 Certificate from State Commission.

Applications for exemption under § 152.3 shall contain, or there shall be separately filed, a certificate from the appropriate State Commission that the natural-gas (a) rates (including rates for sales for resale), (b) service, and (c) facilities of the applicant are subject to the regulatory jurisdiction of the State Commission and that the State Commission is exercising such jurisdiction.

(Sec. 1(c), 68 Stat. 36; 15 U.S.C. 717(c))

[Order 306, 30 FR 12729, Oct. 6, 1965]

§ 152.5 Applicability of exemption.

Nothing in this part shall be construed to relieve any person exempted from the provisions of the Natural Gas Act by section 1(c) thereof from compliance with valid State regulatory requirements. If an exemption from the provisions of the Natural Gas Act is effective pursuant to section 1(c), the exempted person shall be responsible for calling to the attention of the State Commission by which it is regulated and of the Federal Energy Regulatory Commission any future operations in which it may engage which may make the exemption inapplicable to it. The exempted person shall also be responsible for calling to the attention of the Federal Energy Regulatory Commission any changes, amendment, or judicial or administrative interpretation of the State law pursuant to which it is regulated, which may make the exemption inapplicable to it.

(Sec. 1(c), 68 Stat. 36; 15 U.S.C. 717(c))

[Order 306, 30 FR 12729, Oct. 6, 1965, as amended by Order 737, 75 FR 43404, July 26, 2010]

§ 153.1 Purpose and scope.

The purpose of this part is to implement the Commission's delegated authorities under section 3 of the Natural Gas Act and Executive Order 10485, as amended by Executive Order 12038. Subpart B of this part establishes filing requirements an applicant must follow to obtain authorization under section 3 of the Natural Gas Act for the siting, construction, operation, place of entry for imports or place of exit for exports. Subpart C of this part establishes filing requirements an applicant must follow to apply for a Presidential Permit, or an amendment to an existing Presidential Permit, for border facilities at the international boundary between the United States and Canada or Mexico.

§ 153.2 Definitions.

(a) DOE/FE means the Department of Energy/Office of Fossil Energy or its successor office.

(b) Person means an individual or entity as defined in 10 CFR 590.102(m).

(c) LNG Terminal means all natural gas facilities located onshore or in state waters that are used to receive, unload, load, store, transport, gasify, liquefy, or process natural gas that is imported to the United States from a foreign country, exported to a foreign country from the United States, or transported in interstate commerce by a waterborne vessel, but does not include:

(1) Waterborne vessels used to deliver natural gas to or from any such facility; or

(2) Any pipeline or storage facility subject to the jurisdiction of the Commission under section 7 of the Natural Gas Act.

(d) For purposes of this part and § 157.21, related jurisdictional natural gas facilities means any pipeline or other natural gas facilities which are subject to section 7 of the NGA; will directly interconnect with the facilities of an LNG terminal, as defined in paragraph (d) of this section; and which are necessary to transport gas to or regasified LNG from:

(1) A planned but not yet authorized LNG terminal; or

(2) An existing or authorized LNG terminal for which prospective modifications are subject pursuant to section 157.21(e)(2) to a mandatory pre-filing process.

(e) Waterway Suitability Assessment (WSA) means a document used by the U.S. Coast Guard in assessing the suitability of a waterway for LNG marine traffic pursuant to 33 CFR 127.007. The Preliminary WSA initiates the process of analyzing the safety and security risks posed by proposed LNG tanker operations to a port and waterways, and the Follow-On WSA provides a detailed analysis of the same issues.

[Order 595, 62 FR 30446, June 4, 1997, as amended by Order 665, 70 FR 60440, Oct. 18, 2005; Order 900, 88 FR 74041, Oct. 30, 2023]

§ 153.3 Notice requirements.

All applications filed under this part are subject to the landowner notification requirements in § 157.6(d) of this chapter.

[Order 609, 64 FR 57390, Oct. 25, 1999]

§ 153.4 General requirements.

The procedures in §§ 157.5, 157.6, 157.8, 157.9, 157.10, 157.11, and 157.12 of this chapter are applicable to the applications described in this subpart.

[86 FR 16302, Mar. 29, 2021]

§ 153.5 Who shall apply.

(a) Applicant. Any person proposing to site, construct, or operate facilities which are to be used for the export of natural gas from the United States to a foreign country or for the import of natural gas from a foreign country or to amend an existing Commission authorization, including the modification of existing authorized facilities, shall file with the Commission an application for authorization therefor under subpart B of this part and section 3 of the Natural Gas Act.

(b) Cross-reference. Any person applying under paragraph (a) of this section to construct facilities at the borders of the United States and Canada or Mexico must also simultaneously apply for a Presidential Permit under subpart C of this part.

§ 153.6 Time of filing.

(a) An application filed pursuant to § 153.5(a) shall state whether DOE/FE authorization for the import/export of natural gas is required and whether DOE/FE has granted all required authorizations for the import/export of natural gas.

(b) If all required DOE/FE authorizations have not been obtained prior to filing an application with the Commission, the applicant agrees, as a condition of its authorization, to file a statement that all required DOE/FE authorizations have been obtained prior to applicant's construction of border facilities.

(c) When a prospective applicant for authorization for LNG terminal facilities, related jurisdictional natural gas facilities or modifications to existing LNG terminal facilities is required by § 157.21(a) to comply with that section's pre-filing procedures, no application for such authorization may be made before 180 days after the date of issuance of the notice by the Director of the Office of Energy Projects, as provided in § 157.21(e), of the commencement of the prospective applicant's pre-filing process under § 157.21.

[Order 595, 62 FR 30446, June 4, 1997, as amended by Order 665, 70 FR 60440, Oct. 18, 2005]

§ 153.7 Contents of application.

Every application under subpart B of this part shall include, in the order indicated, the following:

(a) Information regarding applicant. (1) The exact legal name of applicant;

(2) The name, title, and post office address, telephone and facsimile numbers of the person to whom correspondence in regard to the application shall be addressed;

(3) If a corporation, the state or territory under the laws of which the applicant was organized, and the town or city where applicant's principal office is located. If applicant is incorporated under the laws of, or authorized to operate in, more than one state, all pertinent facts should be stated. If applicant company is owned wholly or in part by any foreign government entity, or directly or indirectly subsidized by any foreign government entity; or, if applicant company has any agreement for such ownership or subsidization from any foreign government, provide full details of ownership and/or subsidies.

(b) Summary. A detailed summary of the proposal, including descriptions of the facilities utilized in the proposed export or import of natural gas; state, foreign, or other Federal governmental licenses or permits for the construction, operation, or modification of facilities in the United States, Canada, or Mexico; and the status of any state, foreign, or other Federal regulatory proceedings which are related to the proposal.

(c) Statements. (1) A statement demonstrating that the proposal or proposed construction is not inconsistent with the public interest, including, where applicable to the applicant's operations and proposal, a demonstration that the proposal:

(i) Will improve access to supplies of natural gas, serve new market demand, enhance the reliability, security, and/or flexibility of the applicant's pipeline system, improve the dependability of international energy trade, or enhance competition within the United States for natural gas transportation or supply;

(ii) Will not impair the ability of the applicant to render transportation service in the United States at reasonable rates to its existing customers; and,

(iii) Will not involve any existing contract(s) between the applicant and a foreign government or person concerning the control of operations or rates for the delivery or receipt of natural gas which may restrict or prevent other United States companies from extending their activities in the same general area, with copies of such contracts; and,

(2) A statement representing that the proposal will be used to render transportation services under parts 157 or 284 of this chapter, private transportation, or service that is exempt from the provisions of the Natural Gas Act pursuant to sections 1(b) or 1(c) thereof. The applicant providing transportation service under part 157 of this chapter must represent that the pipeline's proposed increase in capacity at an existing import/export point is not exclusively reserved for part 157 users and that all new service made available as a result of a new or modified import/export facility will be under part 284 of this chapter.

§ 153.8 Required exhibits.

(a) An application must include the following exhibits:

(1) Exhibit A. A certified copy of articles of incorporation, partnership or joint venture agreements, and by-laws of applicant; the amount and classes of capital stock; nationality of officers, directors, and stockholders, and the amount and class of stock held by each;

(2) Exhibit B. A detailed statement of the financial and corporate relationship existing between applicant and any other person or corporation;

(3) Exhibit C. A statement, including signed opinion of counsel, showing that the construction, operation, or modification of facilities for the export or the import of natural gas is within the authorized powers of applicant, that applicant has complied with laws and regulations of the state or states in which applicant operates;

(4) Exhibit D. If the proposal is for a pipeline interconnection to import or export natural gas, a copy of any construction and operation agreement between the applicant and the operator(s) of border facilities in the United States and Canada or Mexico;

(5) Exhibit E. If the proposal is to import or export LNG, evidence that an appropriate and qualified concern will properly and safely receive or deliver such LNG, including a report containing detailed engineering and design information. The Commission staff's “Guidance Manual for Environmental Report Preparation” may be obtained from the Commission's Office of Energy Projects, 888 First Street, NE., Washington, DC 20426;

(6) Exhibit F. An environmental report as specified in §§ 380.3 and 380.12 of this chapter. Applicant must submit all appropriate revisions to Exhibit F whenever route or site changes are filed. These revisions should identify the specific differences resulting from the route or site changes, and not just provide revised totals for the resources affected;

(7) Exhibit G. A geographical map of a suitable scale and detail showing the physical location of the facilities to be utilized for the applicant's proposed export or import operations The map should indicate with particularity the ownership of such facilities at or on each side of the border between the United States and Canada or Mexico, if applicable; and

(8) Exhibit H. A statement identifying each Federal authorization that the proposal will require; the Federal agency or officer, or State agency or officer acting pursuant to delegated Federal authority, that will issue each required authorization; the date each request for authorization was submitted; why any request was not submitted and the date submission is expected; and the date by which final action on each Federal authorization has been requested or is expected.

(b) The applicant may incorporate by reference any Exhibit required by paragraph (a) of this section already on file with the Commission.

[Order 595, 62 FR 30446, June 4, 1997, as amended by Order 603, 64 FR 26604, May 14, 1999; Order 687, 71 FR 62920, Oct. 27, 2006; Order 699, 72 FR 45325, Aug. 14, 2007; Order 900, 88 FR 74042, Oct. 30, 2023]

§ 153.9 Transferability.

(a) Non-transferable. Authorizations under subpart B of this part and section 3 of the Natural Gas Act and related facilities shall not be transferable or assignable without prior Commission authorization.

(b) Involuntary transfer. A Commission order granting such authorization shall continue in effect temporarily for a reasonable time in the event of the involuntary transfer of facilities used thereunder by operation of law (including such transfers to receivers, trustees, or purchasers under foreclosure or judicial sale) pending the making of an application for permanent authorization and decision thereon, provided notice is promptly given in writing to the Commission accompanied by a statement that the physical facts relating to operations of the facilities remain substantially the same as before the transfer and as stated in the initial application for such authorization.

§ 153.10 Authorization not exclusive.

No authorization granted pursuant to subpart B of this part and section 3 of the Natural Gas Act shall be deemed to prevent the Commission from granting authorization under subpart B to any other person at the same general location, or to prevent any other person from making application for such authorization.

§ 153.11 Supplemental orders.

The Commission also may make, at any time subsequent to the original order of authorization, after opportunity for hearing, such supplemental orders implementing its authority under section 3 of the Natural Gas Act as it may find necessary or appropriate.

§ 153.12 Pre-filing procedures for applications for authorization to site, construct, maintain, connect or modify facilities to be used for the export or import of natural gas.

The definitions in § 157.1 and the pre-filing procedures in § 157.21 of this chapter are applicable to applications under section 3 of the Natural Gas Act filed pursuant to subpart B of this part.

[Order 665, 70 FR 60440, Oct. 18, 2005]

§ 153.13 Emergency reconstruction.

The provisions of subpart F of part 157 of this chapter that permit reconstruction for the purpose of immediately restoring interrupted service for the protection of life or health or for maintenance of physical property in an emergency due to a sudden unanticipated loss of gas supply or capacity are applicable to facilities subject to section 3 of the Natural Gas Act.

[Order 633, 68 FR 31604, May 28, 2003]

§ 153.15 Who shall apply.

(a) Applicant. Any person proposing to construct, operate, maintain, or connect facilities at the borders of the United States and Canada or Mexico, for the export or import of natural gas to or from those countries, or to amend an existing Presidential Permit, shall file with the Commission an application for a Presidential Permit under subpart C of this part and Executive Order 10485, as amended by Executive Order 12038.

(b) Cross-reference. Any person applying under paragraph (a) of this section for a Presidential Permit for the construction and operation of border facilities must also simultaneously apply for authorization under subpart B of this part.

§ 153.16 Contents of application.

(a) Cross-reference. The submission of information under §§ 153.7 and 153.8 of subpart B of this part shall be deemed sufficient for purposes of applying for a Presidential Permit or an amendment to an existing Presidential Permit under subpart C of this part for the construction and operation of border facilities.

(b) Amendment not proposing construction. An applicant proposing to amend the article(s) of an existing Presidential Permit (other than facilities aspects) must file information pursuant to § 153.7(a) and a summary and justification of its proposal.

§ 153.17 Effectiveness of Presidential Permit.

A Presidential Permit, once issued by the Commission, shall not be effective until it has been accepted by the highest authority of the Permittee, as indicated by Permittee's execution of a Testimony of Acceptance, and a certified copy of the accepted Presidential Permit and the executed Testimony of Acceptance has been filed with the Commission.

§ 153.20 General rule.

(a) Filing procedures. Applications under Subparts B and C must be submitted to the Secretary of the Commission in accordance with filing procedures posted on the Commission's Web site at http://www.ferc.gov.

(b) Certification. All applications must be signed in compliance with § 385.2005 of this chapter.

(1) The signature on an application constitutes a certification that: The signer has read the filing signed and knows the contents of the paper copies; and, the signer possesses the full power and authority to sign the filing.

(2) An application must be signed by one of the following:

(i) The person on behalf of whom the application is made;

(ii) An officer, agent, or employee of the governmental authority, agency, or instrumentality on behalf of which the filing is made; or,

(iii) A representative qualified to practice before the Commission under § 385.2101 of this chapter who possesses authority to sign.

(c) Where to file. The paper copies and an accompanying transmittal letter must be submitted in one package to: Office of the Secretary, Federal Energy Regulatory Commission, Washington, DC 20426. This paragraph (c) shall cease to have effect on December 5, 2026, unless the Commission determines that the cessation deadline should be extended to a date not more than 5 years in the future after offering the public an opportunity to provide input on the costs and benefits of this paragraph (c) and considering that input. The Commission will publish a document in the Federal Register announcing its determination and revising or removing this paragraph (c) accordingly.

[Order 595, 62 FR 30446, June 4, 1997, as amended by Order 737, 75 FR 43404, July 26, 2010; Order 914, 90 FR 48403, Oct. 21, 2025]

§ 153.21 Conformity with requirements.

(a) General Rule. Applications under subparts B and C of this part must conform with the requirements of this part.

(b) Rejection of applications. If an application patently fails to comply with applicable statutory requirements or with applicable Commission rules, regulations, and orders for which a waiver has not been granted, the Director of the Office of Energy Projects may reject the application within 10 days of filing as provided by § 385.2001(b) of this chapter. This rejection is without prejudice to an applicant's refiling a complete application. However, an application will not be rejected solely on the basis of: Environmental reports that are incomplete because the company has not been granted access by the affected landowner(s) to perform required surveys, or environmental reports that are incomplete, but where the minimum checklist requirements of part 380, appendix A of this chapter have been met. An application that relates to an operation, service, or construction concerning which a prior application has been filed and rejected, shall be docketed as a new application. Such new application shall state the docket number of the prior rejected application.

[Order 595, 62 FR 30446, June 4, 1997, as amended by Order 603, 64 FR 26604, May 14, 1999; Order 699, 72 FR 45325, Aug. 14, 2007]

§ 153.22 Amendments and withdrawals.

Amendments to or withdrawals of applications must conform to the requirements of §§ 385.215 and 385.216 of this chapter.

§ 153.23 Reporting requirements.

Each person authorized under this part 153 that is not otherwise required to file information concerning the start of construction or modification of import/export facilities, the completion of construction or modification, and the commencement of service must file such information with the Commission within 10 days after such event. Each person, other than entities without pipeline capacity, must also report by March 1 of each year the estimated peak day capacity and actual peak day usage of its import/export facilities.

§ 154.1 Application; Obligation to file.

(a) The provisions of this part apply to filings pursuant to section 4 of the Natural Gas Act.

(b) Every natural gas company must file with the Commission and post in conformity with the requirements of this part, schedules showing all rates and charges for any transportation or sale of natural gas subject to the jurisdiction of the Commission, and the classifications, practices, rules, and regulations affecting such rates, charges, and services, together with all contracts related thereto.

(c) No natural gas company may file, under this part, any new or changed rate schedule or contract for the performance of any service for which a certificate of public convenience and necessity or certificate amendment must be obtained pursuant to section 7(c) of the Natural Gas Act, until such certificate has been issued.

(d) For the purposes of paragraph (b) of this section, any contract that conforms to the form of service agreement that is part of the pipeline's tariff pursuant to § 154.110 does not have to be filed. Any contract or executed service agreement which deviates in any material aspect from the form of service agreement in the tariff is subject to the filing requirements of this part.

§ 154.2 Definitions.

(a) Contract means any agreement which in any manner affects or relates to rates, charges, classifications, practices, rules, regulations, or services for any transportation or sale of natural gas subject to the jurisdiction of the Commission. This term includes an executed service agreement.

(b) FERC Gas Tariff or tariff means a compilation, on electronic media, of all of the effective rate schedules of a particular natural gas company, and a copy of each form of service agreement.

(c) Form of service agreement means an unexecuted agreement for service included as an example in the tariff.

(d) Post means: to make a copy of a natural gas company's tariff and contracts available during regular business hours for public inspection in a convenient form and place at the natural gas company's offices where business is conducted with affected customers; and, to serve each affected customer and interested state Commission in accordance with § 154.208 of this Part.

(e) Rate schedule means a statement of a rate or charge for a particular classification of transportation or sale of natural gas subject to the jurisdiction of the Commission, and all terms, conditions, classifications, practices, rules, and regulations affecting such rate or charge.

(f) Filing date means the day on which a tariff, or part thereof, or a contract is received in the Office of the Secretary of the Commission for filing in compliance with the requirements of this part.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 714, 73 FR 57533, Oct. 3, 2008]

§ 154.3 Effective tariff.

(a) The effective tariff of a natural gas company is the tariff filed pursuant to the requirements of this part, and permitted by the Commission to become effective. A natural gas company must not directly or indirectly, demand, charge, or collect any rate or charge for, or in connection with, the transportation or sale of natural gas subject to the jurisdiction of the Commission, or impose any classifications, practices, rules, or regulations, different from those prescribed in its effective tariff and executed service agreements on file with the Commission, unless otherwise specifically permitted by order of the Commission.

(b) No tariff provision may purport to change an effective rate or charge except in the manner provided in section 4 of the Natural Gas Act, and the regulations in this part. The tariff may not provide for any rate or charge to be automatically changed by an index or other periodic adjustment, without filing for a rate change pursuant to these regulations.

§ 154.4 Electronic filing of tariffs and related materials.

(a) General rule. All filings made in proceedings initiated under this part must be made electronically, including tariffs, rate schedules, service agreements, and contracts, or parts thereof, and material that relates to or bears upon such documents, such as cancellations, amendments, withdrawals, termination, or adoption of tariffs, and motions relating to suspension.

(b) Requirement for signature. All filings must be signed in compliance with the following:

(1) The signature on a filing constitutes a certification that the contents are true to the best knowledge and belief of the signer, and that the signer possesses full power and authority to sign the filing.

(2) A filing must be signed by one of the following:

(i) The person on behalf of whom the filing is made;

(ii) An officer, agent, or employee of the company, governmental authority, agency, or instrumentality on behalf of which the filing is made; or,

(iii) A representative qualified to practice before the Commission under § 385.2101 of this chapter who possesses authority to sign.

(3) All signatures on the filing or any document included in the filing must comply, where applicable, with the requirements in § 385.2005 of this chapter with respect to sworn declarations or statements and electronic signatures.

(c) Format requirements for electronic filing. The requirements and formats for electronic filing are listed in instructions for electronic filing and for each form. These formats are available through the Commission's website, https://www.ferc.gov.

(d) Only filings filed and designated as filings with statutory action dates in accordance with these electronic filing requirements and formats will be considered to have statutory action dates. Filings not properly filed and designated as having statutory action dates will not become effective, pursuant to the Natural Gas Act, should the Commission not act by the requested action date.

[Order 714, 73 FR 57533, Oct. 3, 2008, as amended by Order 714-A, 79 FR 29076, May 21, 2014; Order 899, 88 FR 74030, Oct. 30, 2023]

§ 154.5 Rejection of filings.

A filing that fails to comply with this part may be rejected by the Director of the Office of Energy Market Regulation pursuant to the authority delegated to the Director in Part 375 of this chapter.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 699, 72 FR 45325, Aug. 14, 2007; Order 701, 72 FR 61054, Oct. 29, 2007; Order 714, 73 FR 57534, Oct. 3, 2008]

§ 154.6 Acceptance for filing not approval.

The acceptance for filing of any tariff, contract or part thereof does not constitute approval by the Commission. Any filing which does not comply with any applicable statute, rule, or order, may be rejected.

§ 154.7 General requirements for the submission of a tariff filing or executed service agreement.

The following must be included with the filing of any tariff, executed service agreement, or part thereof, or change thereto.

(a) A letter of transmittal containing:

(1) A list of the material enclosed,

(2) The name of a responsible company official to whom questions regarding the filing may be addressed, with a telephone number at which the official may be reached,

(3) The date on which such filing is proposed to become effective,

(4) Reference to the authority under which the filing is made, including the specific section of a statute, subpart of these regulations, order of the Commission, provision of the company's tariff, or any other appropriate authority. If an order is referenced, the letter must include the citation to the FERC Reports, the date of issuance, and the lead docket number of the proceeding in which the order was issued.

(5) A list of the tariff sheets or sections enclosed,

(6) A statement of the nature, the reasons, and the basis for the filing. The statement must include a summary of the changes or additions made to the tariff or executed service agreement, as appropriate. The statement must include a quantified summary comparing the cost of service, rate base and throughput underlying each change in rate made to the tariff or executed service agreement compared to the same information underlying the last rate found by the Commission to be just and reasonable. A detailed explanation of the need for each change or addition to the tariff or executed service agreement must be included. The natural gas company also must note all relevant precedents relied upon to prepare its filing.

(7) Any requests for waiver. A request for waiver must include a reference to the specific section of the statute, regulations, or the company's tariff from which waiver is sought, and a justification for the waiver.

(8) Where the natural gas company proposes a new rate, identification of the last rate, found by the Commission to be just and reasonable, that underlies the proposed rate.

(9) A motion, in case of minimal suspension, to place the proposed rates into effect at the end of the suspension period; or, a specific statement that the pipeline reserves its right to file a later motion to place the proposed rates into effect at the end of the suspension period.

(b) A certification of service to all customers and state commissions pursuant to § 154.2(d).

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 582-A, 61 FR 9628, Mar. 11, 1996; Order 714, 73 FR 57534, 57535, Oct. 3, 2008]

§ 154.8 Informal submission for staff suggestions.

Any natural gas company may informally submit a proposed tariff or any part thereof or material relating thereto for the suggestions of the Commission staff prior to filing. Opinions of the Commission staff are not binding upon the Commission.

§ 154.101 [Reserved]

§ 154.102 Requirements for filing rate schedules and tariffs.

(a) All rates schedules, tariffs, and service agreements may be filed either by dividing the rate schedule, tariff, or agreement into individual tariff sheets, or tariff sections, or as an entire document except as provided in paragraph (b) of this section.

(b) Open access transportation tariffs must be filed either as individual sheets or sections. If filed as sections, each section must include only material of related subject matter and must be of reasonable length and must include at a minimum a section for each item listed in the table of contents under § 154.103 of this section and each topic listed under General Terms and Conditions of Service.

(c) Individual negotiated rate agreements, non-conforming service agreements, or other agreements that are included in the tariff may be filed as entire documents.

(d) The first section or sheet of the tariff must include:

(1) The FERC Gas Tariff Volume Number and Name of the Natural Gas Company, for example

FERC Gas Tariff Volume No. [ ] of [Name of Natural Gas Company]

(2) The name, title, address, telephone number, e-mail address and facsimile number of a person to whom communications concerning the tariff should be sent.

[Order 714, 73 FR 57534, Oct. 3, 2008]

§ 154.103 Composition of tariff.

(a) The tariff must contain sections, in the following order: A table of contents, a preliminary statement, a uniform resource locator for the Internet address of a map of the system, currently effective rates, composition of rate schedules, general terms and conditions, form of service agreement, and an index of customers.

(b) Rate schedules must be grouped according to class and numbered serially within each group, using letters before the serial number to indicate the class of service. For example: FT-1, FT-2 may be used for firm transportation service; IT-1, IT-2 may be used for interruptible transportation service; X-1, X-2 may be used for schedules for which special exception has been obtained.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 801, 79 FR 75050, Dec. 17, 2014]

§ 154.104 Table of contents.

The table of contents must contain a list of the rate schedules, sections of the general terms and conditions, and other sections in the order in which they appear, showing the sheet number of the first page of each section or the section number. The list of rate schedules must consist of: The alphanumeric designation of each rate schedule, a very brief description of the service, and the sheet number of the first page of each rate schedule or the section number.

[Order 714, 73 FR 57534, Oct. 3, 2008]

§ 154.105 Preliminary statement.

The preliminary statement must contain a brief general description of the company's operations and may also contain a general explanation of its policies and practices. General rules and regulations, and any material necessary for the interpretation or application of the rate schedules, may not be included in the preliminary statement.

§ 154.106 Map.

(a) The tariff must state a uniform resource locator on the pipeline's Internet Web site, at which the general public may display and download system map(s).

(b) The map must show the general geographic location of the company's principal pipeline facilities and of the points at which service is rendered under the tariff. The boundaries of any rate zones or rate areas must be shown and the areas or zones identified. The entire system should be displayed on a single map. In addition, a separate map should be provided for each zone.

(c) The map must be revised to reflect any major change no later than the end of the calendar quarter that immediately follows the calendar quarter in which the major change occurred.

[Order 801, 79 FR 75050, Dec. 17, 2014]

§ 154.107 Currently effective rates.

(a) This section of the tariff must present the currently effective rates and charges under each rate schedule.

(b) All rates must be stated clearly in cents or dollars and cents per thermal unit. The unit of measure must be stated for each component of a rate.

(c) A rate having more than one part must have each component set out separately under appropriate headings (e.g., “Reservation Charge,” “Usage Charge.”)

(d) Where a component of a rate is adjusted pursuant to a mechanism approved under subpart E of this part, the adjustment must be stated in a separate column on the rate sheet or section.

(e) Exception to paragraph (d) of this section. Where the rate component is an Annual Charge Adjustment surcharge approved by the Commission, the adjustment or surcharge may be stated in a footnote on the rate sheet or section.

(f) A total rate, indicating the sum of the rate components under paragraph (c) of this section plus the adjustments under paragraph (d) of this section, must be shown in the last column at the end of a line for a rate, so that a reader can readily determine the separate components comprising the total rate for a service.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 714, 73 FR 57534, Oct. 3, 2008]

§ 154.108 Composition of rate schedules.

The rate schedule must contain a statement of the rate or charge and all terms and conditions governing its application, arranged as follows:

(a) Title. Each rate schedule must have a title consisting of a designation of the type or classification of service (see § 154.103(b)), and a statement of the type or classification of service to which the rate is applicable.

(b) Availability. This paragraph must describe the conditions under which the rate is offered, including any geographic zone limitations.

(c) Applicability and character of service. This paragraph must fully describe the kind or classification of service to be rendered.

(d) Summary of rates. This paragraph must briefly set forth all components of the rates, refer to the location of the rates in the Currently Effective Rates, and provide a description of the calculation of the monthly charges for each rate component.

(e) Other provisions. All other major provisions governing the application of the rate schedule, such as determination of billing demand, contract demand, heat content, and measurement base, must be set forth with appropriate headings or incorporated by reference to the applicable general terms and conditions.

(f) Applicable terms and conditions. This paragraph either states that all of the general terms and conditions set forth in the tariff apply to the rate schedule, or specifies which of the general terms and conditions do not apply.

§ 154.109 General terms and conditions.

(a) This section of the tariff contains terms and conditions of service applicable to all or any of the rate schedules. Subsections and paragraphs must be numbered for convenient reference.

(b) The general terms and conditions of the tariff must contain a statement of the company's policy with respect to the financing or construction of laterals including when the pipeline will pay for or contribute to the construction cost. The term “lateral” means any pipeline extension (other than a mainline extension) built from an existing pipeline facility to deliver gas to one or more customers, including new delivery points and enlargements or replacements of existing laterals.

(c) The general terms and conditions of the tariff must contain a statement of the order in which the company discounts its rates and charges. The statement, specifying the order in which each rate component will be discounted, must be in accordance with Commission policy.

§ 154.110 Form of service agreement.

The tariff must contain an unexecuted pro forma copy of each form of service agreement. The form for each service must refer to the service to be rendered and the applicable rate schedule of the tariff; and, provide spaces for insertion of the name of the customer, effective date, expiration date, and term. Spaces may be provided for the insertion of receipt and delivery points, contract quantity, and other specifics of each transaction as appropriate.

§ 154.111 Index of customers.

(a) If a pipeline is in compliance with the reporting requirements of § 284.13(c) of this chapter, then an index of customers need not be provided in the tariff.

(b) If all of a pipeline's jurisdictional transportation and sales are pursuant to part 157 of this chapter, then an index of customers must be provided that contains: a list of the pipeline's firm transportation, storage, and sales customers, and the rate schedule number for the services for which the shippers are contracting; the effective date of the contract; the expiration date of the contract; if the service is transportation or sales, the maximum daily contract demand under the contract; and, if the service is storage, the maximum storage quantity. Specify units of measurement when reporting contract quantities.

(c) The index of customers must be kept current by filing new or revised sheets or sections, semi-annually. One filing must coincide with the filing of the natural gas company's FERC Form No. 2 or 2-A with a proposed effective date of June 1. The other filing must be made six months later with a proposed effective date of December 1. The Index of Customers must contain a list of the contracts in effect as of the filing date.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 637, 65 FR 10219, Feb. 25, 2000; Order 714, 73 FR 57535, Oct. 3, 2008]

§ 154.112 Exception to form and composition of tariff.

(a) The Commission may permit a special rate schedule to be filed in the form of an agreement in the case of a special operating arrangement, previously certificated pursuant to part 157 of this chapter, such as for the exchange of natural gas. The special rate schedule must contain a title page showing the parties to the agreement, the date of the agreement, a brief description of services to be rendered, and the designation: “Rate Schedule X-[number].” Special rate schedules may not contain any supplements. Modifications must be made by inserting revised sheets, sections or the entire document as appropriate. Special rate schedules must be included in a separate volume of the tariff. Each such separate volume must contain a table of contents which is incorporated as a sheet or section in the open access transmission tariff.

(b) Contracts for service pursuant to part 284 of this chapter that deviate in any material aspect from the form of service agreement must be filed. Such non-conforming agreements must be referenced in the open access transmission tariff.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 714, 73 FR 57534, Oct. 3, 2008; 81 FR 51100, Aug. 3, 2016]

§ 154.201 Filing requirements.

In addition to the requirements of subparts A and B of this part, the following must be included with the filing of any tariff, executed service agreement, or part thereof, that changes or supersedes any tariff, contract, or part thereof, on file with the Commission.

(a) A list in the transmittal letter of the tariff sheets or sections being revised and a marked version of the sheets or sections to be changed or superseded showing additions and deletions. New numbers and text must be marked by either highlight, background shading, bold, or underline. Deleted text and numbers must be indicated by strike-through. Only those revisions appropriately designated and marked constitute the filing. Revisions to unmarked portions of the rate schedule or tariff are not considered part of the filing nor will any acceptance of the filing by the Commission constitute acceptance of such unmarked changes.

(b) Documentation whether in the form of workpapers, or otherwise, sufficiently detailed to support the company's proposed change.

(1) The documentation must include but is not limited to the schedules, workpapers, and supporting documentation required by these rules and regulations and the Commission's orders.

(2) All rate changes in the filing must be supported by step-by-step mathematical calculations and sufficient written narrative to allow the Commission and interested parties to duplicate the company's calculations.

(3) Any data or summaries included in the filing purporting to reflect the books of account must be supported by accounting workpapers setting forth all necessary particulars from which an auditor may readily verify that such data are in agreement with the company's books of account. All statements, schedules, and workpapers must be prepared in accordance with the classifications of the Commission's Uniform System of Accounts. Workpapers in support of all adjustments, computations, and other information, properly indexed and cross-referenced to the filing and other workpapers, must be available for Commission examination.

(4) Where a rate, cost, or volume is derived from another rate, cost, or volume, the derivation must be shown mathematically and be accompanied by a written narrative sufficient to allow the Commission and interested parties to duplicate the calculations. If the derivation is due to a load factor adjustment, application of a percentage, or other adjusting factor, the pipeline must also note or explain the origin of the adjusting factor.

(5) Where workpapers show progressive calculations, any discontinuity between one working paper and another must be explained.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 714, 73 FR 57534, Oct. 3, 2008]

§ 154.202 Filings to initiate a new rate schedule.

(a) When the filing is to initiate a new service authorized under a blanket authority in part 284 of this chapter, the filing must comply with the requirements of this paragraph.

(1) Filings under this paragraph must:

(i) Adhere to the requirements of subparts A, B, and C of this part;

(ii) Contain a description of the new service, including, but not limited to, the proposed effective date for commencement of service, applicability, whether the service is interruptible or firm, and the necessity for the service;

(iii) Explain how the new service will differ from existing services, including a concise description of the natural gas company's existing operations;

(iv) Explain the impact of the new service on existing firm and interruptible customers, including but not limited to:

(A) The adequacy of existing capacity, if the proposed service is a firm service, and

(B) The effect on receipt and delivery point flexibility, nominating and scheduling priorities, allocation of capacity, operating conditions, and curtailment, for any new service;

(v) Include workpapers that detail the computations underlying the proposed rate under the new rate schedule; or, if the rate is a currently effective rate, include the appropriate reference and an explanation of why the rate is appropriate;

(vi) Give a justification, similar in form to filed testimony in a general section 4 rate case, explaining why the proposed rate design and proposed allocation of costs are just and reasonable;

(vii) If the costs relating to existing services are reallocated to new services, explain the method for allocating the costs and the impact on the existing customers;

(viii) Include workpapers showing the estimated effect on revenue and costs over the twelve-month period commencing on the proposed effective date of the filing.

(ix) List other filings pending before the Commission at the time of the filing which may significantly affect the filing. Explain how the instant filing would be affected by the outcome of each related pending filing;

(2) Any interdependent filings must be filed concurrently and contain a notice of the interdependence.

(b) If a new service, facility, or rate is specifically authorized by a Commission order pursuant to section 7 of the Natural Gas Act, with the filing of tariff sheets or sections to implement the new rate schedule, the natural gas company must:

(1) Comply with the requirements of § 154.203; and

(2) Where the rate or charge proposed differs from the rate or charge approved in the certificate order, the natural gas company must: Show that the change is due to a rate adjustment under a periodic rate change mechanism previously accepted under § 154.403 which has taken effect since the certificate order was issued; or, show that the rate change is in accordance with the terms of the certificate, and provide workpapers justifying the change.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 714, 73 FR 57535, Oct. 3, 2008]

§ 154.203 Compliance filings.

(a) In addition to the requirements of subparts A, B, and C of this part, filings made to comply with orders issued by the Commission, including those issued under delegated authority, must contain the following:

(1) A list of the directives with which the company is complying;

(2) Revised workpapers, data, or summaries with cross-references to the originally filed workpapers, data, or summaries;

(b) Filings made to comply with Commission orders must include only those changes required to comply with the order. Such compliance filings may not be combined with other rate or tariff change filings. A compliance filing that includes other changes or that does not comply with the applicable order in every respect may be rejected.

§ 154.204 Changes in rate schedules, forms of service agreements, or the general terms and conditions.

A filing to revise rate schedules, forms of service agreements, or the general terms and conditions, must:

(a) Adhere to the requirements of subparts A, B, and C, of this part;

(b) Contain a description of the change in service, including, but not limited to, applicability, necessity for the change, identification of services and types of customers that will be affected by the change;

(c) Explain how the proposed tariff provisions differ from those currently in effect, including an example showing how the existing and proposed tariff provisions operate. Explain why the change is being proposed at this time;

(d) Explain the impact of the proposed revision on firm and interruptible customers, including any changes in a customer's rights to capacity in the manner in which a customer is able to use such capacity, receipt or delivery point flexibility, nominating and scheduling, curtailment, capacity release;

(e) Include workpapers showing the estimated effect on revenues and costs over the 12-month period commencing on the proposed effective date of the filing. If the filing proposes to change an existing penalty provision, provide workpapers showing the penalty revenues and associated quantities under the existing penalty provision during the latest 12-month period; and

(f) List other filings pending before the Commission which may significantly affect the filing.

§ 154.205 Withdrawals and amendments of tariff filings and executed service agreements.

(a) Withdrawals of tariff filings or service agreements prior to Commission action. (1) A natural gas company may withdraw in its entirety a tariff filing or executed service agreement that has not become effective and upon which no Commission or delegated order has been issued by filing a withdrawal motion with the Commission. Upon the filing of such motion, the proposed tariff sheets, sections or service agreements will not become effective under section 4(d) of the Natural Gas Act in the absence of Commission action making the rate schedule or tariff filing effective.

(2) The withdrawal motion will become effective, and the rate schedule or tariff filing will be deemed withdrawn, at the end of 15 days from the date of filing of the withdrawal motion, if no answer in opposition to the withdrawal motion is filed within that period and if no order disallowing the withdrawal is issued within that period. If an answer in opposition is filed within the 15 day period, the withdrawal is not effective until an order accepting the withdrawal is issued.

(b) Amendments or modifications to tariff sheets, sections or service agreements prior to Commission action on a tariff filing. A natural gas company may file to amend or modify a tariff or service agreement contained in a tariff filing upon which no Commission or delegated order has yet been issued. Such filing will toll the notice period in section 4(d) of the Natural Gas Act for the original filing, and establish a new date on which the entire filing will become effective, in the absence of Commission action, no earlier than 31 days from the date of the filing of the amendment or modification.

(c) Withdrawal of suspended tariffs, executed service agreements, or parts thereof. A natural gas company may not, within the period of suspension, withdraw a proposed tariff, executed service agreement, or part thereof, that has been suspended by order of the Commission, except by special permission of the Commission granted upon application therefor and for good cause shown.

(d) Changes in suspended tariffs, executed service agreements, or parts thereof. A natural gas company may not, within the period of suspension, file any change in a proposed tariff, executed service agreement, or part thereof, that has been suspended by order of the Commission, except by special permission of the Commission granted upon application therefor and for good cause shown.

(e) Changes in tariffs, executed service agreements, or parts thereof continued in effect, and which were to be changed by the suspended filing. A natural gas company may not, within the period of suspension, file any change in a tariff, executed service agreement, or part thereof, that is continued in effect by operation of the order of suspension, and that was proposed to be changed by the suspended filing, except:

(1) Under a previously approved tariff provision permitting a limited rate change, or

(2) By special permission of the Commission.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 714, 73 FR 57534, Oct. 3, 2008]

§ 154.206 Motion to place suspended rates into effect.

(a) If, prior to the end of the suspension period, the Commission has issued an order requiring changes in the filed rates, or the filed rates recover costs for facilities not certificated and in service as of the proposed effective date, in order to place the suspended rates into effect, the pipeline must file a motion at least one day prior to the effective date requested by the pipeline. The motion must be accompanied by revised tariff sheets or sections reflecting any changes ordered by the Commission or modifications approved by the Commission during the suspension period under § 154.205. The filing of the revised tariff sheets or sections must:

(1) Comply with the requirements of subparts A, B, and C of this part;

(2) Identify the Commission order directing the revision;

(3) List the modifications made to the currently effective rate during the suspension period, the docket number in which the modifications were filed, and identify the order permitting the modifications.

(b) Where the Commission has suspended the effective date of a change of rate, charge, classification, or service for a minimal period and the pipeline has not included a motion in its transmittal letter, or has specified in its transmittal letter pursuant to § 154.7(a)(9), that it reserves its right to file motion to place the proposed change of rate, charge, classification, or service into effect at the end of the suspension period, the change will go into effect, subject to refund, upon motion of the pipeline.

(c) Where the Commission has suspended the effective date of a change of rate, charge, classification, or service for a minimal period and the pipeline has included, in its transmittal letter pursuant to § 154.7(a)(9), a motion to place the proposed change of rate, charge, classification, or service into effect at the end of the suspension period, the change will go into effect, subject to refund, on the authorized effective date.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 714, 73 FR 57535, Oct. 3, 2008]

§ 154.207 Notice requirements.

All proposed changes in tariffs, contracts, or any parts thereof must be filed with the Commission and posted not less than 30 days nor more than 60 days prior to the proposed effective date thereof, unless a waiver of the time periods is granted by the Commission.

§ 154.208 Service of tariff filings on customers and other parties.

(a) On or before the filing date, the company must serve, upon all customers as of the date of the filing and all affected state regulatory commissions, an abbreviated form of the filing consisting of: The Letter of Transmittal; the Statement of Nature, Reason, and Basis; the changed tariff sheets or sections; a summary of the cost-of-service and rate base; and, summary of the magnitude of the change.

(b) On or before the filing date, the company must serve a full copy of the filing upon all customers and state regulatory commissions that have made a standing request for such service.

(c) Within two business days of receiving a request for a complete copy from any customer or state commission that has not made a standing request, the company must serve a full copy of any filing.

(d) A customer or other party may designate a recipient of service. The filing company must serve the designated recipient, in accordance with this section, instead of the customer or other party. For the purposes of this section, service upon the designated recipient will be deemed service upon the customer or other party.

(e) The company may choose to effect service either electronically or by paper. Such service must be made in accordance with the requirements of Part 385 of this chapter.

(f) Unless it seeks a waiver of electronic service, each customer or party entitled to service of initial tariff filings under this section must notify the company of the e-mail address to which service should be directed. A customer or party may seek a waiver of electronic service by filing a waiver request under Part 390 of this chapter, providing good cause for its inability to accept electronic service.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 582A, 61 FR 9628, Mar. 11, 1996; Order 714, 73 FR 57535, Oct. 3, 2008]

§ 154.209 [Reserved]

§ 154.210 Protests, interventions, and comments.

(a) Unless the notice issued by the Commission provides otherwise, any protest, intervention or comment to a tariff filing made pursuant to this part must be filed in accordance with § 385.211 of this chapter, not later than 12 days after the subject tariff filing. A protest must state the basis for the objection. A protest will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make the protestant a party to the proceeding. A person wishing to become a party to the proceeding must file a motion to intervene.

(b) Any motion to intervene must be filed not later than 12 days after the subject tariff filing in accordance with § 385.214 of this chapter.

§ 154.301 Changes in rates.

(a) Except for changes in rates pursuant to subparts E, F and G, of this part, any natural gas company filing for a change in rates or charges, except for a minor rate change, must submit, in addition to the material required by subparts A, B, and C of this part, the Statements and Schedules described in § 154.312.

(b) A natural gas company filing for a minor rate change must file the Statements and Schedules described in § 154.313.

(c) A natural gas company filing for a change in rates or charges must be prepared to go forward at a hearing and sustain, solely on the material submitted with its filing, the burden of proving that the proposed changes are just and reasonable. The filing and supporting workpapers must be of such composition, scope, and format as to comprise the company's complete case-in-chief in the event that the change is suspended and the matter is set for hearing. If the change in rates or charges presented are not in full accord with any prior Commission decision directly involving the filing company, the company must include in its working papers alternate material reflecting the effect of such prior decision.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 582-A, 61 FR 9628, Mar. 11, 1996]

§ 154.302 Previously submitted material.

(a) If all, or any portion, of the information called for by this part has already been submitted to the Commission within six months of the filing date of this application, or is included in other data filed pursuant to this part, specific reference thereto may be made in lieu of resubmission.

(b) If a new FERC Form No. 2 or 2-A is required to be filed within 60 days from the end of the base period, the new FERC Form No. 2 or 2-A must be filed concurrently with the rate change filing. There must be furnished to the Director, Office of Energy Market Regulation, with the rate change filing, one copy of the FERC Form No. 2 or 2-A.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 699, 72 FR 45325, Aug. 14, 2007; Order 701, 72 FR 61054, Oct. 29, 2007]

§ 154.303 Test periods.

Statements A through M, O, P, and supporting schedules, in § 154.312 and § 154.313, must be based upon a test period.

(a) If the natural gas company has been in operation for 12 months on the filing date, then the test period consists of a base period followed by an adjustment period.

(1) The base period consists of 12 consecutive months of the most recently available actual experience. The last day of the base period may not be more than 4 months prior to the filing date.

(2) The adjustment period is a period of up to 9 months immediately following the base period.

(3) The test period may not extend more than 9 months beyond the filing date.

(4) The rate factors (volumes, costs, and billing determinants) established during the base period may be adjusted for changes in revenues and costs which are known and measurable with reasonable accuracy at the time of the filing and which will become effective within the adjustment period. The base period factors must be adjusted to eliminate nonrecurring items. The company may adjust its base period factors to normalize items eliminated as nonrecurring.

(b) If the natural gas company has not been in operation for 12 months on the filing date, then the test period must consist of 12 consecutive months ending not more than one year after the filing date. Rate factors may be adjusted as in paragraph (a)(4) of this section but must not be adjusted for occurrences anticipated after the 12-month period.

(c)(1) Adjustments to base period experience, or to estimates where 12 months' experience is not available, may include the costs for facilities for which either a permanent or temporary certificate has been granted, provided such facilities will be in service within the test period; or a certificate application is pending. The filing must identify facilities, related costs and the docket number of each such outstanding certificate. Subject to paragraph (c)(2) of this section, adjustments to base period experience, or to estimates where 12 months' experience is not available, may include any amounts for facilities that require a certificate of public convenience and necessity, where a certificate has not been issued by the filing date but is expected to be issued before the end of the test period. Adjustments to base period may include costs for facilities that do not require a certificate and are in service by the end of the test period.

(2) When a pipeline files a motion to place the rates into effect, the filing must be revised to exclude the costs associated with any facilities that will not be in service as of the end of the test period, or for which certificate authorization is required but will not be granted as of the end of the test period. At the end of the test period, the pipeline must remove from its rates costs associated with any facility that is not in service or for which certificate authority is required but has not been granted.

(d) The Commission may allow reasonable deviation from the prescribed test period.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 582-A, 61 FR 9629, Mar. 11, 1996]

§ 154.304 Format of statements, schedules, workpapers and supporting data.

(a) All statements, schedules, and workpapers must be prepared in accordance with the Commission's Uniform System of Accounts.

(b) The data in support of the proposed rate change must include the required particulars of book data, adjustments, and other computations and information on which the company relies, including a detailed narrative explanation placed at the beginning of the specific statement or schedule to which they apply, explaining each proposed adjustment to base period actual volumes and costs.

(c) Book data included in statements and schedules required to be prepared or submitted as part of the filing must be reported in a separate column or columns. All adjustments to book data must also be reported in a separate column or columns so that book amounts, adjustments thereto, and adjusted amounts will be clearly disclosed. All adjustments must be supported by a narrative explanation placed at the beginning of the specific statement or schedule to which they apply.

(d) Certain of the statements and schedules of § 154.313 are workpapers. Any data or summaries reflecting the books of account must be supported by accounting workpapers setting forth all necessary particulars from which an auditor may readily identify the book data included in the filing and verify that such data are in agreement with the company's books of account.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 582-A, 61 FR 9629, Mar. 11, 1996]

§ 154.305 Tax normalization.

(a) Applicability. An interstate pipeline must compute the income tax component of its cost-of-service by using tax normalization for all transactions.

(b) Definitions. (1) Tax normalization means computing the income tax component as if transactions recognized in each period for ratemaking purposes are also recognized in the same amount and in the same period for income tax purposes.

(2) Commission-approved ratemaking method means a ratemaking method approved by the Commission in a final decision. This includes a ratemaking method that is part of an approved settlement or arbitration providing that the ratemaking method is to be effective beyond the term of the settlement or arbitration.

(3) Income tax purposes means for the purpose of computing actual income tax under the provisions of the Internal Revenue Code or the income tax provisions of the laws of a State or political subdivision of a State (including franchise taxes).

(4) Income tax component means that part of the cost-of-service that covers income tax expenses allowable by the Commission.

(5) Ratemaking purposes means for the purpose of fixing, modifying, accepting, approving, disapproving, or rejecting rates under the Natural Gas Act.

(6) Tax effect means the tax reduction or addition associated with a specific expense or revenue transaction.

(7) Transaction means an activity or event that gives rise to an accounting entry.

(c) Reduction of, and addition to, Rate Base. (1) The rate base of an interstate pipeline using tax normalization under this section must be reduced by the balances that are properly recordable in Account 281, “Accumulated deferred income taxes-accelerated amortization property”; Account 282, “Accumulated deferred income taxes—other property”: and Account 283, “Accumulated deferred income taxes—other.” Balances that are properly recordable in Account 190, “Accumulated deferred income taxes,” must be treated as an addition to rate base. Include, as an addition or reduction, as appropriate, amounts in Account 182.3, Other regulatory assets, and Account 254, Other regulatory liabilities, that result from a deficiency or excess in the deferred tax accounts (see paragraph (d) of this section) and which have been, or are soon expected to be, authorized for recovery or refund through rates.

(2) Such rate base reductions or additions must be limited to deferred taxes related to rate base, construction, or other costs and revenues affecting jurisdictional cost-of-service.

(d) Special rules. (1) This paragraph applies:

(i) If the rate applicant has not provided deferred taxes in the same amount that would have accrued had tax normalization always been applied; or

(ii) If, as a result of changes in tax rates, the accumulated provision for deferred taxes becomes deficient in, or in excess of, amounts necessary to meet future tax liabilities.

(2) The interstate pipeline must compute the income tax component in its cost-of-service by making provision for any excess or deficiency in deferred taxes.

(3) The interstate pipeline must apply a Commission-approved ratemaking method made specifically applicable to the interstate pipeline for determining the cost-of-service provision described in paragraph (d)(2) of this section. If no Commission-approved ratemaking method has been made specifically applicable to the interstate pipeline, then the interstate pipeline must use some ratemaking method for making such provision, and the appropriateness of such method will be subject to case-by-case determination.

(4) An interstate pipeline must continue to include, as an addition or reduction to rate base, any deficiency or excess attributable to prior flow-through or changes in tax rates (paragraphs (d)(1)(i) and (d)(1)(ii) of this section), until such deficiency or excess is fully amortized in accordance with a Commission approved ratemaking method.

§ 154.306 Cash working capital.

A natural gas company that files a tariff change under this part may not receive a cash working capital adjustment to its rate base unless the company or other participant in a rate proceeding under this part demonstrates, with a fully developed and reliable lead-lag study, a net revenue receipt lag or a net expense payment lag (revenue lead). Any demonstrated net revenue receipt lag will be credited to rate base; and, any demonstrated net expense payment lag will be deducted from rate base.

§ 154.307 Joint facilities.

The Statements required by § 154.312 must show all costs (investment, operation, maintenance, depreciation, taxes) that have been allocated to the natural gas operations involved in the subject rate change and are associated with joint facilities. The methods used in making such allocations must be provided.

§ 154.308 Representation of chief accounting officer.

The filing must include a statement executed by the chief accounting officer or other authorized accounting representative of the filing company representing that the cost statements, supporting data, and workpapers, that purport to reflect the books of the company do, in fact, set forth the results shown by such books.

§ 154.309 Incremental expansions.

(a) For every expansion for which incremental rates are charged, the company must provide a summary with applicable cross-references to § 154.312 and § 154.313, of the costs and revenues associated with the expansion, until the Commission authorizes the costs of the incremental facilities to be rolled-in to the pipeline's rates. For every expansion that has an at-risk provision in the certificate authorization, the costs and revenues associated with the facility must be shown in summary format with applicable cross-references to § 154.312 and § 154.313, until the Commission removes the at-risk condition.

(b) The summary statements must provide the formulae and explain the bases used in the allocation of common costs to each incremental facility.

§ 154.310 Zones.

If the company maintains records of costs by zone, and proposes a zone rate methodology based on these costs, the statements and schedules in § 154.312 and § 154.313 must reflect costs detailed by zone.

§ 154.311 Updating of statements.

(a) Certain statements and schedules in § 154.312, that include test period data, must be updated with actual data by month and must be resubmitted in the same format and with consecutive monthly totals for each month of the adjustment period with a single set of updates encompassing a 12-month period. The updated statements or schedules must be filed 45 days after the end of the test period. The updated filing must be provided to parties specifically requesting them. The updated filing must reference the associated docket number and must be filed in the same format, form, and number as the original filing.

(b) The statements and schedules in § 154.312 to be updated are: Statements C, D and H-4; Schedules B-1, B-2, C-3, D-2, E-2, E-4, G-1, G-4, G-5, G-6, H-1 (1)(a), H-1 (1)(b), H-1 (1)(c), H-1 (2)(a) through H-1 (2)(k), H-2 (1), H-3 (3), I-4, and I-6.

(c) This requirement to file updates may be extended by the Secretary pursuant to § 375.302 of this chapter.

[Order 582-A, 61 FR 9629, Mar. 11, 1996]

§ 154.312 Composition of Statements.

(a) Statement A. Cost-of-service Summary. Summarize the overall gas utility cost-of-service: operation and maintenance expenses, depreciation, taxes, credits to cost-of-service, and return as developed in other statements and schedules.

(b) Statement B. Rate Base and Return Summary. Summarize the overall gas utility rate base shown in Statements C, D, E, and Schedules B-1 and B-2. Show the application of the claimed rate of return to the overall rate base.

(1) Schedule B-1. Accumulated Deferred Income Taxes (Account Nos. 190, 282, and 283). Show monthly book balances of accumulated deferred income taxes for each of the 12 months during the base period. List all items for which the accumulated deferred income taxes are calculated. In adjoining columns, show additions and reductions for the adjustment period balance and the total adjusted balance. Separately identify the individual components and the amounts in these accounts that the company seeks to include in its rate base.

(2) Schedule B-2. Regulatory Asset and Liability. If the pipeline seeks recovery of such balances in rate base, show monthly book balances of regulatory assets (Account 182.3) and liabilities (Account 254) for each of the 12 months during the base period. In adjoining columns, show additions and reductions for the adjustment period balance and the total adjusted balance. Separately identify the individual components and the amounts in these accounts that the company seeks to include in its rate base. Identify any specific Commission authority that required the establishment of these amounts. Regulatory asset or liability net of deferred tax amounts should be included. Also, separately state the gross amounts of the regulatory asset and liability.

(c) Statement C. Cost of Plant Summary. Show the amounts of gas utility plant classified by Accounts 101, 102, 103, 104, 105, 106, 107, 117.1, and 117.2 as of the beginning of the 12 months of actual experience, the book additions and reductions (in separate columns) during the 12 months, and the book balances at the end of the 12-month period. In adjoining columns, show the claimed adjustments, if any, to the book balances and the total cost of plant to be included in rate base. For Account 117, also provide the volumes by subaccount. State the method used for accounting for system gas recorded in Account 117.2. Explain all adjustments in the following schedules.

(1) Schedule C-1. End of Base and Test Period Plant Functionalized. Demonstrate the ending base and test period balances for Plant in Service, in columnar form, by detailed plant account prescribed by the Commission's Uniform System of Accounts for Natural Gas Companies (part 201 of this chapter) with subtotals by functional classifications, e.g., Intangible Plant, Manufactured Gas Production Plant, Natural Gas Production and Gathering Plant, Products Extraction Plant, Storage Plant, Transmission Plant, Distribution Plant, and General Plant. Show zones, to the extent required by § 154.310, and expansions, to the extent required by § 154.309. Separately identify those facilities and associated costs claimed for the test period that require certificate authority but such authority has not been obtained at the time of filing. Give the docket number of the certificate proceeding.

(2) Schedule C-2. Show, for Accounts 106 and 107, a list of work orders claimed in the rate base. Give the work order number, docket number, description, amount of each work order, and the amounts of each type of undistributed construction overhead. Work orders amounting to $500,000 or less may be grouped by category of items.

(3) Schedule C-3. A cross-reference to updated information in the company's FERC Form No. 2 may be substituted for this Schedule. Give details of each storage project owned and storage projects under contract to the company, showing cost by major functions. Show base and system gas storage quantities and associated costs by account for the test period and for the 12 months of actual experience with monthly inputs and outputs to system gas.

(4) Schedule C-4. This schedule is part of the workpapers. State the methods and procedures followed in capitalizing the allowance for funds used during construction and other construction overheads. This schedule must be provided only in situations when the pipeline has changed any of its procedures since the last filed FERC Forms No. 2 or 2-A.

(5) Schedule C-5. This schedule is part of the workpapers. Set forth the cost of Plant in Service carried on the company's books as gas utility plant which was not being used in rendering gas service. Describe the plant. This schedule must be provided only if there is a significant change of $500,000 or more since the end of the year reported in the company's last FERC Form No. 2 or 2-A.

(d) Statement D. Accumulated Provisions for Depreciation, Depletion, and Amortization. Show the accumulated provisions for depreciation, depletion, amortization, and abandonment (Account 108, detailed by functional plant classification, and Account 111), as of the beginning of the 12 months of actual experience, the book additions and reductions during the 12 months, and the balances at the end of the 12-month period. In adjoining columns, show adjustments to these ending book balances and the total adjusted balances. All adjustments must be explained in the supporting material. Any authorized negative salvage must be maintained in a separate subaccount of account 108, and shall not include any amounts related to asset retirement obligations. For each functional plant classification, show depreciation reserve associated with offshore and onshore plant separately. The following schedules and additional material must be submitted as part of Statement D:

(1) Schedule D-1. This schedule is part of the workpapers. Show the depreciation reserve book balance applicable to that portion of the depreciation rate not yet approved by the Commission, the depreciation rates, the docket number of the order approving such rate, and an explanation of any difference. Reflect actual end of base period depreciation reserve functionalized and test period depreciation reserve functionalized. Show accumulated depreciation and amortization, in columnar form, for the ending base and test period balances by functional classifications of Accumulated Depreciation reserve. (Examples are provided in Schedule C-1). For each functional plant classification, show depreciation reserve associated with offshore and onshore plant separately.

(2) Schedule D-2. This schedule is part of the workpapers. Give a description of the methods and procedures used in depreciating, depleting, and amortizing plant and in recording abandonments. This schedule must be filed only if a policy change has been made effective since the period covered by the last annual report on FERC Form No. 2 or 2-A was filed with the Commission.

(e) Statement E. Working Capital. Show the components of working capital in sufficient detail to explain how the amount of each component was computed. Components of working capital, other than cash working capital, may include an allowance for the average of 13 monthly balances of materials and supplies and prepayments actually expended and gas for resale. To the extent the applicant files to adjust the average of any 13 monthly balances, workpapers must be submitted that support the adjustment(s). Show the computations, cross-references, and sources from which the data used in computing claimed working capital are derived. The following schedules and material must be submitted as part of Statement E:

(1) Schedule E-1. Show the computation of cash working capital claimed as an adjustment to the gas company's rate base. Any adjustment to rate base requested must be based on a fully-developed and reliable lead-lag study. The components of the lead-lag study must include actual total company revenues, purchased gas costs, storage expense, transportation and compression of gas by others, salaries and wages, administrative and general expenses, income taxes payable, taxes other than income taxes, and any other operating and maintenance expenses for the base period. Cash working capital allowances in the form of additions to rate base may not exceed one-eighth of the annual operating expenses, as adjusted, net of non-cash items.

(2) Schedule E-2. Set forth monthly balances for materials, supplies, and prepayments in such detail as to disclose, either by subaccounts regularly maintained on the books or by analysis of the principal items included in the main account, the nature of such charges.

(3) Schedule E-3. For FERC Accounts 117.3, 164.1, 164.2 and 164.3, show the quantities and the respective costs of natural gas stored at the beginning of the test period, the input, output and balance remaining in Dth and associated costs by months. The method of pricing input, output and balance, and the claimed adjustments shall be disclosed and clearly and fully explained. Pipelines using the inventory method for system gas should not include any system gas inventory balances in this schedule.

(f) Statement F-1. Rate of Return Claimed. Show the percentage rate of return claimed and the general reasons therefor. Where any component of the capital of the filing company is not primarily obtained through its own financing, but is primarily obtained from a company by which the filing company is controlled, as defined in the Commission's Uniform System of Accounts, then the data required by these statements must be submitted with respect to the debt capital, preferred stock capital, and common stock capital of such controlling company or any intermediate company through which such funds have been secured. Furnish the Commission staff a copy of the latest prospectus issued by the filing natural gas company, any superimposed holding company, or subsidiary companies.

(g) Statement F-2. Show

(1) The capitalization, capital structure, cost of debt capital, preferred stock capital, and the claimed return on stockholders' equity;

(2) The weighted cost of each capital class based on the capital structure; and,

(3) The overall rate of return claimed.

(h) Statement F-3. Debt Capital. Show the weighted average cost of debt capital based upon the following data for each class and series of long-term debt outstanding according to the balance sheet, as of the end of the 12-month base period of actual experience and as of the end of the 9-month test period.

(1) Title.

(2) Date of issuance and date of maturity.

(3) Interest rate.

(4) Principal amount of issue: Gross proceeds; Underwriters' discount or commission: Amount; Percent gross proceeds; Issuance expense: Amount; Percent gross proceeds; Net proceeds; Net proceeds per unit.

(5) Cost of money: Yield to maturity based on the interest rate and net proceeds per unit outstanding determined by reference to any generally accepted table of bond yields. The yield to maturity is to be expressed as a nominal annual interest rate. For example, for bonds having semiannual payments, the yield to maturity is twice the semiannual rate.

(6) If the issue is owned by an affiliate, state the name and relationship of the owner.

(7) If the filing company has acquired, at a discount or premium, some part of its outstanding debt which could be used in meeting sinking fund requirements, or for other reasons, separately show: The annual amortization of the discount or premium for each series of debt from the date of reacquisition over the remaining life of the debt being retired; and, the total discount and premium, as a result of such amortization, applicable to the test period.

(i) Statement F-4. Preferred Stock Capital. Show the weighted average cost of preferred stock capital based upon the following data for each class and series of preferred stock outstanding according to the balance sheet, as of the end of the 12-month base period of actual experience and as of the end of the nine-month test period.

(1) Title.

(2) Date of issuance.

(3) If callable, call price.

(4) If convertible, terms of conversion.

(5) Dividend rate.

(6) Par or stated amount of issue: Gross proceeds; Underwriters' discount or commission: Amount; Percent gross proceeds; Issuance expenses: Amount; Percent gross proceeds; Net proceeds; Net proceeds per unit.

(7) Cost of money: Annual dividend rate divided by net proceeds per unit.

(8) State whether the issue was offered to stockholders through subscription rights or to the public.

(9) If the issue is owned by an affiliate, state the name and relationship of the owner.

(j) Statement G. Revenues, Credits, and Billing Determinants.

(1) Show in summary format the information requested below on revenues, credits and billing determinants for the base period and the base period as adjusted. Explain the basis for adjustment to the base period. The level of billing determinants should not be adjusted for discounting.

(i) Revenues. Provide the total revenues, from jurisdictional and non-jurisdictional services, classified in accordance with the Commission's Uniform System of Accounts for the base period and for the base period as adjusted. Separate operating revenues by major rate component (e.g., reservation charges, demand charges, usage charges, commodity charges, injection charges, withdrawal charges, etc.) from revenues received from penalties, surcharges or other sources (e.g., ACA, GRI, transition costs). Show revenues by rate schedule and by receipt and delivery rate zones, if applicable. Show separately the revenues for firm services under contracts with a primary term of less than one year. For services provided through released capacity, identify total revenues by rate schedule and by receipt and delivery rate zones, if applicable.

(ii) Credits. Show the principal components comprising each of the various items which are reflected as credits to the cost-of-service in preparing Statement A, Overall Cost-of-service for the base period and the base period as adjusted. Any transition cost component of interruptible transportation revenue must not be treated as operating revenues as defined above.

(iii) Billing Determinants. Show total reservation and usage billing determinants for the base period and the base period as adjusted, by rate schedule by receipt and delivery rate zones, if applicable. Show separately the billing determinants for firm services under contracts with a primary term of less than one year. For services provided through released capacity, identify billing determinants by rate schedule and by receipt and delivery rate zones, if applicable.

(2) The Schedules G-1 through G-6 must be filed at the FERC and served on all state commissions having jurisdiction over the affected customers within fifteen days after the rate case is filed. Schedules G-1 through G-6 must also be served on parties that request such service within 15 days of the filing of the rate case.

(i) Schedule G-1. Base Period Revenues. For the base period, show total actual revenues and billing determinants by month by customer name, by rate schedule, by receipt and delivery zone, if applicable, by major rate component (e.g., reservation charges) and totals. Billing determinants must not be adjusted for discounting. Provide actual throughput (i.e., usage or commodity quantities, unadjusted for discounting) and actual contract demand levels (unadjusted for discounting). Provide this information separately for firm service under contracts with a primary term of less than one year. Separate operating revenues from revenues received from surcharges or other sources (e.g., ACA, GRI, transition costs). Identify customers who are affiliates. Identify rate schedules under which costs are allocated and rate schedules under which revenues are credited for the base period with cross-references to the other filed statements and schedules.

(ii) Schedule G-2. Adjustment Period Revenues.

(A) Show revenues and billing determinants by month, by customer name, by rate schedule, by receipt and delivery zone, if applicable, by major rate component (e.g., reservation charges) and totals for the base period adjusted for known and measurable changes which are expected to occur within the adjustment period computed under the rates expected to be charged. Billing determinants must not be adjusted for discounting. Provide projected throughput (i.e., usage or commodity quantities, unadjusted for discounting) and projected contract demand levels (unadjusted for discounting). Provide this information separately for firm service under contracts with a primary term of less than one year. Separate operating revenues from revenues received from surcharges or other sources (e.g., ACA, GRI, transition costs). Identify customers who are affiliates. Identify rate schedules under which costs are allocated and rate schedules under which revenues are credited for the adjustment period with cross-references to the other filed statements and schedules.

(B) Provide a reconciliation of the base period revenues and billing determinants and the revenues and billing determinants for the base period as adjusted.

(iii) Schedule G-3. Specify, quantify, and justify each proposed adjustment (capacity release, plant closure, contract termination, etc.) to base period actual billing determinants, and provide a detailed explanation for each factor contributing to the adjustment. Include references to any certificate docket authorizing changes. Submit workpapers with all formulae.

(iv) Schedule G-4. At-Risk Revenue. For each instance where there is a separate cost-of-service associated with facilities for which the applicant is “at risk,” show the base period and adjustment period revenue by customer or customer code, by rate schedule, by receipt and delivery zone, if applicable, and as 12-month totals. Provide this information by month unless otherwise agreed to by interested parties and if monthly reporting is consistent with past practice of the pipeline. However, if seasonal services are involved, or if billing determinants vary from month to month, the information must be provided monthly. Provide projected throughput (i.e., usage or commodity quantities, unadjusted for discounting) and projected contract demand levels (unadjusted for discounting).

(v) Schedule G-5. Other Revenues.

(A) Describe and quantify, by month, the types of revenue included in Account Nos. 490-495 for the base and test periods. Show revenues applicable to the sale of products. Show the principal components comprising each of the various items which are reflected as credits to cost-of-service in Statement A.

(B) To the extent the credits to the cost-of-service reflected in Statement A differ from the amounts shown on Schedule G-5, compare and reconcile the two statements. Quantify and explain each proposed adjustment to base period actuals. For Account No. 490, show the name and location of each product extraction plant processing gas for the applicant, and the inlet and outlet monthly dth of the pipeline's gas at each plant. Show the revenues received by the applicant by product by month for each extraction plant for the base period and proposed for the test period.

(C) Separately state each item and revenue received for the transportation of liquids, liquefiable hydrocarbon, or nonhydrocarbon constituents owned by shippers. For both the base and test periods, indicate by shipper contract: The quantity transported and the revenues received.

(D) Separately state the revenues received from the release by the pipeline of transportation and compression capacity it holds on other pipeline systems. The revenues must equal the revenues reflected on Schedule I-4(iv).

(vi) Schedule G-6. Miscellaneous Revenues. Separately state by month the base and adjustment period revenues and the associated quantities received as penalties from jurisdictional customers; the revenues received from cash outs and other imbalance adjustments; and, the revenues received from exit fees.

(k) Statement H-1. Operation and Maintenance Expenses. Show the gas operation and maintenance expenses according to each applicable account of the Commission's Uniform System of Accounts for Natural Gas Companies. Show the expenses under columnar headings, with subtotals for each functional classification, as follows: Operation and maintenance expense by months, as booked, for the 12 months of actual experience, and the 12-month total; adjustments, if any, to expenses as booked; and, total adjusted operation and maintenance expenses. Provide a detailed narrative explanation of, and the basis and supporting workpapers for, each adjustment. The following schedules and additional material must be submitted as part of Statement H-1:

(1) Schedule H-1 (1). This schedule is part of the workpapers. Show the labor costs, materials and other charges (excluding purchased gas costs) and expenses associated with Accounts 810, 811, and 812 recorded in each gas operation and maintenance expense account of the Uniform System of Accounts. Show these expenses, under the columnar headings, with subtotals for each functional classification, as follows: operation and maintenance expenses by months, as booked, for the 12 months of actual experience, and the 12-month total; adjustments, if any, to expenses as booked; and total adjusted operation and maintenance expenses. Disclose and explain all accrual on the books at the end of the base period or other normalizing accounting entries for internal purposes reflected in the monthly expenses presented per book. Explain any amounts not currently payable, except depreciation charged through clearing accounts, included in operation and maintenance expenses.

(2) Schedule H-1 (1)(a). Labor Costs.

(3) Schedule H-1 (1)(b). Materials and Other Charges (Excluding Purchased Gas Costs and items shown in Schedule H-1 (1)(c)).

(4) Schedule H-1 (1)(c). Quantities Applicable to Accounts Nos. 810, 811, and 812. Show the quantities for each of the contra-accounts for both base and test periods.

(5) Schedule H-1 (2). This schedule is part of the workpapers. Show, for the 12 months of actual experience and claimed adjustments: A classification of principal charges, credits and volumes; particulars of supporting computations and accounting bases; a description of services and related dollar amounts for which liability is incurred or accrued; and, the name of the firm or individual rendering such services. Expenses reported in Schedules H-1 (2)(a) through H-1 (2)(k) of $100,000 or less per type of service may be grouped.

(6) Schedule H-1 (2)(a). Accounts 806, 808.1, 808.2, 809.1, 809.2, 813, 823, and any other account used to record fuel use or gas losses. Provide details of each type of expense.

(7) Schedule H-1 (2)(b). Accounts 913 and 930.1. Advertising Expenses. Disclose principal types of advertising such as TV, newspaper, etc.

(8) Schedule H-1 (2)(c). Account 921. Office Supplies and Expenses.

(9) Schedule H-1 (2)(d). Account 922. Administrative Expenses Transferred Credit.

(10) Schedule H-1 (2)(e). Account 923. Outside Services Employed.

(11) Schedule H-1 (2)(f). Account 926. Employee Pensions and Benefits.

(12) Schedule H-1 (2)(g). Account 928. Regulatory Commission Expenses.

(13) Schedule H-1 (2)(h). Account 929. Duplicate Charges. Credit.

(14) Schedule H-1 (2)(i). Account 930.2. Miscellaneous General Expenses.

(15) Schedule H-1 (2)(j). Intercompany and Interdepartmental Transactions. Provide a complete disclosure of all corporate overhead allocated to the company. If the expense accounts contain charges or credits to and from associated or affiliated companies or nonutility departments of the company, submit a schedule, or schedules, as to each associated or affiliated company or nonutility department showing:

(i) The amount of the charges, or credits, during each month and in total for the base period and the adjustment period.

(ii) The FERC Account No. charged (or credited).

(iii) Descriptions of the specific services performed for, or by, the associated/affiliated company or nonutility department.

(iv) The bases used in determining the amounts of the charges (credits). Explain and demonstrate the derivation of the allocation bases with underlying calculations used to allocate costs among affiliated companies, and identify (by account number) all costs paid to, or received from affiliated companies which are included in a pipeline's cost-of-service for both the base and test periods.

(16) Schedule H-1 (2)(k). Show all lease payments applicable to gas operation contained in the operation and maintenance accounts. Leases of $500,000 or less may be grouped by type of lease.

(l) Statement H-2. Depreciation, Depletion, Amortization and Negative Salvage Expenses. Show, separately, the gas plant depreciation, depletion, amortization, and negative salvage expenses by functional classifications. For each functional plant classification, show depreciation reserve associated with offshore and onshore plant separately. Show, in separate columns: expenses for the 12 months of actual experience; adjustments, if any, to such expense; and, the total adjusted expense claimed. Explain the bases, methods, essential computations, and derivation of unit rates for the calculation of depreciation, depletion, and amortization expense for the 12 months of actual experience and for the adjustments. The amounts of depreciable plant must be shown by the functions specified in paragraph C of Account 108, Accumulated Provisions for Depreciation of Gas Utility Plant, and Account 111, Accumulated Provision for Amortization and Depletion of Gas Utility Plant, of the Commission's Uniform System of Accounts for Natural Gas Companies, and, if available, for each detailed plant account (300 Series) together with the rates used in computing such expenses. Explain any deviation from the rates determined to be just and reasonable by the Commission. Show the rate or rates previously used together with supporting data for the new rate or rates used for this filing. The following schedule and additional material must be submitted as a part of Statement H-2:

(1) Schedule H-2 (1). Depreciable Plant.

(i) Reconcile the depreciable plant shown in Statement H-2 with the aggregate investment in gas plant shown in Statement C, and the expense charged to other than prescribed depreciation, depletion, amortization, and negative salvage expense accounts. Identify the amounts of plant costs and associated plant accounts used as the bases for depreciation expense charged to clearing accounts. For each functional plant classification, show depreciation reserve associated with offshore and onshore plant separately.

(ii) Schedule H-2 (1) must be updated, as set forth in § 154.310, with actual depreciable plant and reconciled with updated Statement C.

(m) Statement H-3. Income Taxes. Show the computation of allowances for Federal and State income taxes for the test period based on the claimed return applied to the overall gas utility rate base. To indicate the accounting classification applicable to the amount claimed, the computation of the Federal income tax allowance must show, separately, the amounts designated as current tax and deferred tax. Section 154.306, Tax Normalization, is incorporated in these instructions by reference. All the requirements of this section apply to Schedule H-3. The following schedules and additional material must be submitted as a part of Statement H-3:

(1) Schedule H-3 (1). This schedule is part of the workpapers. Show the income tax paid each State in the current and/or previous year covered by the test period.

(2) Schedule H-3 (2). This schedule is part of the workpapers. Show the computation of an updated reconciliation between book depreciable plant and tax depreciable plant and accumulated provision for deferred income taxes, for the base period or latest calendar or fiscal year (depending on the company's reporting period). Regulatory asset or liability net of deferred tax amounts should be included in this reconciliation. Also, separately state the gross amounts of the regulatory asset and liability.

(n) Statement H-4. Other Taxes. Show the gas utility taxes, other than Federal or state income taxes, in separate columns, as follows: Tax expense per books for the 12 months of actual experience (separately identify the amounts expensed or accrued during the period); adjustments, if any, to amounts booked; and, the total adjusted taxes claimed. Show the kind and amount of taxes paid under protest or in connection with taxes under litigation. Show taxes by state and by type of tax. The following schedules and additional material must be submitted as a part of Statement H-4:

(1) Schedule H-4. This schedule is part of the workpapers. Show the computations of adjusted taxes claimed in Statement H(4).

(o) Statement I. Statement I consists of the following Schedules:

(1) Schedule I-1. Functionalization of Cost-of-service. Show the overall cost-of-service contained in Statement A as supported by Statements B, C, D, E, G (revenue credits), and H:

(i) Schedule I-1(a). Separate overall cost-of-service by function of facility.

(ii) Schedule I-1(b). Separate the transmission, storage, and gathering facilities between incremental and non-incremental facilities. If the pipeline proposes to directly assign the costs of specific facilities, it must provide a separate cost-of-service for every directly assigned facility (e.g., lateral or storage field).

(iii) Schedule I-1(c). If the pipeline maintains records of costs by zone and proposes a zone rate methodology based on those costs separately state transmission, storage, and gathering costs, for each zone.

(iv) Schedule I-1(d). Show the method used to allocate common and joint costs to various functions including the allocation of A&G. Provide the factors underlying the allocation of general costs (e.g., miles of pipe, cost of plant, labor). Show the formulae used and explain the bases for the allocation of common and joint costs.

(2) Schedule I-2. Classification of Cost-of-service.

(i) For each functionalized cost-of-service provided in Schedule I-1 (a), (b), and (c), show the classification of costs between fixed costs and variable costs and between reservation costs and usage costs. The classification must be for each element of the cost-of-service (e.g., depreciation expenses, state income taxes, revenue credits). For operation and maintenance expenses and revenue credits, the classification must be provided by account and by total.

(ii) Explain the basis for the classification of costs.

(iii) Explain any difference between the method for classifying costs and the classification method underlying the pipeline's currently effective rates.

(3) Schedule I-3. Allocation of Cost-of-service.

(i) If the company provides gas sales and transportation as a bundled service, show the allocation of costs between direct sales or distribution sales and the other services. If the company provides unbundled transportation, show the allocation of costs between services with cost-of-service rates and services with market-based rates, including products extraction, sales, and company-owned production. If the cost-of-service is allocated among rate zones, show how the classified cost-of-service is allocated among rate zones by function. If the pipeline proposes to establish rate zones for the first time, or to change existing rate zone boundaries, explain how the rate zone boundaries are established.

(ii) Show how the classified costs of service provided in Schedule I-2 or Schedule I-3 (i) are allocated among the pipeline's services and rate schedules.

(iii) Provide the formulae used in the allocation of the cost-of-service. Provide the factors underlying the allocation of the cost-of-service (e.g., contract demand, annual billing determinants, three-day peak). Provide the load factor or other basis for any imputed demand quantities.

(iv) Explain any changes in the basis for the allocation of the cost-of-service from the allocation methodologies underlying the currently effective rates.

(4) Schedule I-4. Transmission and Compression of Gas by Others (Account 858). Provide the following information for each transaction for the base and adjustment period:

(i) The name of the transporter.

(ii) The name of the rate schedule under which service is provided, and the expiration date of the contract.

(iii) Monthly usage volumes.

(iv) Monthly costs.

(v) The monthly revenues for volumes flowing under released capacity. The revenues in Schedule I-4 (iv) must also be reflected, separately, as a credit in Schedule G-5.

(5) Schedule I-5. Gas Balance. Show by months and total, for the 12 months of actual experience, the company's Gas Account, in the form required by FERC Form No. 2 pages 520 and 521. Show corresponding estimated data, if claimed to be different from actual experience. Provide the basis for any variation between estimated and actual base period data.

(p) Statement J. Comparison and Reconciliation of Estimated Operating Revenues With Cost-of-service. Compare the total revenues by rate schedule (Schedule G-2) to the allocated cost-of-service (Statement I). Identify any surcharges that are reflected in Statement N or in Statement I.

(1) Schedule J-1. Summary of Billing Determinants. Provide a summary of all billing determinants used to derive rates. Provide a reconciliation of customers' total billing determinants as shown on Schedule G-2 with those used to derive rates in Schedule J-2. Provide an explanation of how any discount adjustment is developed. If billing determinants are imputed for interruptible service, explain the method for calculating the billing determinants.

(2) Schedule J-2. Derivation of Rates. Show the derivation of each rate component of each rate. For each rate component of each rate schedule, include:

(i) A reference (by page, line, and column) to the allocated cost-of-service in Statement I.

(ii) A reference to the appropriate billing determinants in Schedule J-1.

(iii) Explain any changes in the method used for the derivation of rates from the method used in developing the underlying rates.

(q) Statement K. [Reserved]

(r) Statement L. Balance Sheet. Provide a balance sheet in the form prescribed by the Commission's Uniform System of Accounts for Natural Gas Companies as of the beginning and end of the base period. Include any notes. If the natural gas company is a member of a group of companies, also provide a balance sheet on a consolidated basis.

(s) Statement M. Income Statement. Provide an income statement, including a section on earnings, in the form prescribed by the Commission's Uniform System of Accounts for Natural Gas Companies for the base period. Include any notes. If the natural gas company is a member of a system group of companies, provide an income statement on a consolidated basis.

(t) Statement N. [Reserved]

(u) Statement O. Description of Company Operations. Provide a description of the company's service area and diversity of operations. Include the following:

(1) Only if significant changes have occurred since the filing of the last FERC Form No. 2 or 2-A, provide a detailed system map.

(2) A list of each major expansion and abandonment since the company's last general rate case. Provide brief descriptions, approximate dates of operation or retirement from service, and costs classified by functions.

(3) A detailed description of how the company designs and operates its systems. Include design temperature.

(v) Statement P. Explanatory Text and Prepared Testimony. Provide copies of prepared testimony indicating the line of proof which the company would offer for its case-in-chief in the event that the rates are suspended and the matter set for hearing. Name the sponsoring witness of all text and testimony. Statement P must be filed concurrently with the other schedules.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 582-A, 61 FR 9629, Mar. 11, 1996; Order 631, 68 FR 19622, Apr. 21, 2003]

§ 154.313 Schedules for minor rate changes.

(a) A change in a rate or charge that, for the test period, does not increase the company's revenues by the smaller of $1,000,000 or 5 percent is a minor rate change. A change in a rate level that does not directly or indirectly result in an increased rate or charge to any customer or class of customers is a minor rate change.

(b) In addition to the schedules in this section, filings for minor rate changes must include Statements L, M, O, P, I-1 through I-4, and J of § 154.312.

(c) The schedules of this section must contain the principal determinants essential to test the reasonableness of the proposed minor rate change. Any adjustments to book figures must be separately stated and the basis for the adjustment must be explained.

(d) Schedules B-1, B-2, C, D, E, H, H-2, and H-4 of § 154.313, must be updated with actual data by month and must be resubmitted in the same format and with consecutive 12 month running totals, for each month of the adjustment period. The updated statements or schedules must be filed 45 days after the end of the test period. The updated filing must reference the associated docket number and must be filed in the same format, form, and number as the original filing.

(e) Composition of schedules for minor rate changes.

(1) Schedule A. Overall Cost-of-service by Function. Summarize the overall cost-of-service (operation and maintenance expenses, depreciation, taxes, return, and credits to cost-of-service) developed from the supporting schedules below.

(2) Schedule B. Overall Rate Base and Return. Summarize the overall gas utility rate base by function. Include the claimed rate of return and show the application of the claimed rate of return to the overall rate base.

(3) Schedule B-1. Accumulated Deferred Income Taxes (Account Nos. 190, 281, 282, and 283). Show monthly book balances of accumulated deferred income taxes for each of the 12 months during the base period. In adjoining columns, show additions and reductions for the adjustment period balance and the total adjusted balance.

(4) Schedule B-2. Regulatory Asset and Liability. Show monthly book balances of regulatory asset (Account 182.3) and liability (Account 254) for each of the 12 months during the base period. In adjoining columns, show additions and reductions for the adjustment period balance and the total adjusted balance. Only include these accounts if recovery of these balances are reflected in the company's costs. Identify the specific Commission authority which required the establishment of these accounts.

(5) Schedule C. Cost of Plant by Functional Classification as of the End of the Base and Adjustment Periods.

(6) Schedule D. Accumulated Provisions for Depreciation, Depletion, Amortization, and Abandonment by Functional Classifications as of the Beginning and as of the End of the Test Period.

(7) Schedule E. Working Capital. Show the various components provided for in § 154.312, Statement E.

(8) Schedule F. Show the rate of return claimed with a brief explanation of the basis.

(9) Schedule G. Revenues and Billing Determinants.

(i) Show in summary format the information requested below on revenues and billing determinants for the base period and the base period as adjusted. Schedule G must be submitted to all customers of the pipeline that received service during the base period or are expected to receive service during the base period as adjusted and on State commissions having jurisdiction over the affected customers.

(A) Revenues. Provide the total revenues by rate schedule from jurisdictional services, classified in accordance with the Commission's Uniform System of Accounts for the base period and for the base period as adjusted. Separate operating revenues by major rate component (e.g., reservation charges, demand charges, usage charges, commodity charges, injection charges, withdrawal charges, etc.) from revenues received from penalties, surcharges or other sources (e.g., ACA, GRI, transition costs). For services provided through released capacity, identify total revenues by rate schedule and by receipt and delivery rate zones, if applicable.

(B) Billing Determinants. Show total reservation and usage billing determinants by rate schedule for the base period and the base period as adjusted. For services provided through released capacity, identify total billing determinants by rate schedule and by receipt and delivery rate zones, if applicable.

(ii) Schedule G-1 must be filed at the Commission and on all state commissions having jurisdiction over the affected customers within 15 days after the rate case is filed. Schedule G-1 must also be served on parties that request such service within 15 days of the filing of the rate case.

(A) Schedule G-1. Adjustment Period Revenues.

(1) Show revenues and billing determinants by month, by customer name, by rate schedule, by major rate component (e.g., reservation charges) and totals for the base period adjusted for known and measurable changes which are expected to occur within the adjustment period computed under the rates expected to be charged. Show commodity billing determinants by rate schedule. Billing determinants must not be adjusted for discounting. Provide projected throughput (i.e., usage or commodity quantities, unadjusted for discounting) and projected contract demand levels (unadjusted for discounting). Separate operating revenues from revenues received from surcharges or other sources (e.g., ACA, GRI, transition costs). Identify customers who are affiliates. Identify rate schedules under which costs are allocated and rate schedules under which revenues are credited for the adjustment period with cross-references to the other filed statements and schedules.

(2) Provide a reconciliation of the base period revenues and billing determinants and the revenues and billing determinants for the base period as adjusted.

(10) Schedule H. Operation and Maintenance Expenses. Show the gas operation and maintenance expenses according to each applicable account of the Commission's Uniform System of Accounts for Natural Gas Companies. The expenses must be shown under appropriate columnar-headings, by labor, materials and other charges, and purchased gas costs, with subtotals for each functional classification: Operation and maintenance expense by months, as booked, for the 12 months of actual experience, and the total thereof; adjustments, if any, to expenses as booked; and, total adjusted operation and maintenance expenses claimed. Explain all adjustments. Specify the month or months during which the adjustments would be applicable.

(11) Schedule H-1. Workpapers for Expense Accounts. Furnish workpapers for the 12 months of actual experience and claimed adjustments and analytical details as set forth in § 154.312, Schedule H-1 (3).

(12) Schedule H-2. Depreciation, Depletion, Amortization and Negative Salvage Expenses. Show, separately, the gas plant depreciation, depletion, amortization, and negative salvage expenses by functional classifications. For each functional plant classification, show depreciation reserve associated with offshore and onshore plant separately. The bases, methods, essential computations, and derivation of unit rates for the calculation of depreciation, depletion, amortization, and negative salvage expenses for actual experience must be explained.

(13) Schedule H-3. Income Tax Allowances Computed on the Basis of the Rate of Return Claimed. Show the computation of allowances for Federal and State income taxes based on the claimed return applied to the overall gas utility rate base.

(14) Schedule H-3 (1). This schedule is part of the workpapers. Show the computation of an updated reconciliation between book depreciable plant and tax depreciable plant and accumulated provision for deferred income taxes, for the base period or latest calendar or fiscal year (depending on the company's reporting period).

(15) Schedule H-4. Other Taxes. Show the gas utility taxes, other than Federal or state income taxes in separate columns, as follows: Tax expense per books for the 12 months of actual experience;) adjustments, if any, to amounts booked; and, the total adjusted taxes claimed. Provide the details of the kind and amount of taxes paid under protest or in connection with taxes under litigation. The taxes must be shown by states and by kind of taxes. Explain all adjustments.

§ 154.314 Other support for a filing.

(a) Any company filing for a rate change is responsible for preparing prior to filing, and maintaining, workpapers sufficient to support the filing.

(b) If the natural gas company has relied upon data other than those in Statements A through P in § 154.312 in support of its general rate change, such other data must be identified and submitted.

§ 154.315 Asset retirement obligations.

(a) A natural gas company that files a tariff change under this part and has recorded an asset retirement obligation on its books must provide a schedule, as part of the supporting workpapers, identifying all cost components related to the asset retirement obligations that are included in the book balances of all accounts reflected in the cost of service computation supporting the proposed rates. However, all cost components related to asset retirement obligations that would impact the calculation of rate base, such as gas plant and related accumulated depreciation and accumulated deferred income taxes, may not be reflected in rates and must be removed from the rate base calculation through a single adjustment.

(b) A natural gas company seeking to recover nonrate base costs related to asset retirement obligations in rates must provide, with its filing under § 154.312 or § 154.313, a detailed study supporting the amounts proposed to be collected in rates.

(c) A natural gas company who has recorded asset retirement obligations on its books but is not seeking recovery of the asset retirement costs in rates, must remove all asset retirement obligations related cost components from the cost of service supporting its proposed rates.

[Order 631, 68 FR 19622, Apr. 21, 2003]

§ 154.400 Additional requirements.

In addition to the requirements of subparts A, B, and C of this part, any proposal to implement a limited rate change must comply with this subpart.

§ 154.401 RD&D expenditures.

(a) Requirements. Upon approval by the Commission, a natural gas company may file to recover research, development, and demonstration (RD&D) expenditures in its rates under this subpart.

(b) Applications for rate treatment approval. (1) An application for advance approval of rate treatment may be filed by a natural gas company for RD&D expenditures related to a project or group of projects undertaken by the company or as part of a project undertaken by others. When more than one company supports an RD&D organization, the RD&D organization may submit an application that covers the organization's RD&D program. Approval by the Commission of such an RD&D application and program will constitute approval of the individual companies' contributions to the RD&D organization.

(2) An application for advance approval of rate treatment must include a 5-year program plan and must be filed at least 180 days prior to the commencement of the 5-year period of the plan.

(3) A 5-year program plan must include at a minimum:

(i) A statement of the objectives for the 5-year period that relates the objectives to the interests of ratepayers, the public, and the industry and to the objectives of other major research organizations.

(ii) Budget, technical, and schedule information in sufficient detail to explain the work to be performed and allow an assessment of the probability of success and a comparison with other organizations' research plans.

(iii) The commencement date, expected termination date, and expected annual costs for individual RD&D projects to be initiated during the first year of the plan.

(iv) A discussion of the RD&D efforts and progress since the preparation of the program plan submitted the previous year and an explanation of any changes that have been made in objectives, priorities, or budgets since the plan of the previous year.

(v) A statement identifying all jurisdictional natural gas companies that will support the program and specifying the amounts of their budgeted support.

(vi) A statement identifying those persons involved in the development, review, and approval of the plan and specifying the amount of effort contributed and the degree of control exercised by each.

(c) Applications must describe the RD&D projects in such detail as to satisfy the Commission that the RD&D expenditures qualify as valid, justifiable, and reasonable.

(d) Within 120 days of the filing of an application for rate treatment approval and a 5-year program plan, the Commission will state its decision with respect to acceptance, partial acceptance, or rejection of the plan, or, when the complexity of issues in the plan so requires, will set a date certain by which a final decision will be made, or will order the matter set for hearing. Partial rejection of a plan by the Commission will be accompanied by a decision as to the partial level of acceptance which will be proportionally applied to all contributions listed for jurisdictional companies in the plan. Approval by the Commission of a 5-year plan constitutes approval for rate treatment of all projects identified as starting during the first year of the approved plan. Continued rate treatment will depend upon review and evaluation of subsequent annual applications and 5-year program plans.

§ 154.402 ACA expenditures.

(a) Requirements. Upon approval by the Commission, a natural gas pipeline company may adjust its rates, annually, to recover from its customers annual charges assessed by the Commission under part 382 of this chapter pursuant to an annual charge adjustment clause (ACA clause). Prior to the start of each fiscal year, the Commission will post on its Web site the amount of annual charges to be flowed through per unit of energy sold or transported (ACA unit charge) for that fiscal year. A company's ACA clause must be filed with the Commission and must incorporate by reference the ACA unit charge for the upcoming fiscal year as posted on the Commission's Web site. A company must incorporate by reference the ACA unit charge posted on the Commission's Web site in each of its rate schedules applicable to sales or transportation deliveries. The company must apply the ACA unit charge posted on the Commission's Web site to the usage component of rate schedules with two-part rates. A company may recover annual charges through an ACA unit charge only if its rates do not otherwise reflect the costs of annual charges assessed by the Commission under § 382.106(a) of this chapter. The applicable annual charge, required by § 382.103 of this chapter, must be paid before the company applies the ACA unit charge. Upon payment to the Commission of its annual charges, the ACA unit charge for that fiscal year will be incorporated by reference into the company's tariff, effective throughout that fiscal year.

(b) Application for rate treatment authorization. A company seeking authorization to use an ACA unit charge must file with the Commission a separate ACA tariff record containing:

(1) A statement that the company is collecting an ACA unit charge, as calculated by the Commission, applicable to all the pipeline's sales and transportation rate schedules,

(2) A statement that the ACA unit charge, as revised annually and posted on the Commission's Web site, is incorporated by reference into the company's tariff,

(3) For companies with existing ACA clauses, a proposed effective date of the tariff change of October 1 of the fiscal year; for companies seeking to utilize an ACA clause after October 1 of the fiscal year, a proposed effective date 30 days after the filing of the tariff record, unless a shorter period is specifically requested in a waiver petition and approved), and

(4) A statement that the pipeline will not recover any annual charges recorded in FERC Account 928 in a proceeding under subpart D of this part.

(c) Changes to the ACA unit charge must be filed annually, to reflect the annual charge unit rate authorized by the Commission each fiscal year.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 714, 73 FR 57535, Oct. 3, 2008; Order 776, 78 FR 19412, Apr. 1, 2013]

§ 154.403 Periodic rate adjustments.

(a) This section applies to the passthrough, on a periodic basis, of a single cost item or revenue item for which passthrough is not regulated under another section of this subpart, and to revisions on a periodic basis of a gas reimbursement percentage.

(b) Where a pipeline recovers fuel use and unaccounted-for natural gas in kind, the fuel reimbursement percentage must be stated in the tariff either on the tariff sheet stating the currently effective rate or on a separate tariff sheet or section in such a way that it is clear what amount of natural gas must be tendered in kind for each service rendered.

(c) A natural gas company that passes through a cost or revenue item or adjusts its fuel reimbursement percentage under this section, must state within the general terms and conditions of its tariff, the methodology and timing of any adjustments. The following must be included in the general terms and conditions:

(1) A statement of the nature of the revenue or costs to be flowed through to the customer;

(2) A statement of the manner in which the cost or revenue will be collected or returned, whether through a surcharge, offset, or otherwise;

(3) A statement of which customers are recipients of the revenue credit and which rate schedules are subject to the cost or fuel reimbursement percentage;

(4) A statement of the frequency of the adjustment and the dates on which the adjustment will become effective;

(5) A step-by-step description of the manner in which the amount to be flowed through is calculated and a step-by-step description of the flowthrough mechanism, including how the costs are classified and allocated. Where the adjustment modifies a rate established under subpart D of this part, the methodology must be consistent with the methodology used in the proceeding under subpart D of this part;

(6) Where costs or revenue credits are accumulated over a past period for periodic recovery or return, the past period must be defined and the mechanism for the recovery or return must be detailed on a step-by-step basis. Where the natural gas company proposes to use a surcharge to clear an account in which the difference between costs or revenues, recovered through rates, and actual costs and revenues accumulate, a statement must be included detailing, on a step-by-step basis, the mechanism for calculating the entries to the account and for passing through the account balance.

(7) Where carrying charges are computed, the calculations must be consistent with the methodology and reporting requirements set forth in § 154.501 using the carrying charge rate required by that section. A natural gas company must normalize all income tax timing differences which are the result of differences between the period in which expense or revenue enters into the determination of taxable income and the period in which the expense or revenue enters into the determination of pre-tax book income. Any balance upon which the natural gas company calculates carrying charges must be adjusted for any recorded deferred income taxes.

(8) Where the natural gas company discounts the rate component calculated pursuant to this section, explain on a step-by-step basis how the natural gas company will adjust for rate discounts in its methodology to reflect changes in costs under this section.

(9) If the costs passed through under a mechanism approved under this section are billed by an upstream natural gas company, explain how refunds received from upstream natural gas companies will be passed through to the natural gas company's customers, including the allocation and classification of such refunds;

(10) A step-by-step explanation of the methodology used to reflect changes in the fuel reimbursement percentage, including the allocation and classification of the fuel use and unaccounted-for natural gas. Where the adjustment modifies a fuel reimbursement percentage established under subpart D of this part, the methodology must be consistent with the methodology used in the proceeding under subpart D of this part;

(11) A statement of whether the difference between quantities actually used or lost and the quantities retained from the customers for fuel use and loss will be recovered or returned in a future surcharge. Include a step-by-step explanation of the methodology used to calculate such surcharge. Any period during which these differences accumulate must be defined.

(d) Filing requirements. (1) Filings under this section must include:

(i) A summary statement showing the rate component added to each rate schedule with workpapers showing all mathematical calculations.

(ii) If the filing establishes a new fuel reimbursement percentage or surcharge, include computations for each fuel reimbursement or surcharge calculated, broken out by service, classification, area, zone, or other subcategory.

(iii) Workpapers showing the allocation of costs or revenue credits by rate schedule and step-by-step computations supporting the allocation, segregated into reservation and usage amounts, where appropriate.

(iv) Where the costs, revenues, rates, quantities, indices, load factors, percentages, or other numbers used in the calculations are publicly available, include references by source.

(v) Where a rate or quantity underlying the costs or revenue credits is supported by publicly available data (such as another natural gas company's tariff or EBB), the source must be referenced to allow the Commission and interested parties to review the source. If the rate or quantity does not match the rate or quantity from the source referenced, provide step-by-step instructions to tie the rate in the referenced source to the rate in the filing.

(vi) Where a number is derived from another number by applying a load factor, percentage, or other adjusting factor not referenced in paragraph (d)(1)(i) of this section, include workpapers and a narrative to explain the calculation of the adjusting factor.

(2) If the natural gas company is adjusting its rates to reflect changes in transportation and compression costs paid to others:

(i) The changes in transportation and compression costs must be based on the rate on file with the Commission. If the rate is not on file with the Commission or a discounted rate is paid, the rate reflected in the filing must be the rate the natural gas company is contractually obligated to pay;

(ii) The filing must include appropriate credits for capacity released under § 284.243 of this chapter with workpapers showing the quantity released, the revenues received from the release, the time period of the release, and the natural gas pipeline on which the release took place; and,

(iii) The filing must include a statement of the refunds received from each upstream natural gas company which are included in the rate adjustment. The statement must conform to the requirements set forth in § 154.501.

(3) If the natural gas company is reflecting changes in its fuel reimbursement percentage, the filing must include:

(i) A summary statement of actual gas inflows and outflows for each month used to calculate the fuel reimbursement percentage or surcharge. For purposes of establishing the surcharge, the summary statement must be included for each month of the period over which the differences defined in paragraph (c) of this section accumulate.

(ii) Where the fuel reimbursement percentage is calculated based on estimated activity over a future period, the period must be defined and the estimates used in the calculation must be justified. If any of the estimates are publicly available, include a reference to the source.

(4) The natural gas company must not recover costs and is not obligated to return revenues which are applicable to the period pre-dating the effectiveness of the tariff language setting forth the periodic rate change mechanism, unless permitted or required to do so by the Commission.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 714, 73 FR 57535, Oct. 3, 2008]

§ 154.501 Refunds.

(a) Refund Obligation. (1) Any natural gas company that collects rates or charges pursuant to this chapter must refund that portion of any increased rates or charges either found by the Commission not to be justified, or approved for refund by the Commission as part of a settlement, together with interest as required in paragraph (d) of this section. The refund plus interest must be distributed as specified in the Commission order requiring or approving the refund, or if no date is specified, within 60 days of a final order. For purposes of this paragraph, a final order is an order no longer subject to rehearing. The pipeline is not required to make any refund until it has collected the refundable money through its rates.

(2) Any natural gas company must refund to its jurisdictional customers the jurisdictional portion of any refund it receives which is required by prior Commission order to be flowed through to its jurisdictional customers or represents the refund of an amount previously included in a filing under § 154.403 and charged and collected from jurisdictional customers within thirty days of receipt or other time period established by the Commission or as established in the pipeline's tariff.

(b) Costs of Refunding. Any natural gas company required to make refunds pursuant to this section must bear all costs of such refunding.

(c) Supplier Refunds. The jurisdictional portion of supplier refunds (including interest received), applicable to periods in which a purchased gas adjustment clause was in effect, must be flowed through to the natural gas company's jurisdictional gas sales customers during that period with interest as computed in paragraph (d) of this section.

(d) Interest on Refunds. Interest on the refund balance must be computed from the date of collection from the customer until the date refunds are made as follows:

(1) At an average prime rate for each calendar quarter on all excessive rates or charges held (including all interest applicable to such rates and charges) on or after October 1, 1979. The applicable average prime rate for each calendar quarter must be the arithmetic mean, to the nearest one-hundredth of one percent, of the prime rate values published in the Federal Reserve Bulletin, or in the Federal Reserve's “Selected Interest Rates” (Statistical Release G, 13), for the fourth, third, and second months preceding the first month of the calendar quarter.

(2) The interest required to be paid under paragraph (d)(1) of this section must be compounded quarterly.

(3) The refund balance must be either:

(i) The revenues resulting from the collection of the portion of any increased rates or charges found by the Commission not to be justified; or

(ii) An amount agreed upon in a settlement approved by the Commission; or

(iii) The jurisdictional portion of a refund the natural gas company receives.

(e) Unless otherwise provided by the order, settlement or tariff provision requiring the refund, the natural gas company must file a report of refunds, within 30 days of the date the refund was made, which complies with § 154.502 and includes the following:

(1) Workpapers and a narrative sufficient to show how the refunds for jurisdictional services were calculated;

(2) Workpapers and a narrative sufficient to determine the origin of the refund, including step-by-step calculations showing the derivation of the refund amount described in paragraph (d)(3) of this section, if necessary;

(3) References to any publicly available sources which confirm the rates, quantities, or costs, which are used to calculate the refund balance or which confirm the refund amount itself. If the rate, quantity, cost or refund does not directly tie to the source, a workpaper must be included to show the reconciliation between the rate, quantity, cost, or refund in the natural gas company's report and the corresponding rate, quantity, cost or refund in the source document;

(4) Workpapers showing the calculation of interest on a monthly basis, including how the carrying charges were compounded quarterly;

(5) Workpapers and a narrative explaining how the refund was allocated to each jurisdictional customer. Where the numbers used to support the allocation are publicly available, a reference to the source must be included. Where the allocation methodology has been approved previously, a reference to the order or tariff provision approving the allocation methodology must be included.

(6) A letter of transmittal containing:

(i) A list of the material enclosed;

(ii) The name and telephone number of a company official who can answer questions regarding the filing;

(iii) A statement of the date the refund was disbursed;

(iv) A reference to the authority by which the refund is made, including the specific subpart of these regulations, an order of the Commission, a provision of the company's tariff, or any other appropriate authority. If a Commission order is referenced, include the citation to the FERC Reports, the date of issuance, and the docket number;

(v) Any requests for waiver. Requests must include a reference to the specific section of the statute, regulations, or the company's tariff from which waiver is sought, and a justification for the waiver.

(7) A certification of service to all affected customers and interested state commissions.

(f) Each report filed under paragraph (e) of this section must be posted no later than the date of filing. Each report must be posted to all recipients of a share of the refund and all state commissions whose jurisdiction includes the location of any recipient of a refund share that have made a standing request for such full report.

(g) Recipients of refunds and state commissions that have not made a standing request for such full report shall receive an abbreviated report consisting of the items listed in § 154.501 (e)(5) and (e)(6).

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 582-A, 61 FR 9629, Mar. 11, 1996]

§ 154.502 Reports.

(a) When the natural gas company is required, either by a Commission order or as a part of a settlement in a proceeding initiated under this part 154 or part 284 of this chapter, to make a report on a periodic basis, details about the nature and contents of the report must be provided in an appropriate section of the general terms and conditions of its tariff.

(b) The details in the general terms and conditions of the tariff must include the frequency and timing of the report. Explain whether the report is filed annually, semi-annually, monthly, or is triggered by an event. If triggered by an event, explain how soon after the event the report must be filed. If the report is periodic, state the dates on which the report must be filed.

(c) Each report must include:

(1) A letter of transmittal containing:

(i) A list of the material enclosed;

(ii) The name and telephone number of a company official who can answer questions regarding the filing;

(iii) A reference to the authority by which the report is made, including the specific subpart of these regulations, an order of the Commission, a provision of the company's tariff, or any other appropriate authority. If a Commission order is referenced, include the citation to the FERC Reports, the date of issuance, and the docket number;

(iv) Any requests for waiver. Requests must include a reference to the specific section of the statute, regulations, or the company's tariff from which waiver is sought, and a justification for the waiver.

(2) A certification of service to all affected customers and interested state commissions.

(d) Each report filed under paragraph (b) of this section must be posted no later than the date of filing.

§ 154.600 Compliance with other subparts.

Any proposal to implement a tariff change other than in rate level must comply with subparts A, B, and C of this part.

§ 154.601 Change in executed service agreement.

Agreements intended to effect a change or revision of an executed service agreement on file with the Commission must be in the form of a superseding executed service agreement only. Service agreements may not contain any supplements, but may contain exhibits which may be separately superseded. The exhibits may show, among other things, contract demand delivery points, delivery pressures, names of industrial customers of the distributor-customer, or names of distributors (with one distributor named as agent where delivery to several distributors is effected at the same delivery points).

§ 154.602 Cancellation or termination of a tariff, executed service agreement or part thereof.

When an effective tariff, contract, or part thereof on file with the Commission, is proposed to be canceled or is to terminate by its own terms and no new tariff, executed service agreement, or part thereof, is to be filed in its place, the natural gas company must notify the Commission of the proposed cancellation or termination , at least 30 days prior to the proposed effective date of such cancellation or termination. With such notice, the company must submit a statement showing the reasons for the cancellation or termination, a list of the affected customers and the contract demand provided to the customers under the service to be canceled. A copy of the notice must be duly posted tariff filing in the electronic format required by § 154.4.

[Order 582, 60 FR 52996, Oct. 11, 1995, as amended by Order 714, 73 FR 57535, Oct. 3, 2008]

§ 154.603 Adoption of the tariff by a successor.

Whenever the tariff or contracts of a natural gas company on file with the Commission is to be adopted by another company or person as a result of an acquisition, or merger, authorized by a certificate of public convenience and necessity, or for any other reason, the succeeding company must file with the Commission, and post within 30 days after such succession, a tariff filing in the electronic format required by § 154.4 bearing the name of the successor company.

[Order 714, 73 FR 57535, Oct. 3, 2008]

§ 156.1 Who may apply.

Any person or municipality as defined in section 2 of the Natural Gas Act engaged or legally authorized to engage in the local distribution of natural or artificial gas to the public may file with the Commission an application pursuant to the provisions of section 7(a) of the Natural Gas Act for an order of the Commission directing a natural gas company to extend or improve its transportation facilities, to establish physical connection of its transportation facilities with the facilities of, and sell natural gas to such person or municipality, and for such purpose to extend its transportation facilities to communities immediately adjacent to such facilities or to territory served by such natural gas company.

§ 156.2 Purpose and intent of rules.

(a) Applications filed pursuant to the provisions of section 7(a) of the Natural Gas Act shall contain all information necessary to advise the Commission fully concerning the applicant, the service which applicant requests the Commission to direct the natural gas company to render together with a description of any improvement or extension of facilities which the natural gas company would be required to make in connection with the rendition of the service, applicant's present and proposed operations, construction, service, and sales together with a description of any extension or improvement of facilities by applicant which would be required to enable applicant to engage in the local distribution of natural gas.

(b) Every requirement of this part shall be considered as an obligation upon the applicant which can be avoided only by a definite and positive showing that the information or data required by the applicable section of the regulations is not necessary to the consideration and ultimate determination of the application.

(c) This part will be strictly applied to all applications as submitted and the burden of adequate presentation in understandable form as well as justification for omitted data or information rests with the applicant.

(d) Under this part, the natural gas company from which applicant is seeking the service is a party respondent to the proceeding.

§ 156.3 Applications; general requirements.

(a) Applicable rules. The application must be filed with the Secretary of the Commission in accordance with filing procedures posted on the Commission's Web site at http://www.ferc.gov. In all other respects applications shall conform to the requirements of §§ 156.1 through 156.5. Amendments to or withdrawals of applications shall be filed in accordance with the requirements of §§ 385.213 and 385.214 of this chapter.

(b) General content of application; filing fee. Except as provided in paragraph (d) of this section, each application shall set forth the following information:

(1) The exact legal name of the applicant; the name of the natural gas company (respondent) from which applicant is seeking an extension or improvement of transportation facilities, physical connection of facilities or service of natural gas together with a concise description of the extension, improvement, physical connection of facilities or service sought from such company including the estimated volumes of natural gas involved to meet annual and maximum day requirements for the estimated first three years of proposed operation.

(2) Applicant's principal place of business; whether applicant is an individual, corporation or municipality as defined in section 2 of the Natural Gas Act; State under the laws of which applicant is incorporated, organized or authorized; and the name, title, and mailing address of the person or persons to whom communications concerning the application are to be addressed.

(3) The facts relied upon by applicant to show that the proposed extension or improvement of transportation facilities, physical connection of facilities or service and sale of natural gas are necessary or desirable in the public interest.

(4) A concise description of applicant's operations, if any, at the time the application is filed.

(5) A concise description of applicant's proposed operations, construction, service and sales together with a description of any extension or improvement of facilities by applicant which would be required to enable applicant to engage in the local distribution of natural gas and including the proposed dates for the beginning and completion of construction and commencement of operations.

(6) A full statement concerning and description of any certificate of public convenience and necessity, franchise or other authorization which applicant has applied for or received from any State commission or municipality covering its proposed operations.

(7) A full statement as to whether any other application must be or is to be filed by applicant with any other Federal or State body, or other political subdivision or agency of a State to enable applicant to engage in the local distribution of natural gas in the territory it proposes to serve.

(8) Each application shall contain a table of contents which shall list all exhibits and documents filed in compliance with §§ 156.1 through 156.2, as well as other documents and exhibits filed therewith, identifying them by their appropriate titles and alphabetical letter designations specified in § 156.5. The alphabetical designation specified in § 156.5 must be adhered to strictly and any additional exhibits submitted on applicant's own volition, pursuant to § 156.5(b) shall be designated in sequence under the letter designation Z (Z1, Z2, Z3, etc.). Together with each exhibit applicant shall set forth a full and complete explanation of the data submitted, the manner in which it was obtained, and the reasons for the conclusions which are derived therefrom.

(c) Incorporation by reference. Any information required by this part which is already on file with the Commission may be incorporated by reference.

(d) Small distributors. A distributor requesting natural gas service of less than 2000 Mcf per day to serve a single community may file the information required by the form of application represented in § 250.6 of this chapter.

[Order 234, 26 FR 4848, June 1, 1961, as amended by Order 280, 29 FR 4875, Apr. 7, 1964; Order 317, 31 FR 432, Jan. 13, 1966; Order 225, 47 FR 19057, May 3, 1982; Order 737, 75 FR 43404, July 26, 2010]

§ 156.4 Form of exhibits to be attached to applications.

(a) General requirements. Each exhibit shall contain a title page showing applicant's name, Docket No. CP- ______ (number designation to be left blank), title of exhibit, and if exhibit consists of 10 or more pages a table of contents citing by page, section number or subdivision the component elements or matters contained therein.

(b) Measurement base. All gas volumes shall be stated upon a uniform basis of measurement, and, in addition, if the uniform basis of measurement used in any application is other than 14.73 p.s.i.a., then the volume or volumes of natural gas to be received from any source and delivered by applicant shall also be stated upon a basis of 14.73 p.s.i.a. Similarly, total volumes on all summary sheets, as well as grand totals of volumes in any exhibit, shall also be stated upon a basis of 14.73 p.s.i.a. if the basis of measurement used is other than 14.73 p.s.i.a.

§ 156.5 Exhibits.

(a) Exhibits to be submitted with application. All of the following exhibits shall be submitted with the application when tendered for filing. Such exhibits may be attached to the application or furnished in a separate volume or separate volumes designated “Exhibits to Application.” Such separate volume or volumes shall indicate on the cover thereof applicant's name and bear Docket No. CP- ______ (number designation to be left blank).

(1) Exhibit A—Articles of incorporation and bylaws. If applicant is not an individual, a conformed copy of its articles of incorporation and bylaws, or other similar documents. One certified copy shall be submitted with the original application.

(2) Exhibit B—State and local authorizations. (i) A copy of any certificate of public convenience and necessity or similar authorization which applicant has obtained from the State commission or commissions of each of the States in which applicant engages or proposes to engage in the local distribution of natural gas; (ii) a copy of any franchise or similar authorization which applicant has obtained from each of the municipalities in which applicant engages or proposes to engage in the local distribution of natural gas; and (iii) a copy of any other authorization or form of consent which applicant has obtained from any State, State commission, municipality or from any agency of the Federal government necessary or incidental to applicant's proposal to engage in the local distribution of natural gas. One certified copy of each of the documents specified in paragraphs (a)(2) (i), (ii), and (iii) of this section shall be submitted as exhibits to the original application.

(3) Exhibit C—Officials. A list of the names and business addresses of applicant's officers and directors, or similar officials if applicant is not a corporation.

(4) Exhibit D—Subsidiaries and affiliation. If applicant or any of its officers or directors, directly or indirectly, owns, controls, or holds with power to vote, 10 percent or more of the outstanding voting securities of any other person or organized group of persons engaged in production, transportation, distribution, or sale of natural gas, or of any person or organized group of persons engaged in the construction or financing of such enterprises or operations, a detailed explanation of each such relationship, including the percentage of voting strength represented by such ownership of securities. If any persons or organized group of persons, directly or indirectly, owns, controls, or holds with power to vote, 10 percent or more of the outstanding voting securities of applicant—give a detailed explanation of each such relationship.

(5) Exhibit F—Location of facilities. A geographical map of suitable scale and detail showing all of the transmission facilities proposed to be installed and operated by Applicant between distribution systems of Applicant and the transmission pipeline system of the proposed supplier (respondent), and include:

(i) Location, length, and size of applicant's transmission pipelines.

(ii) Location and size (related horsepower) of applicant's transmission compressor stations.

(iii) Location and designation of each point of connection of applicant's proposed transmission facilities with (a) proposed pipeline supplier (respondent) main line industrial customers, gas pipeline or distribution systems, showing towns and communities to be served, and (b) gas producing and storage filed, or other sources of supply.

(iv) Location, length and size of facilities required to be installed by the proposed supplier (respondent) necessary for the rendition of service requested by the applicant.

(6) Exhibit G—Flow diagram showing daily design capacity and reflecting operation with proposed transmission facilities. A flow diagram showing daily design capacity of all transmission facilities proposed to be installed and operated by applicant between distribution facilities of applicant and the transmission pipeline system of the proposed supplier (respondent) including the following:

(i) Diameter, wall thickness, and length of pipe to be installed.

(ii) For each transmission compressor station, the size, type, and number of compressor units, horsepower required, horsepower to be installed, volume of gas to be used as fuel, suction and discharge pressures, and compression ratio.

(iii) Pressures and volumes of gas at the main line inlet and outlet connections at each compressor station.

(iv) Pressures and volumes of gas at each intake and takeoff point and at the beginning and terminus of all proposed transmission facilities.

(7) Exhibit G-I—Flow diagram reflecting maximum capabilities. If Exhibit G does not reflect the maximum deliveries of all transmission facilities, proposed to be installed and operated by applicant between distribution facilities of applicant and the transmission pipeline system of the proposed supplier (respondent), under most favorable operating conditions, without installation of any facilities in addition to those proposed in the application, include an additional diagram or diagrams to depict such maximum capabilities.

(8) Exhibit G-II—Flow diagram data. Exhibits G and G-I shall be accompanied by a statement of engineering design data in explanation and support of the diagrams and the proposed project, setting forth:

(i) Assumption, bases, formulae, and methods used in the development and preparation of such diagrams and accompanying data.

(ii) A description of the transmission pipe and fittings to be installed, specifying the diameter, wall thickness, yield point, ultimate tensile strength, method of fabrication, and methods of testing proposed.

(iii) Type, capacity, and location of each natural gas storage field or facility, or other similar plant or facility directly attached to the applicant's transmission system.

(9) Exhibit H—Total gas supply data. A statement of the total gas supply committed to, controlled by, or possessed by an applicant which is available to it for the acts and the services proposed, together with:

(i) The estimated total volume of proven reserves in place for each reservoir in each field from which applicant takes natural gas, giving names and location of fields (state, county, or parish).

(ii) The estimated total volumes of proven reserves available to applicant by fee or under lease, segregated by gas fields and reservoirs thereof, giving names and locations of fields (state, county, or parish).

(iii) The names and addresses of persons with whom applicant has gas purchase contracts, the effective dates and remaining terms in years of such contracts.

(iv) A study, showing the daily volumes of natural gas which can and are proposed to be obtained each year from each source of supply.

(v) Estimate of the Btu content of the gas available to or requested by applicant for proposed service.

(vi) A study of each proposed gas storage field showing: Location; geology; original and present reserves for each reservoir; original and present pressure of each reservoir; proposed top and base storage pressures; proposed top and base gas volumes to be stored; a deliverability study, including daily and annual injection and withdrawal rates and pressures; and maximum daily deliverability and maximum storage capacity under the proposed plan of development.

(vii) This paragraph (a)(9) shall cease to have effect on December 5, 2026, unless the Commission determines that the cessation deadline should be extended to a date not more than 5 years in the future after offering the public an opportunity to provide input on the costs and benefits of this paragraph (a)(9) and considering that input. The Commission will publish a document in the Federal Register announcing its determination and revising or removing this paragraph (a)(9) accordingly.

(10) Exhibit I—Market data. An estimate by distribution systems of the volumes of gas to be delivered during the year in which proposed service is estimated to begin and during each of the first 3 full years of operation of the proposed facilities, and actual data of like import for each of the 3 years next preceding the filing of the application, together with:

(i) Names and locations of areas to be served, showing the number of residential, commercial, firm industrial, interruptible industrial, residential space heating, commercial space heating, and other types of customers for each distribution system to be served; and the names and locations of each firm and interruptible direct industrial customer whose estimated consumption totals 10,000 Mcf or more in any calendar month or 100,000 Mcf or more per year.

(ii) Applicant's total annual and peak day gas requirements by classification of service in paragraph (a)(10)(i) of this section, divided as follows: Gas requirements (a) for each distribution area where gas is sold or to be sold by applicant at retail; (b) for all main-line direct industrial customers and (c) company use and unaccounted-for gas.

(iii) Total past and expected curtailments of service by the applicant in each distribution area proposed to be supplied with gas from the project, all to be listed by the classifications of service as indicated in paragraph (a)(10)(i) of this section.

(iv) Explanation of basic factors used in estimating future requirements, including, for example: Peak day and annual degree day deficiencies, annual load factors of applicant's deliveries to its proposed customers; derivation of numbers of customers proposed to be served; individual consumer peak day and annual consumption factors for each class of consumers, with supporting historical data; forecasted saturation of space heating as related to past experience; and full detail as to all other sources of gas supply available to applicant and to each of its customers, including manufacturing facilities and liquid petroleum gas.

(v) A full description of all facilities, other than transmission facilities, necessary to provide service in the communities to be served.

(vi) A copy of each market survey made within the past 3 years for the markets proposed to be served.

(11) Exhibit J—Conversion to natural gas. If it is assumed that proposed customers in new areas or firm and interruptible direct industrial customers whose estimated consumption totals 10,000 Mcf or more in any calendar month or 100,000 Mcf or more in any calendar year will convert from other fuels to natural gas, state the basis for such assumption and include a study showing estimated cost of converting customers' facilities to natural gas. The study should indicate the number of customers of each of the other fuels who applicant anticipates will convert to natural gas and the current cost of fuel to be displaced compared to the cost of natural gas on an equivalent Btu basis.

(12) Exhibit K—Cost of facilities. A detailed estimate of total capital cost of the proposed facilities involved in the application, showing cost of construction by operating units such as distribution facilities, compressor stations, transmission pipelines and laterals, measuring and regulating stations, and separately stating the cost of rights-of-way, damages, surveys, materials, labor, engineering and inspection, administrative overhead, fees for legal and other services, allowance for funds used during construction, and contingencies. Detailed estimates of cost of facilities required to be installed by the pipeline supplier shall be separately stated.

(13) Exhibit L—Financing. Plans for financing the proposed facilities for which the application is filed, together with:

(i) A detailed description of applicant's outstanding and proposed securities and liabilities, showing amount (face value and number), interest or dividend rate, dates of issue and maturity, voting privileges, and principal terms and conditions applicable to each.

(ii) The manner in which applicant proposes to dispose of securities by private sale, competitive bidding or otherwise; the persons, if known, to whom they will be sold or issued, and evidence that such persons having agreed to purchase the securities, and if not known, the class or classes of such persons.

(iii) A statement showing for each proposed issue, by total amount and by unit, the estimated sale price and estimated net proceeds to the applicant.

(iv) A statement as to the extent to which the applicant will rely on temporary financing in connection with the proposed construction, and statements tending to substantiate the fact that such temporary loans will be made available.

(v) Statement of anticipated cash flow, including provision during the period of construction and the first 3 full years of proposed operation for interest requirements, dividends, and capital retirements.

(vi) Statement showing, over the life of each issue, the annual amount of securities which applicant expects to retire through operation of a sinking fund or other extinguishment of the obligation.

(vii) A balance sheet and income statement (12 months) of most recent date available.

(viii) Comparative pro forma balance sheets and income statements for the period of construction and each of the first 3 full years of operation, giving effect to the proposed construction and proposed financing of the project.

(ix) Any additional data and information upon which applicant proposes to rely in showing the adequacy and availability to it of resources for financing its proposed project.

(14) Exhibit M—Construction, operation, and management. A concise statement setting forth arrangements for supervision, management, engineering, accounting, legal, or other similar service to be rendered in connection with the construction or operation of the project if not to be performed by employees of applicant, including reference to any existing or contemplated agreements therefor.

(15) Exhibit N—Revenues, expenses income. Applicant shall submit pro forma statements for each of the first 3 full years of operation of all the proposed facilities, showing:

(i) Gas system annual revenues and volumes of natural gas related thereto subdivided by classes of service and further subdivided by sales to direct industrial customers, sales to other utilities (if any), transportation for other gas utilities and other sales.

(ii) Gas system annual operating expenses, cost of gas purchased, depreciation, depletion, taxes, utility income and resulting rate of return on net investment in gas plant, including working capital, or in the case of a municipality applicant similar data and amortization-interest schedule for life of each bond issue related to the proposed project. Cost of gas purchased shall be at the currently effective applicable rate of the pipeline supplier or applicable rate filed by such pipeline supplier, but not effective at date of filing, whichever is the higher.

(iii) The information required by paragraphs (a)(15)(i) and (ii) of this section need not be furnished when the applicant furnishes as a part of its application a pro forma copy of a certificate of convenience and necessity or similar authorization issued to it by the local State commission having jurisdiction over its proposed operations.

(16) Exhibit P—Rates. (i) A statement of the rates proposed to be charged for the proposed services to be rendered. Indicate whether rates are subject to regulation by the State or local authorities.

(ii) Identification of the rate schedule of the natural gas company (respondent) under which gas is proposed to be purchased.

(b) Additional exhibits. Applicant shall submit additional exhibits necessary to support or clarify its application. Such exhibits shall be identified and designated as provided by § 156.3(b)(8).

(c) Additional information. Upon request by the Secretary, prior to or during hearing upon the application, applicant shall submit such additional data, information, exhibits, or other detail as may be specified.

[Order 234, 26 FR 4848, June 1, 1961, as amended by Order 280, 29 FR 4876, Apr. 7, 1964; Order 436, 36 FR 15530, Aug. 17, 1971; Order 225, 47 FR 19057, May 3, 1982; Order 914, 90 FR 48403, Oct. 21, 2025]

§ 156.6 Acceptance for filing or rejection of application.

Applications will be docketed when received and the applicant so advised. Any application which does not conform to the requirements of §§ 156.1 through 156.5 will be rejected by the Secretary. All but one copy of a rejected application will be returned. An application which relates to an operation concerning which a prior application has been filed and rejected, shall be docketed as a new application. Such new application shall state the docket number of the prior rejected application.

§ 156.7 Service of application.

After an application has been accepted for filing, the Secretary will cause a copy thereof to be served upon the natural gas company (respondent) against which an order pursuant to section 7(a) of the Natural Gas Act has been requested. The natural gas company shall, within 30 days after the date of service of such application file its answer (an original and 7 conformed copies) to such application in which it shall state whether it has any objection to the grant of the application. If the natural gas company objects to the grant of the relief sought by the application, it shall fully state the grounds and reasons for its objections. The answer shall be verified and shall be signed by an executive of the natural gas company. In the event that the respondent natural gas company fails to file a timely response to the application it shall be deemed to have agreed to the grant thereof.

[Order 302, 30 FR 9302, July 27, 1965, as amended by Order 225, 47 FR 19057, May 3, 1982]

§ 156.8 Notice of application.

Notice of each application filed, except when rejected in accordance with § 156.6, will be published in the Federal Register and copies of such notice sent to the State affected thereby via electronic means if practical, otherwise by mail.

[Order 653, 70 FR 8724, Feb. 23, 2005]

§ 156.9 Protests and interventions.

Notices of applications, as provided by § 156.8 will fix the time within which any person desiring to participate in the proceeding or to file a protest regarding the application, may file a petition to intervene or protest, and within which any interested regulatory agency desiring to intervene may file its notice of intervention. Failure to make timely filing will constitute ground for denial of participation, in the absence of extraordinary circumstances for good cause shown.

§ 156.10 Hearings.

The Commission will schedule each application for public hearing at the earliest possible date giving due consideration of statutory requirements and other matters pending, with notice thereof as provided by § 385.2009 of this chapter: Provided, however, That where no protests or petitions to intervene have been received and accepted, the Commission may, after the due date for such protests or petitions to intervene, issue the requested order without hearing.

[Order 234, 26 FR 4848, June 1, 1961, as amended by Order 225, 47 FR 19057, May 3, 1982]

§ 156.11 Dismissal of application.

Except for good cause shown, failure of an applicant to go forward on the date set for hearing and present its full case in support of its application will constitute ground for the summary dismissal of the application and the termination of the proceedings.

§ 157.1 Definitions.

For the purposes of this part—

For the purposes of § 157.21 of this part, Director means the Director of the Commission's Office of Energy Projects.

Indian tribe means, in reference to a proposal or application for a certificate or abandonment, an Indian tribe which is recognized by treaty with the United States, by federal statute, or by the U.S. Department of the Interior in its periodic listing of tribal governments in the Federal Register in accordance with 25 CFR 83.6(b), and whose legal rights as a tribe may be affected by the proposed construction, operation or abandonment of facilities or services (as where the construction or operation of the proposed facilities could interfere with the tribe's hunting or fishing rights or where the proposed facilities would be located within the tribe's reservation).

Resource agency means a Federal, state, or interstate agency exercising administration over the areas of recreation, fish and wildlife, water resource management, or cultural or other relevant resources of the state or states in which the facilities or services for which a certificate or abandonment is proposed are or will be located.

[Order 608, 64 FR 51220, Sept. 22, 1999, as amended by Order 665, 70 FR 60440, Oct. 18, 2005]

§ 157.5 Purpose and intent of rules.

(a) Applications under section 7 of the Natural Gas Act shall set forth all information necessary to advise the Commission fully concerning the operation, sales, service, construction, extension, or acquisition for which a certificate is requested or the abandonment for which permission and approval is requested. Some applications may be of such character that an abbreviated application may be justified under the provisions of § 157.7. Applications for permission and approval to abandon pursuant to section 7(b) of the Act shall conform to § 157.18 and to such other requirements of this part as may be pertinent. However, every applicant shall file all pertinent data and information necessary for a full and complete understanding of the proposed project, including its effect upon applicant's present and future operations and whether, and at what docket, applicant has previously applied for authorization to serve any portion of the market contemplated by the proposed project and the nature and disposition of such other project.

(b) Every requirement of this part shall be considered as a forthright obligation of the applicant which can only be avoided by a definite and positive showing that the information or data called for by the applicable rules is not necessary for the consideration and ultimate determination of the application.

(c) This part will be strictly applied to all applications as submitted and the burden of adequate presentation in intelligible form as well as justification for omitted data or information rests with the applicant.

[17 FR 7386, Aug. 14, 1952, as amended by Order 280, 29 FR 4876, Apr. 7, 1964]

§ 157.6 Applications; general requirements.

(a) Applicable rules—(1) Submission required to be furnished by applicant under this subpart. Applications, amendments thereto, and all exhibits and other submissions required to be furnished by an applicant to the Commission under this subpart must be submitted in an original and 7 conformed copies. To the extent that data required under this subpart has been provided to the Commission, this data need not be duplicated. The applicant must, however, include a statement identifying the forms and records containing the required information and when that form or record was submitted.

(2) Maps and diagrams. An applicant required to submit a map or diagram under this subpart must submit one paper copy of the map or diagram. This paragraph (a)(2) shall cease to have effect on December 5, 2026, unless the Commission determines that the cessation deadline should be extended to a date not more than 5 years in the future after offering the public an opportunity to provide input on the costs and benefits of this paragraph (a)(2) and considering that input. The Commission will publish a document in the Federal Register announcing its determination and revising or removing this paragraph (a)(2) accordingly.

(3) The following must be submitted in electronic format as prescribed by the Commission:

(i) Applications filed under this part 157 and all attached exhibits;

(ii) Applications covering acquisitions and all attached exhibits;

(iii) Applications for temporary certificates and all attached exhibits;

(iv) Applications to abandon facilities or services and all attached exhibits;

(v) The progress reports required under § 157.20(c) and (d);

(vi) Applications submitted under subpart E of this part and all attached exhibits;

(vii) Applications submitted under subpart F of this part and all attached exhibits;

(viii) Requests for authorization under the notice procedures established in § 157.205 and all attached exhibits;

(ix) The annual report required by § 157.207;

(x) The report required under § 157.214 when storage capacity is increased;

(xi) Amendments to any of the foregoing.

(4) All filings must be signed in compliance with the following.

(i) The signature on a filing constitutes a certification that: The signer has read the filing signed and knows the contents of the paper copies and electronic filing; the paper copies contain the same information as contained in the electronic filing; the contents as stated in the copies and in the electronic filing are true to the best knowledge and belief of the signer; and the signer possesses full power and authority to sign the filing.

(ii) A filing must be signed by one of the following:

(A) The person on behalf of whom the filing is made;

(B) An officer, agent, or employee of the governmental authority, agency, or instrumentality on behalf of which the filing is made; or,

(C) A representative qualified to practice before the Commission under § 385.2101 of this chapter who possesses authority to sign.

(5) Other requirements. Applications under section 7 of the Natural Gas Act must conform to the requirements of §§ 157.5 through 157.14. Amendments to or withdrawals of applications must conform to the requirements of §§ 385.215 and 385.216 of this chapter. If the application involves an acquisition of facilities, it must conform to the additional requirements prescribed in §§ 157.15 and 157.16. If the application involves an abandonment of facilities or service, it must conform to the additional requirements prescribed in § 157.18.

(b) General content of application. Each application filed other than an application for permission and approval to abandon pursuant to section 7(b) shall set forth the following information:

(1) The exact legal name of applicant; its principal place of business; whether an individual, partnership, corporation, or otherwise; State under the laws of which organized or authorized; and the name, title, and mailing address of the person or persons to whom communications concerning the application are to be addressed.

(2) The facts relied upon by applicant to show that the proposed service, sale, operation, construction, extension, or acquisition is or will be required by the present or future public convenience and necessity.

(3) A concise description of applicant's existing operations.

(4) A concise description of the proposed service, sale, operation, construction, extension, or acquisition, including the proposed dates for the beginning and completion of construction, the commencement of operations and of acquisition, where involved.

(5) A full statement as to whether any other application to supplement or effectuate applicant's proposals must be or is to be filed by applicant, any of applicant's customers, or any other person, with any other Federal, State, or other regulatory body; and if so, the nature and status of each such application.

(6) A table of contents which shall list all exhibits and documents filed in compliance with §§ 157.5 through 157.18, as well as all other documents and exhibits otherwise filed, identifying them by their appropriate titles and alphabetical letter designations. The alphabetical letter designations specified in §§ 157.14, 157.16, and 157.18 must be strictly adhered to and extra exhibits submitted at the volition of applicant shall be designated in sequence under the letter Z (Z1, Z2, Z3, etc.).

(7) A form of notice of the application suitable for publication in the Federal Register in accordance with the specifications in § 385.203(d) of this chapter. This paragraph (b)(7) shall cease to have effect on December 5, 2026, unless the Commission determines that the cessation deadline should be extended to a date not more than 5 years in the future after offering the public an opportunity to provide input on the costs and benefits of this paragraph (b)(7) and considering that input. The Commission will publish a document in the Federal Register announcing its determination and revising or removing this paragraph (b)(7) accordingly.

(8) For applications to construct new facilities, detailed cost-of-service data supporting the cost of the expansion project, a detailed study showing the revenue responsibility for each firm rate schedule under the pipeline's currently effective rate design and under the pipeline's proposed rates, a detailed rate impact analysis by rate schedule (including by zone, if applicable), and an analysis reflecting the impact of the fuel usage resulting from the proposed expansion project (including by zone, if applicable).

(c) Requests for shortened procedure. If shortened procedure is desired a request therefor shall be made in conformity with § 385.802 of this chapter and may be included in the application or filed separately.

(d) Landowner notification. (1) For all applications filed under this subpart which include construction of facilities or abandonment of facilities (except for abandonment by sale or transfer where the easement will continue to be used for transportation of natural gas), the applicant shall make a good faith effort to notify all affected landowners and towns, communities, and local, state and federal governments and agencies involved in the project:

(i) By certified or first class mail, sent within 3 business days following the date the Commission issues a notice of the application; or

(ii) By hand, within the same time period; and

(iii) By publishing notice twice of the filing of the application, no later than 14 days after the date that a docket number is assigned to the application, in a daily or weekly newspaper of general circulation in each county in which the project is located.

(2) All affected landowners includes owners of property interests, as noted in the most recent county/city tax records as receiving the tax notice, whose property:

(i) Is directly affected (i.e., crossed or used) by the proposed activity, including all facility sites (including compressor stations, well sites, and all above-ground facilities), rights of way, access roads, pipe and contractor yards, and temporary workspace;

(ii) Abuts either side of an existing right-of-way or facility site owned in fee by any utility company, or abuts the edge of a proposed facility site or right-of-way which runs along a property line in the area in which the facilities would be constructed, or contains a residence within 50 feet of the proposed construction work area;

(iii) Is within one-half mile of proposed compressors or their enclosures or LNG facilities; or

(iv) Is within the area of proposed new storage fields or proposed expansions of storage fields, including any applicable buffer zone.

(3) The notice shall include:

(i) The docket number of the filing;

(ii) The most recent edition of the Commission's pamphlet that explains the Commission's certificate process and addresses the basic concerns of landowners. Except: pipelines are not required to include the pamphlet in notifications of abandonments or in the published newspaper notice. Instead, they should provide the title of the pamphlet and indicate its availability at the Commission's Internet address;

(iii) A description of the applicant and the proposed project, its location (including a general location map), its purpose, and the timing of the project;

(iv) A general description of what the applicant will need from the landowner if the project is approved, and how the landowner may contact the applicant, including a local or toll-free phone number and a name of a specific person to contact who is knowledgeable about the project;

(v) A brief summary of what rights the landowner has at the Commission and in proceedings under the eminent domain rules of the relevant state. Except: pipelines are not required to include this information in the published newspaper notice. Instead, the newspaper notice should provide the Commission's Internet address and the telephone number for the Commission's Office of External Affairs; and

(vi) Information on how the landowner can get a copy of the application from the company or the location(s) where a copy of the application may be found as specified in § 157.10.

(vii) A copy of the Commission's notice of application, specifically stating the date by which timely motions to intervene are due, together with the Commission's information sheet on how to intervene in Commission proceedings. Except: pipelines are not required to include the notice of application and information sheet in the published newspaper notice. Instead, the newspaper notice should indicate that a separate notice is to be mailed to affected landowners and governmental entities.

(4) If the notice is returned as undeliverable, the applicant will make a reasonable attempt to find the correct address and notify the landowner.

(5) Within 30 days of the date the application was filed, applicant shall file an updated list of affected landowners, including information concerning notices that were returned as undeliverable.

(6) If paragraph (d)(3) of this section requires an applicant to reveal Critical Energy Infrastructure Information (CEII), as defined by § 388.113(c) of this chapter, to any person, the applicant shall follow the procedures set out in § 157.10(d).

[17 FR 7386, Aug. 14, 1952]

Editorial Note:For Federal Register citations affecting § 157.6, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 157.7 Abbreviated applications.

(a) General. When the operations sales, service, construction, extensions, acquisitions or abandonment proposed by an application do not require all the data and information specified by this part to disclose fully the nature and extent of the proposed undertaking, an abbreviated application may be filed in the manner prescribed in § 385.2011 of this chapter, provided it contains all information and supporting data necessary to explain fully the proposed project, its economic justification, its effect upon applicant's present and future operations and upon the public proposed to be served, and is otherwise in conformity with the applicable requirements of this part regarding form, manner of presentation, and filing. Such an application shall (1) state that it is an abbreviated application; (2) specify which of the data and information required by this part are omitted; and (3) relate the facts relied upon to justify separately each such omission.

[Order 280, 29 FR 4876, Apr. 7, 1964]

Editorial Note:For Federal Register citations affecting § 157.7, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 157.8 Acceptance for filing or rejection of applications.

Applications will be docketed when received and the applicant so advised.

(a) If an application patently fails to comply with applicable statutory requirements or with applicable Commission rules, regulations, and orders for which a waiver has not been granted, the Director of the Office of Energy Projects or the Director of the Office of Energy Market Regulation may reject the application within 10 business days of filing as provided by § 385.2001(b) of this chapter. This rejection is without prejudice to an applicant's refiling a complete application. However, an application will not be rejected solely on the basis of:

(1) Environmental reports that are incomplete because the company has not been granted access by the affected landowner(s) to perform required surveys; or,

(2) Environmental reports that are incomplete, but where the minimum checklist requirements of part 380, appendix A of this chapter have been met.

(b) An application which relates to an operation, sale, service, construction, extension, acquisition, or abandonment concerning which a prior application has been filed and rejected, shall be docketed as a new application. Such new application shall state the docket number of the prior rejected application.

(c) The Director of the Office of Energy Projects or the Director of the Office of Energy Market Regulation may also reject an application after it has been noticed, at any time, if it is determined that such application does not conform to the requirements of this part.

[Order 603-A, 64 FR 54536, Oct. 7, 1999, as amended by Order 699, 72 FR 45325, Aug. 14, 2007; Order 701, 72 FR 61054, Oct. 29, 2007]

§ 157.9 Notice of application and notice of schedule for environmental review.

(a) Notice of each application filed, except when rejected in accordance with § 157.8, will be issued within 10 business days of filing, and subsequently will be published in the Federal Register and copies of such notice sent to States affected thereby, by electronic means if practical, otherwise by mail. Persons desiring to receive a copy of the notice of every application shall so advise the Secretary.

(b) For each application that will require an environmental assessment or an environmental impact statement, notice of a schedule for the environmental review will be issued within 90 days of the notice of the application, and subsequently will be published in the Federal Register.

[Order 653, 70 FR 8724, Feb. 23, 2005, as amended by Order 687, 71 FR 62920, Oct. 27, 2006]

§ 157.10 Interventions and protests.

(a) Notices of applications, as provided by § 157.9, will fix the time within which any person desiring to participate in the proceeding may file a petition to intervene, and within which any interested regulatory agency, as provided by § 385.214 of this chapter, desiring to intervene may file its notice of intervention.

(1) Any person filing a petition to intervene or notice of intervention shall state specifically whether he seeks formal hearing on the application.

(2) Any person may file to intervene on environmental grounds based on the draft environmental impact statement as stated at § 380.10(a)(1)(i) of this chapter. In accordance with that section, such intervention will be deemed timely as long as it is filed within the comment period for the draft environmental impact statement.

(3) Failure to make timely filing will constitute grounds for denial of participation in the absence of extraordinary circumstances or good cause shown.

(4) Protests may be filed in accordance with § 385.211 of this chapter within the time permitted by any person who does not seek to participate in the proceeding.

(b) A copy of each application, supplement and amendment thereto, including exhibits required by §§ 157.14, 157.16, and 157.18, shall upon request be promptly supplied by the applicant to anyone who has filed a petition for leave to intervene or given notice of intervention.

(1) An applicant is not required to serve voluminous or difficult to reproduce material, such as copies of certain environmental information, to all parties, as long as such material is publicly available in an accessible central location in each county throughout the project area.

(2) An applicant shall make a good faith effort to place the materials in a public location that provides maximum accessibility to the public.

(c) Complete copies of the application must be available in accessible central locations in each county throughout the project area, either in paper or electronic format, within three business days of the date a filing is issued a docket number. Within five business days of receiving a request for a complete copy from any party, the applicant must serve a full copy of any filing on the requesting party. Such copy may exclude voluminous or difficult to reproduce material that is publicly available. Pipelines must keep all voluminous material on file with the Commission and make such information available for inspection at buildings with public access preferably with evening and weekend business hours, such as libraries located in central locations in each county throughout the project area.

(d) Critical Energy Infrastructure Information. (1) If this section requires an applicant to reveal Critical Energy Infrastructure Information (CEII), as defined in § 388.113(c) of this chapter, to the public, the applicant shall omit the CEII from the information made available and insert the following in its place:

(i) A statement that CEII is being withheld;

(ii) A brief description of the omitted information that does not reveal any CEII; and

(iii) This statement: “Procedures for obtaining access to Critical Energy Infrastructure Information (CEII) may be found at 18 CFR 388.113. Requests for access to CEII should be made to the Commission's CEII Coordinator.”

(2) The applicant, in determining whether information constitutes CEII, shall treat the information in a manner consistent with any filings that applicant has made with the Commission and shall to the extent practicable adhere to any previous determinations by the Commission or the CEII Coordinator involving the same or like information.

(3) The procedures contained in §§ 388.112 and 388.113 of this chapter regarding designation of, and access to, CEII, shall apply in the event of a challenge to a CEII designation or a request for access to CEII. If it is determined that information is not CEII or that a requester should be granted access to CEII, the applicant will be directed to make the information available to the requester.

(4) Nothing in this section shall be construed to prohibit any persons from voluntarily reaching arrangements or agreements calling for the disclosure of CEII.

[Order 603-A, 64 FR 54536, Oct. 7, 1999, as amended by Order 643, 68 FR 52095, Sept. 2, 2003]

§ 157.11 Hearings.

(a) General. The Commission will schedule each application for public hearing at the earliest date possible giving due consideration to statutory requirements and other matters pending, with notice thereof as provided by § 1.19(b) of this chapter: Provided, however, That when an application is filed less than fifteen days prior to the commencement of a hearing theretofore ordered on a pending application and seeks authority to serve some or all of the markets sought in such pending application or is otherwise competitive with such pending application, the Commission will not schedule the new application for hearing until it has rendered its final decision on such pending application, except when, on its own motion, or on appropriate application, it finds that the public interest requires otherwise.

(b) Shortened procedure. If no protest or petition to intervene raises an issue of substance, the Commission may upon request of the applicant dispose of an application in accordance with the provisions of § 385.802 of this chapter.

[17 FR 7386, Aug. 14, 1952, as amended by Order 225, 47 FR 19057, May 3, 1982]

§ 157.12 Dismissal of application.

Except for good cause shown, failure of an applicant to go forward on the date set for hearing and present its full case in support of its application will constitute ground for the summary dismissal of the application and the termination of the proceedings.

[17 FR 7386, Aug. 14, 1952]

§ 157.13 Form of exhibits to be attached to applications.

Each exhibit attached to an application must conform to the following requirements:

(a) General requirements. Each exhibit must be submitted in the manner prescribed in §§ 157.6(a) and 385.2011 of this chapter and contain a title page showing applicant's name, docket number (to be left blank), title of the exhibit, the proper letter designation of the exhibit, and, if of 10 or more pages, a table of contents, citing by page, section number or subdivision, the component elements or matters therein contained.

(b) Reference to annual reports and previous applications. An application may refer to annual reports and previous applications filed with the Commission and shall specify the exact pages or exhibit numbers of the filing to which reference is made, including the page numbers in any exhibit to which reference is made. When reference is made to a previous application the docket number shall be stated. No part of a rejected application may be incorporated by reference.

(c) Interdependent applications. When an application considered alone is incomplete and depends vitally upon information in another application, it will not be accepted for filing until the supporting application has been filed. When applications are interdependent, they shall be filed concurrently.

(d) Measurement base. All gas volumes, including gas purchased from producers, shall be stated upon a uniform basis of measurement, and, in addition, if the uniform basis of measurement used in any application is other than 14.73 p.s.i.a., then any volume or volumes delivered to or received from any interstate natural-gas pipeline company shall also be stated upon a basis of 14.73 p.s.i.a.; similarly, total volumes on all summary sheets, as well as grand totals of volumes in any exhibit, shall also be stated upon a basis of 14.73 p.s.i.a. if the uniform basis of measurement used is other than 14.73 p.s.i.a.

[17 FR 7387, Aug. 14, 1952, as amended by Order 185, 21 FR 1486, Mar. 8, 1956; Order 280, 29 FR 4877, Apr. 7, 1964; Order 493, 53 FR 15029, Apr. 27, 1988]

§ 157.14 Exhibits.

(a) To be attached to each application. All exhibits specified must accompany each application when tendered for filing. Together with each exhibit applicant must provide a full and complete explanation of the data submitted, the manner in which it was obtained, and the reasons for the conclusions derived from the exhibits. If the Commission determines that a formal hearing upon the application is required or that testimony and hearing exhibits should be filed, the Secretary will promptly notify the applicant that submittal of all exhibits and testimony of all witnesses to be sponsored by the applicant in support of his case-in-chief is required. Submittal of these exhibits and testimony must be within 20 days from the date of the Secretary's notice, or any other time as the Secretary will specify. Exhibits, except exhibits F, F- 1, G, G-I, and G-II, must be submitted to the Commission on electronic media as prescribed in § 385.2011 of this chapter. Receipt and delivery point information required in various exhibits must be labeled with a location point name and code in conformity with the location name and code the pipeline has adopted in conformance with § 284.13(f) of this chapter. Intervenors and persons becoming intervenors after the date of the Secretary's notice must be advised by the applicant of the afore-specified exhibits and testimony, and must be furnished with copies upon request. If this section requires an applicant to reveal Critical Energy Infrastructure Information (CEII), as defined by § 388.113(c) of this chapter, to any person, the applicant shall follow the procedures set out in § 157.10(d).

(1) Exhibit A—Articles of incorporation and bylaws. If applicant is not an individual, a conformed copy of its articles of incorporation and bylaws, or other similar documents.

(2) Exhibit B—State authorization. For each State where applicant is authorized to do business, a statement showing the date of authorization, the scope of the business applicant is authorized to carry on and all limitations, if any, including expiration dates and renewal obligations. A conformed copy of applicant's authorization to do business in each State affected shall be supplied upon request.

(3) Exhibit C—Company officials. A list of the names and business addresses of applicant's officers and directors, or similar officials if applicant is not a corporation.

(4) Exhibit D—Subsidiaries and affiliation. If applicant or any of its officers or directors, directly or indirectly, owns, controls, or holds with power to vote, 10 percent or more of the outstanding voting securities of any other person or organized group of persons engaged in production, transportation, distribution, or sale of natural gas, or of any person or organized group of persons engaged in the construction or financing of such enterprises or operations, a detailed explanation of each such relationship, including the percentage of voting strength represented by such ownership of securities. If any person or organized group of persons, directly or indirectly, owns, controls, or holds with power to vote, 10 percent or more of the outstanding voting securities of applicant—a detailed explanation of each such relationship.

(5) Exhibit E—Other pending applications and filings. A list of other applications and filings under sections 1, 3, 4 and 7 of the Natural Gas Act filed by the applicant which are pending before the Commission at the time of the filing of an application and which directly and significantly affect the application filed, including an explanation of any material effect the grant or denial of those other applications and filings will have on the application and of any material effect the grant or denial of the application will have on those other applications and filings.

(6) Exhibit F—Location of facilities. Unless shown on Exhibit G or elsewhere, a geographical map of suitable scale and detail showing, and appropriately differentiating between all of the facilities proposed to be constructed, acquired or abandoned and existing facilities of applicant, the operation or capacity of which will be directly affected by the proposed facilities or the facilities proposed to be abandoned. This map, or an additional map, shall clearly show the relationship of the new facilities to the applicant's overall system and shall include:

(i) Location, length, and size of pipelines.

(ii) Location and size (rated horsepower) of compressor stations.

(iii) Location and designation of each point of connection of existing and proposed facilities with:

(A) Main-line industrial customers, gas pipeline or distribution systems, showing towns and communities served and to be served at wholesale and retail, and

(B) Gas-producing and storage fields, or other sources of gas supply.

(7) Exhibit F-I—Environmental report. An environmental report as specified in §§ 380.3 and 380.12 of this chapter. Applicant must submit all appropriate revisions to Exhibit F-I whenever route or site changes are filed. These revisions should identify the locations by mile post and describe all other specific differences resulting from the route or site changes, and should not simply provide revised totals for the resources affected.

(8) Exhibit G—Flow diagrams showing daily design capacity and reflecting operation with and without proposed facilities added. A flow diagram showing daily design capacity and reflecting operating conditions with only existing facilities in operation. A second flow diagram showing daily design capacity and reflecting operating conditions with both proposed and existing facilities in operation. Both flow diagrams shall include the following for the portion of the system affected:

(i) Diameter, wall thickness, and length of pipe installed and proposed to be installed and the diameter and wall thickness of the installed pipe to which connection is proposed.

(ii) For each proposed new compressor station and existing station, the size, type and number of compressor units, horsepower required, horsepower installed and proposed to be installed, volume of gas to be used as fuel, suction and discharge pressures, and compression ratio.

(iii) Pressures and volumes of gas at the main line inlet and outlet connections at each compressor station.

(iv) Pressures and volumes of gas at each intake and take-off point and at the beginning and terminus of the existing and proposed facilities and at the intake or take-off point of the existing facilities to which the proposed facilities are to be connected.

(9) Exhibit G-I—Flow diagrams reflecting maximum capabilities. If Exhibit G does not reflect the maximum deliveries which applicant's existing and proposed facilities would be capable of achieving under most favorable operating conditions with utilization of all facilities, include an additional diagram or diagrams to depict such maximum capabilities. If the horsepower, pipelines, or other facilities on the segment of applicant's system under consideration are not being fully utilized due, e.g., to capacity limitation of connecting facilities or because of the need for standby or spare equipment, the reason for such nonutilization shall be stated.

(10) Exhibit G-II—Flow diagram data. Exhibits G and G-I shall be accompanied by a statement of engineering design data in explanation and support of the diagrams and the proposed project, setting forth:

(i) Assumptions, bases, formulae, and methods used in the development and preparation of such diagrams and accompanying data.

(ii) A description of the pipe and fittings to be installed, specifying the diameter, wall thickness, yield point, ultimate tensile strength, method of fabrication, and methods of testing proposed.

(iii) When lines are looped, the length and size of the pipe in each loop.

(iv) Type, capacity, and location of each natural gas storage field or facility, and of each dehydration, desulphurization, natural gas liquefaction, hydrocarbon extraction, or other similar plant or facility directly attached to the applicant's system, indicating which of such plants are owned or operated by applicant, and which by others, giving their names and addresses.

(v) If the daily design capacity shown in Exhibit G is predicated upon an ability to meet each customer's maximum contract quantity on the same day, explain the reason for such coincidental peak-day design. If the design day capacity shown in Exhibit G is predicated upon an assumed diversity factor, state that factor and explain its derivation.

(vi) The maximum allowable operating pressure of each proposed facility for which a certificate is requested, as permitted by the Department of Transportation's safety standards. The applicant shall certify that it will design, install, inspect, test, construct, operate, replace, and maintain the facilities for which a certificate is requested in accordance with Federal safety standards and plans for maintenance and inspection or shall certify that it has been granted a waiver of the requirements of the safety standards by the Department of Transportation in accordance with the provisions of section 3(e) of the Natural Gas Pipeline Safety Act of 1968. Pertinent details concerning the waiver shall be set forth.

(11) Exhibit H—Total gas supply data. A statement by applicant describing:

(i) Those production areas accessible to the proposed construction that contain sufficient existing or potential gas supplies for the proposed project; and

(ii) How those production areas are connected to the proposed construction.

(iii) This paragraph (a)(11) shall cease to have effect on December 5, 2026, unless the Commission determines that the cessation deadline should be extended to a date not more than 5 years in the future after offering the public an opportunity to provide input on the costs and benefits of this paragraph (a)(11) and considering that input. The Commission will publish a document in the Federal Register announcing its determination and revising or removing this paragraph (a)(11) accordingly.

(12) Exhibit I—Market data. A system-wide estimate of the volumes of gas to be delivered during each of the first 3 full years of operation of the proposed service, sale, or facilities and during the years when the proposed facilities are under construction, and actual data of like import for each of the 3 years next preceding the filing of the application, together with:

(i) Names and locations of customer companies and municipalities, showing the number of residential, commercial, firm industrial, interruptible industrial, residential space-heating, commercial space-heating, and other types of customers for each distribution system to be served at retail or wholesale; and the names and locations of each firm and interruptible direct industrial customer whose estimated consumption totals 10,000 Mcf or more in any calendar month or 100,000 Mcf or more per year together with an explanation of the end use to which each of these industrial customers will put the gas.

(ii) Applicant's total annual and peak day gas requirements by classification of service in paragraph (a)(11)(i) of this section, divided as follows: Gas requirements for each distribution area where gas is sold by applicant at retail; for each wholesale customer; for all main line direct industrial customers; and company use and unaccounted-for gas, for both the applicant and each wholesale customer.

(iii) Total past and expected curtailments of service by the applicant and each wholesale customer proposing to receive new or additional supplies of gas from the project, all to be listed by the classifications of service in paragraph (a)(12)(i) of this section.

(iv) Explanation and derivation of basic factors used in estimating future requirements, including, for example: Peak-day and annual degree-day deficiencies, annual load factors of applicant's system and of its deliveries to its proposed customers; individual consumer peak-day and annual consumption factors for each class of consumers, with supporting historical data; forecasted saturation of space-heating as related to past experience; and full detail as to all other sources of gas supply available to applicant and to each of its customers, including manufacturing facilities and liquid petroleum gas.

(v) Conformed copy of each contract, letter of intent or other agreement for sale or transportation of natural gas proposed by the application. Indicate the rate to be charged. If no agreements have been made, indicate the basis for assuming that contracts will be consummated and that service will be rendered under the terms contemplated in the application.

(vi) A full description of all facilities, other than those covered by the application, necessary to provide service in the communities to be served, the estimated cost of such facilities, by whom they are to be constructed, and evidence of economic feasibility.

(vii) A copy of each market survey made within the past three years for such markets as are to receive new or increased service from the project applied for.

(viii) A statement showing the franchise rights of applicant or other person to distribute gas in each community in which service is proposed.

(ix) When an application requires a statement of total peak-day or annual market requirements of affiliates, whose operations are integrated with those of applicant, to demonstrate applicant's ability to provide the service proposed or to establish a gas supply, estimates and data required by this paragraph (a)(12)(ix) shall also be stated in like detail for such affiliates.

(x) When the proposed project is for service which would not decrease the life index of the total system gas supply by more than one year, the data required in paragraphs (a)(12)(i) to (ix), inclusive, of this section need be submitted only as to the particular market to receive new or additional service.

(13) Exhibit J—Federal authorizations. A statement identifying each Federal authorization that the proposal will require; the Federal agency or officer, or State agency or officer acting pursuant to delegated Federal authority, that will issue each required authorization; the date each request for authorization was submitted; why any request was not submitted and the date submission is expected; and the date by which final action on each Federal authorization has been requested or is expected.

(14) Exhibit K—Cost of facilities. A detailed estimate of total capital cost of the proposed facilities for which application is made, showing cost of construction by operating units such as compressor stations, main pipelines, laterals, measuring and regulating stations, and separately stating the cost of right-of-way, damages, surveys, materials, labor, engineering and inspection, administrative overhead, fees for legal and other services, allowance for funds used during construction, and contingencies. Include a brief statement indicating the source of information used as the basis for the above estimate. If not otherwise set forth, submit data on preliminary bids, if any, for the proposed facilities and recent experienced cost data for facilities of similar character.

(15) Exhibit L—Financing. Plans for financing the proposed facilities for which the application is filed, together with:

(i) A description of the class (e.g., commercial paper, long-term debt, preferred stock) and cost rates for securities expected to be issued with construction period and post- operational sources of financing separately identified.

(ii) Statement of anticipated cash flow, including provision during the period of construction and the first 3 full years of operation of proposed facilities for interest requirements, dividends, and capital requirements.

(iii) A balance sheet and income statement (12 months) of most recent data available.

(iv) Comparative pro forma balance sheets and income statements for the period of construction and each of the first 3 full years of operation, giving effect to the proposed construction and proposed financing of the project.

(v) Any additional data and information upon which applicant proposes to rely in showing the adequacy and availability of resources for financing its proposed project.

(vi) In instances for which principal operations of the company have not commenced or where proposed rates for services are developed on an incremental basis, a brief statement explaining how the applicant will determine the actual allowance for funds used during construction (AFUDC) rate, or if a rate is not to be used, how the applicant will determine the actual amount of AFUDC to be capitalized as a component of construction cost, and why the method is appropriate under the circumstances.

(16) Exhibit M—Construction, operation, and management. A concise statement setting forth arrangements for supervision, management, engineering, accounting, legal, or other similar service to be rendered in connection with the construction or operation of the project, if not to be performed by employees of applicant, including reference to any existing or contemplated agreements therefor, together with:

(i) A statement showing affiliation between applicant and any parties to such agreements or arrangements. See Exhibit D, paragraph (a)(4) of this section.

(ii) Conformed copies of all construction, engineering, management, and other similar service agreements or contracts in any way operative with respect to construction, operation, or financing of facilities which are the subject of the application or will be applicable under system operations.

(17) Exhibit N—Revenues—Expenses—Income. When the estimated revenues and expenses related to a proposed facility will significantly affect the operating revenues or operating expenses of an applicant, there shall be submitted a system-wide statement for the last year preceding the proposed construction or service and pro forma system-wide and incremental statements for each of the first three full years of operation of the proposed facilities, showing:

(i) Gas system annual revenues and volumes of natural gas related thereto, subdivided by classes of service, and further subdivided by sales to direct industrial customers, sales to other gas utilities, and other sales, indicating billing quantities used for computing charges, e.g., actual demands, billing demands, volumes, heat-content adjustment or other determinants. In addition, if enlargement or extension of facilities is involved, the revenues attributable solely to the proposed facilities shall be stated separately, and the basis and data used in such computation shall be clearly shown.

(ii) Gas system annual operating expenses classified in accordance with the Commission's Uniform System of Accounts for Natural Gas Companies; the annual depreciation, depletion, taxes, utility income, and resulting rate of return on net investment in gas plant including working capital. In addition if enlargement or extension of facilities is involved, the cost of service attributable solely to the proposed facilities shall be stated separately with supporting data.

(iii) When the data required in paragraphs (a)(17)(i) and (ii) of this section is not submitted, applicant shall provide in lieu thereof a statement in sufficient detail to show clearly the effect on the operating revenues and operating expenses of the estimated revenues and expenses related to the proposed facility.

(18) Exhibit O—Depreciation and depletion. Depreciation and depletion rates to be established, the method of determination and the justification therefor.

(19) Exhibit P—Tariff. (i) A statement of the rates to be charged for the proposed sales or service, including:

(A) Identification of the applicable presently effective rate schedules, when no additional tariff filings will be required, or

(B) When changes are required in applicant's presently effective tariff, or if applicant has no tariff, pro forma copies of appropriate changes in or additions to the effective tariff or a pro forma copy of the new gas tariff proposed, or

(C) When a new rate is proposed, a statement explaining the basis used in arriving at the proposed rate. Such statement shall clearly show whether such rate results from negotiation, cost-of-service determination, competitive factors or others, and shall give the nature of any studies which have been made in connection therewith.

(ii) When new rates or changes in present rates are proposed or when the proposed facilities will result in a material change in applicant's average cost of service, such statement shall be accompanied by supporting data showing:

(A) System cost of service for the first calendar year of operation after the proposed facilities are placed in service.

(B) An allocation of such costs to each particular service classification, with the basis for each allocation clearly stated.

(C) The proposed rate base and rate of return.

(D) Gas operating expenses, segregated functionally by accounts.

(E) Depletion and depreciation.

(F) Taxes with the basis upon which computed.

(b) Additional exhibits. Applicant shall submit additional exhibits necessary to support or clarify its application. Such exhibits shall be identified and designated as provided by § 157.6(b)(6).

(c) Additional information. Upon request by the Secretary, prior to or during hearing upon the application, applicant shall submit such additional data, information, exhibits, or other detail as may be specified. An original and 7 conformed copies of such additional information shall be furnished to the Commission. The Commission reserves the right to request additional copies.

(d) Availability of Commission staff for advice prior to formal filing. Prior to filing an application, any person may informally confer with the staff of the Commission to obtain advice on any problem of statement or presentation of an application or any part thereof.

[17 FR 7387, Aug. 14, 1952]

Editorial Note:For Federal Register citations affecting § 157.14, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 157.15 Requirements for applications covering acquisitions.

An application for a certificate authorizing acquisition of facilities, in addition to complying with the applicable provisions of §§ 157.5 through 157.14, shall include a statement showing:

(a) The exact legal name of the vendor, lessor, or other party in interest (hereinafter referred to as “vendor”) the State or other laws under which vendor was organized, location of vendor's principal place of business, and a description of the business, operation or property of vendor covered by the application.

(b) Any certificate from the Commission, held by vendor, relating directly to the facilities which applicant seeks to acquire, citing the order, date thereof, docket designation, and title of the proceeding; reference to and designation of any companion applications by vendor for permission and approval pursuant to section 7(b) of the Natural Gas Act.

(c) The manner in which the facilities are to be acquired, the consideration to be paid, the method of arriving at the amount thereof, and anticipated expenses in addition to the consideration.

(d) The facilities to be acquired, their present use, their proposed use after acquisition, and whether they constitute all of vendor's facilities.

(e) Any franchise, license, or permit respecting the facilities involved, showing expiration date thereof, and the effect of the proposed acquisition thereon.

[17 FR 7389, Aug. 14, 1952]

§ 157.16 Exhibits relating to acquisitions.

In addition to the exhibits required by § 157.14, every application involving acquisition of facilities must be accompanied by the exhibits listed below. Together with each exhibit applicant must provide a full and complete explanation of the data submitted, the manner in which it was obtained, and the reasons for the conclusions derived from the exhibits, unless the applicant includes a statement identifying the schedule and rate containing the required information and data filed as prescribed in § 385.2011 of this chapter. If the Commission determines that a formal hearing upon the application is required or that testimony and hearing exhibits should be filed, the Secretary will promptly notify the applicant that submittal of all the exhibits and testimony of all witnesses to be sponsored by the applicant in support of his case-in-chief is required. Submittal of these exhibits and testimony must be within 20 days from the date of the Secretary's notice, or any other time specified by the Secretary in the notice. Sections 157.6(a) and 385.2011 of this chapter will govern the submissions required to be furnished to the Commission. Interveners and persons becoming interveners after the date of the Secretary's notice must be advised by the applicant of the afore-specified exhibits and testimony, and must be furnished with copies upon request. If this section requires an applicant to reveal Critical Energy Infrastructure Information (CEII), as defined by § 388.113(c) of this chapter, to any person, the applicant shall follow the procedures set out in § 157.10(d).

(a) Exhibit Q—Effect of acquisition on existing contracts and tariffs. A statement showing the effect of the proposed transaction upon any agreements for the purchase, sale, or interchange of natural gas, and upon any rate schedules or tariffs on file with this Commission, together with pro forma rate schedule sheets, notices of cancellation, or other tariff filings required to be made with this Commission.

(b) Exhibit R—Acquisition contracts. A summary statement of all contracts, agreements or undertakings relating to the proposed acquisition, including:

(1) A conformed copy of each contract or other agreement covering or relating to the acquisition of the facilities.

(2) The names and addresses of all persons employed or to be employed concerning the transaction, including engineering, financial accounting, legal, or other services, and the compensation, fees, or other payments, paid or payable, to such persons.

(3) A disclosure of affiliation between applicant and vendor or between either of them and any other party in interest in the proposed acquisition. See Exhibit D, § 157.14(a)(4).

(c) Exhibit S—Accounting. A statement showing:

(1) The amounts recorded upon the books of the vendor, as being applicable to the facilities to be acquired, and the related depreciation, depletion, and amortization reserves. Include a brief statement explaining the basis or methods used to derive the related depreciation, depletion and amortization reserves.

(2) The original cost of the facilities to be acquired, segregated by accounts prescribed in the Commission's Uniform System of Accounts for Natural Gas Companies; the method by which the original cost was determined; and whether such statement of original cost has been approved by any regulatory body.

(3) If the original cost has not been determined, an estimate thereof, based upon records or data of vendor or its predecessors, together with an explanation of the manner in which such estimate was made and the name and address of the present custodian of all existing pertinent records and data.

(4) The depreciation, depletion, and amortization reserve requirements applicable to the original cost of the facilities to be acquired, estimated service lives, the approximate average age of the facilities to which the depreciation reserve applies, the amortization period, and the depletion rates and estimated gas reserves upon which accruals to the depletion reserve are based.

(5) The amount at which applicant proposes to record the facilities upon its books; the amount of the original cost to be recorded, the depreciation, depletion, and amortization reserves; and the acquisition adjustments, if any, together with applicant's proposed disposition of all adjustments.

(6) Duplicate facilities to be acquired and retired, property which must be extensively rehabilitated, including a clear description of such property, the additional costs to be incurred, and the accounting therefor proposed.

(7) A balance sheet of the company to be acquired as of the most recent date available, if the acquisition involved is by purchase of capital stock and liquidation of the acquired company.

(8) A pro forma consolidating balance sheet, as of the date of the merger if the acquisition is by merger, showing the merging of the accounts and the adjustments relating thereto.

[17 FR 7389, Aug. 14, 1952, as amended by Order 493, 53 FR 15029, Apr. 27, 1988; Order 603, 64 FR 26605, May 14, 1999; Order 643, 68 FR 52096, Sept. 2, 2003]

§ 157.17 Applications for temporary certificates in cases of emergency.

In cases of emergency and pending the determination of any application on file with the Commission for a certificate of public convenience and necessity pursuant to section 7 of the Natural Gas Act, application may be made for a temporary certificate authorizing the construction and operation of extensions of existing facilities, interconnections of pipeline systems, or sales of natural gas that may be required to assure maintenance of adequate service, or to service particular customers. This application must be submitted in the manner prescribed in §§ 157.6(a) and 385.2011 of this chapter.

(a) Whenever the waiver provisions of § 385.2011 of this chapter apply, the application must be submitted in writing, must be subscribed and verified by a responsible officer of applicant having knowledge of the facts, and must state clearly and specifically the exact character of the emergency, the proposed method of meeting it, and the facts claimed to warrant issuance of a temporary certificate.

(b) The application must be submitted on electronic media as prescribed in § 385.2011 of this chapter, must be subscribed and verified by a responsible officer of applicant having knowledge of the facts, and must state clearly and specifically the exact character of the emergency, the proposed method of meeting it, and the facts claimed to warrant issuance of a temporary certificate.

[Order 493, 53 FR 15029, Apr. 27, 1988, as amended by Order 493-B, 53 FR 49653, Dec. 9, 1988; Order 603, 64 FR 26606, May 14, 1999]

§ 157.18 Applications to abandon facilities or service; exhibits.

Applications for an order authorizing abandonment of facilities or service pursuant to section 7(b) of the Natural Gas Act must contain a statement providing in detail the reasons for the abandonment and must contain the exhibits listed below, unless the applicant includes a statement identifying the schedule and rate containing the required information and data filed as prescribed in § 385.2011 of this chapter. Any application for an abandonment that is not excluded by § 380.4(a)(28) or (29), must include an environmental report as specified by § 380.3(c)(2). Sections 157.6(a) and 385.2011 of this chapter will govern the submission of applications and exhibits required to be furnished. Together with each exhibit, applicant must provide a full and complete explanation of the data submitted, the manner in which it was obtained, and the reasons for the conclusions derived from the data. The Secretary may, in addition, require that the testimony of all witnesses to be presented by the applicant be filed together with all exhibits upon which applicant will base its case-in-chief.

(a) Exhibit T—Related applications. A statement showing:

(1) The docket numbers of the prior proceedings in which the facilities or services sought to be abandoned were certificated.

(2) The docket numbers of related applications pending before or which have been authorized by the Commission with an explanation of the interrelationship of those applications with the instant application.

(b) Exhibit U—Contracts and other agreements. A conformed copy of each contract or other agreement pertaining directly or indirectly to the abandonment of facilities or service, including all agreements which influenced applicant to seek the abandonment and all agreements which are dependent upon the approval of the proposed abandonment.

(c) Exhibit V—Flow diagram showing daily design capacity and reflecting operation of applicant's system after abandonment. Receipt and delivery point information required in various exhibits must be labeled with a location point name and code in accordance with the location name and code the pipeline has adopted in conformance with § 284.13(f) of this chapter. A flow diagram showing daily design capacity and reflecting operating conditions of applicant's system after abandonment of facilities on that segment of the system affected by the abandonment, including the following:

(1) Diameter, wall thickness, and length of pipe remaining.

(2) For each remaining compressor station, the size, type and number of compressor units, horsepower required, horsepower installed, volume of gas to be used as fuel, suction and discharge pressures, and compression ratio.

(3) Pressures and volumes of gas at the main line inlet and outlet connections at each compressor station.

(4) Pressures and volumes of gas at each intake and takeoff point and at the beginning and terminus of all remaining facilities.

(d) Exhibit W—Impact on customers whose service will be terminated. A statement indicating the availability of natural gas from other sources to applicant's customers whose service will be terminated by the abandonment and a statement showing the economic effect of the abandonment on applicant's customers. If no other natural gas is available, indicate the availability of other fuels to those customers and explain why the abandonment of service to each customer is permitted by the public convenience and necessity.

(e) Exhibit X—Effect of the abandonment on existing tariffs. A statement showing the effect of the proposed abandonment upon any rate schedules or tariffs on file with this Commission, together with pro forma rate schedule sheets, notices of cancellation, or other tariff filings required to be made with this Commission.

(f) Exhibit Y—Accounting treatment of abandonment. Concisely describe the changes of property, indicating the cost of property to be abandoned in place, the cost of property to be removed and salvaged, the proposed disposition of salvaged material, and a description of equipment to be relocated setting forth its cost, its proposed new location, and the extent of rehabilitation required. Include the information required below.

(1) State the proposed accounting treatment for property changes, showing, for example, retirements by primary plant accounts, cost of removal, salvage realized for materials and equipment sold, original cost of reusable materials and equipment recovered (see Account 154 of the Uniform System of Accounts), and maintenance costs for reconditioning of reusable materials and equipment.

(2) If the abandonment will be by sale of property, describe the property to be sold, together with the proposed accounting treatment as required by paragraph F of Gas Plant Instruction 5 of the Uniform System of Accounts. Include a brief statement explaining the basis or methods used to derive the accumulated depreciation related to the property to be disposed of. Applicant may use pro forma accounting entries based on estimated amounts, provided that upon consummation of the sale he must file proposed accounting entries in conformity with the requirements of the Uniform System of Accounts. If the proposed sale will result in a taxable gain to the applicant, indicate the amount of federal and state income taxes to be allocated to the gain. If no allocation is to be made, explain the reasons.

(3) State the amount of accumulated deferred income taxes attributable to the property to be abandoned and the tax basis of the property. Indicate the proposed accounting treatment of those accumulated deferred taxes.

(g) Exhibit Z—Location of facilities. Unless shown on Exhibit V or elsewhere, a geographic map of suitable scale and detail showing, and appropriately differentiating between, all of the facilities proposed to be abandoned and the other existing facilities of applicant, the operation or capacity of which will be directly affected by the facilities to be abandoned. This map shall clearly show the relationship of the facilities to be abandoned to the applicant's overall system and shall include:

(1) Location, length and size of pipelines.

(2) Location and size (rated horsepower) of compressor stations.

(3) Location and designation of each point of connection of existing facilities with (i) main line industrial and other consumers, pipeline or distribution companies and municipalities, indicating towns and communities served at wholesale or retail and (ii) gas-producing and storage fields, or other sources of gas supply. Designate on the map those facilities and services proposed to be abandoned.

[Order 280, 29 FR 4879, Apr. 7, 1964, as amended by Order 295, 30 FR 4130, Mar. 30, 1965; Order 493, 53 FR 15029, Apr. 27, 1988; Order 603, 64 FR 26606, May 14, 1999; Order 587-W, 80 FR 67312, Nov. 2, 2015]

§ 157.20 General conditions applicable to certificates.

Such of the following terms and conditions, among others, as the Commission shall find is required by the public convenience and necessity, shall attach to the issuance of each certificate and to the exercise of the rights granted thereunder.

(a) The certificate shall be void and without force or effect unless accepted in writing by applicant within 30 days from the issue date of the order issuing such certificate: Provided, however, That when an application for rehearing of such order is filed in accordance with section 19 of the Natural Gas Act, such acceptance shall be filed within 30 days from the issue date of the order of the Commission upon the application for rehearing or within 30 days from the date on which such application may be deemed to have been denied when the Commission has not acted on such application within 30 days after it has been filed: Provided further, That when a petition for review is filed in accordance with the provisions of section 19 of the Natural Gas Act, such acceptance shall be filed within 30 days after final disposition of the judicial review proceedings thus initiated.

(b) Any authorized construction, extension, or acquisition shall be completed and made available for service by applicant and any authorized operation, service, or sale shall be available for regular performance by applicant within (period of time to be specified by the Commission in each order) from the issue date of the Commission's order issuing the certificate. Applicant shall notify the Commission in writing no later than 10 days after expiration of this time period that the end-user/shipper is unable to meet the imposed timetable to commence service.

(c) Applicant must file with the Commission, in writing and under oath, an original and four conformed copies, as prescribed in § 385.2011 of this chapter and, upon request must furnish an intervener with a single copy, of the following:

(1) Within ten days after the bona fide beginning of construction, notice of the date of such beginning;

(2) Within ten days after authorized facilities have been constructed and placed in service or any authorized operation, sale, or service has commenced, notice of the date of such placement and commencement and

(3) Within six months after authorized facilities have been constructed, a statement showing, on the basis of all costs incurred to that date and estimated to be incurred for final completion of the project, the cost of constructing authorized facilities, such total costs to be classified according to the estimates submitted in the certificate proceeding and compared therewith and any significant differences explained.

(d) With respect to an acquisition authorized by the certificate, applicant must file with the Commission, in writing and under oath, an original and four conformed copies as prescribed in § 385.2011 of this chapter the following:

(1) Within 10 days after acquisition and the beginning of authorized operations, notice of the dates of acquisition and the beginning of operations; and

(2) Within 10 days after authorized facilities have been constructed and within 10 days after such facilities have been placed in service or any authorized operation, sale, or service has commenced, notice of the date of such completion, placement, and commencement, and

(e) The certificate issued to applicant is not transferable in any manner and shall be effective only so long as applicant continues the operations authorized by the order issuing such certificate and in accordance with the provisions of the Natural Gas Act, as well as applicable rules, regulations, and orders of the Commission.

(f) In the interest of safety and reliability of service, facilities authorized by the certificate shall not be operated at pressures exceeding the maximum operating pressure set forth in Exhibit G-II to the application as it may be amended prior to issuance of the certificate. In the event the applicant thereafter wishes to change such maximum operating pressure it shall file an appropriate petition for amendment of the certificate. Such petition shall include the reasons for the proposed change. Nothing contained herein authorizes a natural gas company to operate any facility at a pressure above the maximum prescribed by state law, if such law requires a lower pressure than authorized hereby.

(Sec. 20, 52 Stat. 832; 15 U.S.C. 717s)

[17 FR 7389, Aug. 14, 1952, as amended by Order 280, 29 FR 4879, Apr. 7, 1964; Order 317, 31 FR 432, Jan. 13, 1966; Order 324, 31 FR 9348, July 8, 1966; Order 493, 53 FR 15030, Apr. 27, 1988; Order 493-B, 53 FR 49653, Dec. 9, 1988; Order 603, 64 FR 26606, May 14, 1999]

§ 157.21 Pre-filing procedures and review process for LNG terminal facilities and other natural gas facilities prior to filing of applications.

(a) LNG terminal facilities and related jurisdictional natural gas facilities. A prospective applicant for authorization to site, construct and operate facilities included within the definition of “LNG terminal,” as defined in § 153.2(d), and any prospective applicant for related jurisdictional natural gas facilities must comply with this section's pre-filing procedures and review process. These mandatory pre-filing procedures also shall apply when the Director finds in accordance with paragraph (e)(2) of this section that prospective modifications to an existing LNG terminal are modifications that involve significant state and local safety considerations that have not been previously addressed. Examples of such modifications include, but are not limited to, the addition of LNG storage tanks; increasing throughput requiring additional tanker arrivals or the use of larger vessels; or changing the purpose of the facility from peaking to base load. When a prospective applicant is required by this paragraph to comply with this section's pre-filing procedures:

(1) The prospective applicant must make a filing containing the material identified in paragraph (d) of this section and concurrently file a Letter of Intent pursuant to 33 CFR 127.007, and a Preliminary Waterway Suitability Assessment (WSA) with the U.S. Coast Guard (Captain of the Port/Federal Maritime Security Coordinator). The latest information concerning the documents to be filed with the Coast Guard should be requested from the U.S. Coast Guard. For modifications to an existing or approved LNG terminal, this requirement can be satisfied by the prospective applicant's certifying that the U.S. Coast Guard did not require such information.

(2) An application:

(i) Shall not be filed until at least 180 days after the date that the Director issues notice pursuant to paragraph (e) of this section of the commencement of the prospective applicant's pre-filing process; and

(ii) Shall contain all the information specified by the Commission staff after reviewing the draft materials filed by the prospective applicant during the pre-filing process, including required environmental material in accordance with the provisions of part 380 of this chapter, “Regulations Implementing the National Environmental Policy Act.”

(3) The prospective applicant must provide sufficient information for the pre-filing review of any pipeline or other natural gas facilities, including facilities not subject to the Commission's Natural Gas Act jurisdiction, which are necessary to transport regassified LNG from the subject LNG terminal facilities to the existing natural gas pipeline infrastructure.

(b) Other natural gas facilities. When a prospective applicant for authorization for natural gas facilities is not required by paragraph (a) of this section to comply with this section's pre-filing procedures, the prospective applicant may file a request seeking approval to use the pre-filing procedures.

(1) A request to use the pre-filing procedures must contain the material identified in paragraph (d) of this section unless otherwise specified by the Director as a result of the Initial Consultation required pursuant to paragraph (c) of this subsection; and

(2) If a prospective applicant for non-LNG terminal facilities is approved to use this section's pre-filing procedures:

(i) The application will normally not be filed until at least 180 days after the date that the Director issues notice pursuant to paragraph (e)(3) of this section approving the prospective applicant's request to use the pre-filing procedures under this section and commencing the prospective applicant's pre-filing process. However, a prospective applicant approved by the Director pursuant to paragraph (e)(3) of this section to undertake the pre-filing process is not prohibited from filing an application at an earlier date, if necessary; and

(ii) The application shall contain all the information specified by the Commission staff after reviewing the draft materials filed by the prospective applicant during the pre-filing process, including required environmental material in accordance with the provisions of part 380 of this chapter, “Regulations Implementing the National Environmental Policy Act.”

(c) Initial consultation. A prospective applicant required or potentially required or requesting to use the pre-filing process must first consult with the Director on the nature of the project, the content of the pre-filing request, and the status of the prospective applicant's progress toward obtaining the information required for the pre-filing request described in paragraph (d) of this section. This consultation will also include discussion of the specifications for the applicant's solicitation for prospective third-party contractors to prepare the environmental documentation for the project, and whether a third-party contractor is likely to be needed for the project.

(d) Contents of the initial filing. A prospective applicant's initial filing pursuant to paragraph (a)(1) of the section for LNG terminal facilities and related jurisdictional natural gas facilities or paragraph (b)(1) of this section for other natural gas facilities shall include the following information:

(1) A description of the schedule desired for the project including the expected application filing date and the desired date for Commission approval.

(2) For LNG terminal facilities, a description of the zoning and availability of the proposed site and marine facility location.

(3) For natural gas facilities other than LNG terminal facilities and related jurisdictional natural gas facilities, an explanation of why the prospective applicant is requesting to use the pre-filing process under this section.

(4) A detailed description of the project, including location maps and plot plans to scale showing all major plant components, that will serve as the initial discussion point for stakeholder review.

(5) A list of the relevant federal and state agencies in the project area with permitting requirements. For LNG terminal facilities, the list shall identify the agency designated by the governor of the state in which the project will be located to consult with the Commission regarding state and local safety considerations. The filing shall include a statement indicating:

(i) That those agencies are aware of the prospective applicant's intention to use the pre-filing process (including contact names and telephone numbers);

(ii) Whether the agencies have agreed to participate in the process;

(iii) How the applicant has accounted for agency schedules for issuance of federal authorizations; and

(iv) When the applicant proposes to file with these agencies for their respective permits or other authorizations.

(6) A list and description of the interest of other persons and organizations who have been contacted about the project (including contact names and telephone numbers).

(7) A description of what work has already been done, e.g., contacting stakeholders, agency consultations, project engineering, route planning, environmental and engineering contractor engagement, environmental surveys/studies, and open houses. This description shall also include the identification of the environmental and engineering firms and sub-contractors under contract to develop the project.

(8) For LNG terminal projects, proposals for at least three prospective third-party contractors from which Commission staff may make a selection to assist in the preparation of the requisite NEPA document.

(9) For natural gas facilities other than LNG terminal facilities and related jurisdictional natural gas facilities, proposals for at least three prospective third-party contractors from which Commission staff may make a selection to assist in the preparation of the requisite NEPA document, or a proposal for the submission of an applicant-prepared draft Environmental Assessment as determined during the initial consultation described in paragraph (c) of this section.

(10) Acknowledgement that a complete Environmental Report and complete application are required at the time of filing.

(11) A description of a Public Participation Plan which identifies specific tools and actions to facilitate stakeholder communications and public information, including a project website and a single point of contact. This plan shall also describe how the applicant intends to respond to requests for information from federal and state permitting agencies, including, if applicable, the governor's designated agency for consultation regarding state and local safety considerations with respect to LNG facilities.

(12) Certification that a Letter of Intent and a Preliminary WSA have been submitted to the U.S. Coast Guard or, for modifications to an existing or approved LNG terminal, that the U.S. Coast Guard did not require such information.

(e) Director's notices. (1) When the Director finds that a prospective applicant for authority to site and construct a new LNG terminal has adequately addressed the requirements of paragraphs (a), (c) and (d) of this section, the Director shall issue a notice of such finding. Such notice shall designate the third-party contractor. The pre-filing process shall be deemed to have commenced on the date of the Director's notice, and the date of such notice shall be used in determining whether the date an application is filed is at least 180 days after commencement of the pre-filing process.

(2) When the Director finds that a prospective applicant for authority to make modifications to an existing or approved LNG terminal has adequately addressed the requirements of paragraphs (a), (c) and (d) of this section, the Director shall issue a notice making a determination whether prospective modifications to an existing LNG terminal shall be subject to this section's pre-filing procedures and review process. Such notice shall designate the third-party contractor, if appropriate. If the Director determines that the prospective modifications are significant modifications that involve state and local safety considerations, the Director's notice will state that the pre-filing procedures shall apply, and the pre-filing process shall be deemed to have commenced on the date of the Director's notice in determining whether the date an application is filed is at least 180 days after commencement of the pre-filing process.

(3) When a prospective applicant requests to use this section's pre-filing procedures and review for facilities not potentially subject to this section's mandatory requirements, the Director shall issue a notice approving or disapproving use of the pre-filing procedures of this section and determining whether the prospective applicant has adequately addressed the requirements of paragraphs (b), (c) and (d) of this section. Such notice shall designate the third-party contractor, if appropriate. The pre-filing process shall be deemed to have commenced on the date of the Director's notice, and the date of such notice shall be used in determining whether the date an application is filed is at least 180 days after commencement of the pre-filing process.

(f) Upon the Director's issuance of a notice commencing a prospective applicant's pre-filing process, the prospective applicant must:

(1) Within seven days and after consultation with Commission staff, establish the dates and locations at which the prospective applicant will conduct open houses and meetings with stakeholders (including agencies) and Commission staff.

(2) Within 14 days, conclude the contract with the selected third-party contractor.

(3) Within 14 days, contact all stakeholders not already informed about the project, including all affected landowners as defined in paragraph § 157.6(d)(2) of this section.

(4) Within 30 days, submit a stakeholder mailing list to Commission staff.

(5) Within 30 days, file a draft of Resource Report 1, in accordance with § 380.12(c), and a summary of the alternatives considered or under consideration.

(6) On a monthly basis, file status reports detailing the applicant's project activities including surveys, stakeholder communications, and agency meetings.

(7) Be prepared to provide a description of the proposed project and to answer questions from the public at the scoping meetings held by OEP staff.

(8) Be prepared to attend site visits and other stakeholder and agency meetings arranged by the Commission staff, as required.

(9) Within 14 days of the end of the scoping comment period, respond to issues raised during scoping.

(10) Within 60 days of the end of the scoping comment period, file draft Resource Reports 1 through 12.

(11) At least 60 days prior to filing an application, file revised draft Resource Reports 1 through 12, if requested by Commission staff.

(12) At least 90 days prior to filing an application, file draft Resource Report 13 (for LNG terminal facilities).

(13) Certify that a Follow-on WSA will be submitted to the U.S. Coast Guard no later than the filing of an application with the Commission (for LNG terminal facilities and modifications thereto, if appropriate). The applicant shall certify that the U.S. Coast Guard has indicated that a Follow-On WSA is not required, if appropriate.

(g) Commission staff and third-party contractor involvement during the pre-filing process will be designed to fit each project and will include some or all of the following:

(1) Assisting the prospective applicant in developing initial information about the proposal and identifying affected parties (including landowners, agencies, and other interested parties).

(2) Issuing an environmental scoping notice and conducting such scoping for the proposal.

(3) Facilitating issue identification and resolution.

(4) Conducting site visits, examining alternatives, meeting with agencies and stakeholders, and participating in the prospective applicant's public information meetings.

(5) Reviewing draft Resource Reports.

(6) Initiating the preparation of a preliminary Environmental Assessment or Draft Environmental Impact Statement, the preparation of which may involve cooperating agency review.

(h) A prospective applicant using the pre-filing procedures of this section shall comply with the procedures in § 388.112 of this chapter for the submission of documents containing privileged materials or critical energy infrastructure information.

[Order 665, 70 FR 60440, Oct. 18, 2005, as amended by Order 756, 77 FR 4894, Feb. 1, 2012; Order 769, 77 FR 65475, Oct. 29, 2012]

§ 157.22 Schedule for final decisions on a request for a Federal authorization.

(a) For an application under section 3 or 7 of the Natural Gas Act that requires a Federal authorization—i.e., a permit, special use authorization, certification, opinion, or other approval—from a Federal agency or officer, or State agency or officer acting pursuant to delegated Federal authority, a final decision on a request for a Federal authorization is due no later than 90 days after the Commission issues its final environmental document, unless a schedule is otherwise established by Federal law.

(b) For requests for a water quality certification submitted pursuant to section 401(a)(1) of the Federal Water Pollution Control Act (Clean Water Act) in connection with a project for which authorization is sought from the Commission under section 3 or 7 of the Natural Gas Act, the reasonable period of time during which the certifying agency may act on the water quality certification request is one year from the certifying agency's receipt of the request. A certifying agency is deemed to have waived the certification requirements of section 401(a)(1) of the Clean Water Act if the certifying agency has not denied or granted certification by one year after the date the certifying agency received a written request for certification.

[86 FR 16302, Mar. 29, 2021]

§ 157.30 Purpose.

This subpart establishes the procedures for conducting open seasons for the purpose of making binding commitments for the acquisition of initial or voluntary expansion capacity on Alaska natural gas transportation projects, as defined herein.

§ 157.31 Definitions.

(a) “Alaska natural gas transportation project” means any natural gas pipeline system that carries Alaska natural gas to the international border between Alaska and Canada (including related facilities subject to the jurisdiction of the Commission) that is authorized under the Alaska Natural Gas Transportation Act of 1976 or section 103 of the Alaska Natural Gas Pipeline Act.

(b) “Commission” means the Federal Energy Regulatory Commission.

(c) “Voluntary expansion” means any expansion in capacity of an Alaska natural gas transportation project above the initial certificated capacity, including any increase in mainline capacity, any extension of mainline pipeline facilities, and any lateral pipeline facilities beyond those certificated in the initial certificate order, voluntarily made by the pipeline. An expansion done pursuant to section 105 of the Alaska Natural Gas Pipeline Act is not a voluntary expansion.

§ 157.32 Applicability.

These regulations shall 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. Absent a Commission order to the contrary, these regulations are not applicable in the case of an expansion ordered by the Commission pursuant to section 105 of the Alaska Natural Gas Pipeline Act.

§ 157.33 Requirement for open season.

(a) Any application for a certificate of public convenience and necessity or other authorization 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. Failure to provide the requisite demonstration will result in an application being rejected as incomplete.

(b) Initial capacity on a proposed Alaska natural gas transportation project may be acquired prior to an open season through pre-subscription agreements, provided that in any open season as required in paragraph (a) of this section, capacity is offered to all prospective bidders at the same rates and on the same terms and conditions as contained in the pre-subscription agreements. All pre-subscription agreements shall be made public by posting on Internet websites and press releases within ten days of their execution. In the event there is more than one such agreement, all prospective bidders shall be allowed the option of selecting among the several agreements all of the rates, terms and conditions contained in any one such agreement.

[Order 2005, 70 FR 8286, Feb. 18, 2005, as amended by Order 2005-A, 70 FR 35026, June 16, 2005]

§ 157.34 Notice of open season.

(a) Notice. A prospective applicant must provide reasonable public notice of an open season through methods including postings on Internet Web sites, press releases, direct mail solicitations, and other advertising. In addition, a prospective applicant must provide actual notice of an open season to the State of Alaska and to the Federal Coordinator for Alaska Natural Gas Transportation Projects.

(b) In-State Needs Study. A prospective applicant must conduct or adopt a study of gas consumption needs and prospective points of delivery within the State of Alaska and rely upon such study to develop the contents of the notice required in paragraph (a) of this section. Such study shall be identified in the notice and if practicable, shall include or consist of a study conducted, approved, or otherwise sanctioned by an appropriate governmental agency, office or commission of the State of Alaska. In its open season proposal, a prospective applicant shall include an estimate based upon the study, of how much capacity will be used in-state.

(c) Contents of notice. Notice of the open season required in paragraph (a) of this section, shall contain at least the following information; however, to the extent that any item of such information is not known or determined at the time the notice is issued, the prospective applicant shall make a good faith estimate based on the best information available of all such unknown or undetermined items of required information and further, 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:

(1) The general route of the proposed project, including receipt and delivery points, and any alternative routes under consideration; delivery points must include those within the State of Alaska as determined by the In-State Study in paragraph (b) of this section.

(2) Size and design capacity (including proposed certificate capacity at the delivery points named in paragraph (c)(1) of this section to the extent that it differs from design capacity), a description of possible designs for expanded capacity beyond initial capacity, together with any estimated date when such expansions designs may be considered;

(3) Maximum allowable operating pressure and expected actual operating pressure;

(4) Delivery pressure at all delivery points named in paragraph (c)(1) of this section;

(5) Projected in-service date;

(6) An estimated unbundled transportation rate for each delivery point named in paragraph (c)(1) of this section, stated on a volumetric or thermal basis, for each service offered, including reservation rates for pipeline capacity, interruptible transportation rates, usage rates, fuel retention percentages, and other applicable charges, or surcharges, such as the Annual Charge Adjustment (ACA); (if rates are estimated on a volumetric basis then the notice must inform bidders that final pro forma service agreements and the sponsor's proposed FERC tariff will have to be submitted with rates based on a thermal basis.)

(7) The estimated cost of service (i.e., estimated cost of facilities, depreciation, rate of return and capitalization, taxes and operational and maintenance expenses), and estimated cost allocations, rate design volumes and rate design;

(8) Based on the In-State Study and the delivery points within the State of Alaska identified in paragraph (c)(1) of this section, there must be an estimated transportation rate for such deliveries, based on the amount of in-state needs shown in the study. Such estimated transportation rate must be based on the costs to make such in-state deliveries and shall not include costs to make deliveries outside the State of Alaska;

(9) Negotiated rate and other rate options under consideration, including any rates and terms of any precedent agreements with prospective anchor shippers that have been negotiated or agreed to outside of the open season process prescribed in this section;

(10) Quality specifications and any other requirements applicable to gas to be delivered to the project; provided that a prospective applicant shall not require that potential shippers process or treat their gas at any designated plant or facility;

(11) Terms and conditions for each service offered;

(12) Creditworthiness standards to be applied to, and any collateral requirements for, prospective shippers;

(13) The date, if any, by which potential shippers and the prospective applicant must execute precedent agreements;

(14) A detailed methodology for determining the value of bids for deliveries within the State of Alaska and for deliveries outside the State of Alaska;

(15) The methodology by which capacity will be awarded, in the case of over-subscription, clearly stating all terms that will be considered, except that if any capacity is acquired through pre-subscription agreements as provided in § 157.33(b) and the prospective applicant does not redesign the project to accommodate all capacity requests, only that capacity that was acquired through pre-subscription or was bid in the open season on the same rates, terms, and conditions as any one of the pre-subscription agreements shall be allocated on a pro rata basis and no other capacity acquired through the open season shall be allocated.

(16) Required bid information, whether bids are binding or non-binding, receipt and delivery point requirements, the form of a precedent agreement and time of execution of the precedent agreement, definition and treatment of non-conforming bids;

(17) The projected date for filing an application with the Commission;

(18) All information that the prospective applicant has in its possession pertaining to the proposed service to be offered, projected pipeline capacity and design, proposed tariff provisions, and cost projections, or that the prospective applicant has made available to, or obtained from, 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;

(19) A list of the names and addresses of the prospective applicant's affiliated sales and marketing units and affiliates involved in the production of natural gas in the State of Alaska. Affiliated unit means “Affiliate” as defined in § 358.3(a) of this chapter. Marketing units and or affiliates are those conducting a “marketing function” as defined in § 358.3(c) of this chapter, except that the exemption in § 358.3(c)(2)(iii) shall not apply;

(20) A comprehensive organizational chart showing:

(i) The organizational structure of the prospective applicant's parent corporation(s) with the relative position in the corporate structure of marketing and sales units and any affiliates involved in the production of natural gas in the State of Alaska.

(ii) The job titles and descriptions, and chain of command for all officers and directors of the prospective applicant's marketing and sales units and any affiliates involved in the production of natural gas in the State of Alaska; and

(21) A statement that any officers and directors of the prospective applicant's affiliated sales and marketing units and affiliates involved in the production of natural gas in the State of Alaska named in paragraph (c)(19) of this section will be prohibited from obtaining information about the conduct of the open season or allocation of capacity that is not posted on the open season Internet Web site or that is otherwise also available to the general public or other participants in the open season.

(d) Timing. (1) A prospective applicant must provide prospective shippers at least 90 days from the date on which notice of the open season is given within which to submit requests for transportation services. No bid shall be rejected because a prospective shipper has submitted another bid in another open season conducted under this subpart.

(2) A prospective applicant must consider any bids tendered after the expiration of the open season by qualifying bidders and may reject them only if they cannot be accommodated due to economic, engineering, design, capacity or operational constraints, or accommodating the request would otherwise adversely impact the timely development of the project, and a detailed explanation must accompany the rejection. Any bids tendered after the expiration of the open season must contain a good faith showing, including a statement of the circumstances which prevented the late bidder from tendering a timely bid and how those circumstances have changed. If a prospective applicant determines at any time that, based on the criteria stated in this paragraph, no further late bids for capacity can be accommodated, it may request Commission approval to summarily reject any further requests.

(3) Within 10 days after precedent agreements have been executed for capacity allocated in the open season, the prospective applicant shall make public on the Internet and through press releases the results of the open season, at least including the name of the prospective shipper, amount of capacity awarded, and term of agreement.

(4) Within 20 days after precedent agreements have been executed for capacity allocated in the open season, the prospective applicant must submit copies of all such precedent agreements to the Commission and copies of any relevant correspondence with bidders for capacity who were not allocated capacity that identifies why such bids were not accepted (all documents identified in this paragraph (d)(4) may be filed seeking privileged treatment pursuant to § 388.112 of this chapter.

[Order 2005, 70 FR 8286, Feb. 18, 2005, as amended by Order 2005-A, 70 FR 35026, June 16, 2005; 75 FR 15342, Mar. 29, 2010; Order 769, 77 FR 65475, Oct. 29, 2012]

§ 157.35 Undue discrimination or preference.

(a) All binding open seasons shall be conducted without undue discrimination or preference in the rates, terms or conditions of service and all capacity allocated as a result of any open season shall be awarded without undue discrimination or preference of any kind.

(b) Any complaint filed pursuant to § 385.206 of this chapter alleging non-compliance with any of the requirements of this subpart shall be processed under the Commission's Fast Track Processing procedures contained in § 385.206(h).

(c) Each prospective applicant conducting an open season under this subpart must function independent of the other divisions of the prospective applicant as well as the prospective applicant's “affiliates” performing a “marketing function” as those terms are defined in § 358.3(a) and (c) of the Commission's regulations, except that the exemption in § 358.3(c)(2)(iii) shall not apply. In instances in which the prospective applicant is not an entity created specifically to conduct an open season under this subpart, the prospective applicant must create or designate a unit or division to conduct the open season that must function independent of the other divisions of the project applicant as well as the project applicant's “affiliates” performing a “marketing function” as those terms are defined in § 358.3(a) of this chapter, except that the exemption in 358.3(c)(2)(iii) shall not apply.

(d) Each project applicant conducting an open season under this subpart that is not otherwise subject to the provisions of part 358 of this chapter must comply with the following sections of that part: §§ 358.4(c) and (d), 358.5, 358.6, 358.7(a), (b), and (c), and 358.8 (b) and (c) of this chapter.

[Order 2005, 70 FR 8286, Feb. 18, 2005, as amended by Order 2005-A, 70 FR 35026, June 16, 2005; 75 FR 15342, Mar. 29, 2010]

§ 157.36 Open seasons for expansions.

Any open season for capacity exceeding the initial capacity of an Alaska natural gas transportation project must provide the opportunity for the transportation of gas other than Prudhoe Bay or Point Thomson production. In considering a proposed voluntary expansion of an Alaska natural gas pipeline project, the Commission will consider the extent to which the expansion will be utilized by shippers other than those who are the initial shippers on the project and, in order to promote competition and open access to the project, may require design changes to ensure that some portion of the expansion capacity be allocated to new shippers willing to sign long-term firm transportation contracts, including shippers seeking to transport natural gas from areas other than Prudhoe Bay and Point Thomson.

[Order 2005-A, 70 FR 35026, June 16, 2005]

§ 157.37 Project design.

In reviewing any application for an Alaska natural gas pipeline project, the Commission will consider the extent to which a proposed project has been designed to accommodate the needs of shippers who have made conforming bids during an open season, as well as the extent to which the project can accommodate low-cost expansion, and may require changes in project design necessary to promote competition and offer a reasonable opportunity for access to the project.

[Order 2005, 70 FR 8286, Feb. 18, 2005; Order 756, 77 FR 4894, Feb. 1, 2012]

§ 157.38 Pre-approval procedures.

No later than 90 days prior to providing the notice of open season required by § 157.34(a), a prospective applicant must file, for Commission approval, a detailed plan for conducting an open season in conformance with this subpart. The prospective applicant's plan shall include the proposed notice of open season. Upon receipt of a request for such a determination, the Secretary of the Commission shall issue a notice of the request, which will then be published in the Federal Register. The notice shall establish a date on which comments from interested persons are due and a date, which shall be within 60 days of receipt of the prospective applicant's request unless otherwise directed by the Commission, by which the Commission will act on the proposed plan.

[Order 2005-A, 70 FR 35026, June 16, 2005]

§ 157.39 Rate treatment of pipeline expansions.

There shall be a rebuttable presumption that rates for any expansion of an Alaska natural gas transportation project shall be determined on a rolled-in basis.

§ 157.53 Testing.

(a) Construction and operation of facilities necessary to render direct natural gas service for use in the testing and purging of new natural gas pipeline facilities are exempted from the certificate requirements of section 7(c) of the Natural Gas Act, when the construction and operation of such facilities are conducted in accordance with paragraph (b) of this section.

(b) Operations undertaken to render direct natural gas service shall be terminated upon the completion of the purging or testing of the pipeline facilities. Persons undertaking any construction or operation of facilities or service under this section shall file an original and two copies of an annual statement, by February 1 of each year, describing their activities hereunder.

[43 FR 56544, Dec. 1, 1978, as amended at 60 FR 53065, Oct. 11, 1995]

§ 157.201 Applicability.

(a) Scope. This subpart establishes a procedure whereby an interstate pipeline may obtain a blanket certificate authorizing certain construction and operation of facilities and certain certificate amendments and abandonment under section 7 of the Natural Gas Act.

(b) Who may apply. This procedure is only applicable to interstate pipelines.

(c) Cross-reference. The procedures applicable to transportation by interstate pipelines under blanket certificates are set forth in subpart G of part 284 of this chapter.

(d) Availability of case-specific certificates. Nothing in this subpart shall preclude an interstate pipeline from proceeding under any other provision of the Commission's regulations to obtain Commission approval of abandonments or a temporary or permanent certificate of public convenience and necessity.

[Order 234, 47 FR 24266, June 4, 1982, as amended by Order 436, 50 FR 42490, Oct. 18, 1985; Order 603, 64 FR 26606, May 14, 1999]

§ 157.202 Definitions.

(a) General rule. Terms defined in the Natural Gas Policy Act of 1978 (NGPA) shall have the same meaning for the purposes of this subpart as they have under the Natural Gas Policy Act of 1978.

(b) Subpart F definitions. For purposes of this subpart:

(1) Certificate holder means any interstate pipeline with an effective blanket certificate issued pursuant to this subpart.

(2)(i) Eligible facility means, except as provided in paragraph (b)(2)(ii) of this section, any facility subject to the Natural Gas Act jurisdiction of the Commission that is necessary to provide service within existing certificated levels. Eligible facility also includes any gas supply facility or any facility, including receipt points, needed by the certificate holder to receive gas into its system for further transport or storage, and interconnecting facilities between transporters that transport natural gas under part 284 of this chapter. Further, eligible facility includes main line, lateral, and compressor replacements that do not qualify under § 2.55(b) of this chapter because they will result in an incidental increase in the capacity of main line facilities, or because they will not satisfy the location or work space requirements of § 2.55(b). Replacements must be done for sound engineering purposes. Replacements for the primary purpose of creating additional main line capacity are not eligible facilities; however, replacements and the modification of facilities to rearrange gas flows or increase compression for the primary purpose of restoring service in an emergency due to sudden unforeseen damage to main line facilities are eligible facilities. Eligible facility also includes auxiliary installations and observation wells which do not qualify under § 2.55(a) of this chapter because they will not satisfy the location or work space requirements of § 2.55(a). Finally, for purposes of abandonment under § 157.216, eligible facilities include auxiliary installations that do not qualify for pre-granted abandonment authority under § 2.55(a)(3) and replacement facilities constructed under § 2.55(b).

(ii) Exclusions: “Eligible facility” does not include:

(A) A main line of a transmission system, except replacement facilities covered under § 157.202(b)(2)(i).

(B) An extension of a main line, except replacement facilities covered under § 157.202(b)(2)(i).

(C) A facility, including compression and looping, that alters the capacity of a main line, except replacement facilities and facility modifications covered under paragraph (b)(2)(i) of this section.

(D) A facility required to test or develop an underground storage field or that alters the certificated capacity, deliverability, or storage boundary, or a facility required to store gas above ground in either a gaseous or liquified state, or a facility used to receive gas from plants manufacturing synthetic gas or from plants gasifying liquefied natural gas, or wells needed to utilize an underground storage field.

(E) Delivery points under § 157.211.

(F) Temporary compression under § 157.209.

(G) A facility that crosses a state line and is constructed for the primary purpose of transporting gas which is also transported by an intrastate pipeline under section 311(a)(2) of the NGPA.

(3) Facility, for purposes of construction under this subpart, does not include an auxiliary facility that qualifies for construction under § 2.55(a) of this chapter or a replacement facility that qualifies for construction under § 2.55(b).

(4) Temporary compression means compressor facilities installed and operated at existing compressor locations for the limited purpose of temporarily replacing existing permanent compressor facilities that are undergoing maintenance or repair or that are pending permanent replacement.

(5) Main line means the principal transmission facilities of a pipeline system extending from supply areas to market areas and does not include small diameter supply or delivery laterals or gathering lines.

(6) Miscellaneous rearrangement of any facility means any rearrangement of a facility, excluding underground storage injection/withdrawal wells, that does not result in any change of service rendered by means of the facilities involved, including changes in existing field operations or relocation of existing facilities:

(i) On the same property;

(ii) When required by highway construction, dam construction, encroachment of residential, commercial, or industrial areas, erosion, or the expansion or change of course of rivers, streams or creeks, or

(iii) To respond to other natural forces beyond the certificate holder's control when necessary to ensure safety or maintain the operational integrity of the certificate holder's facilities.

(7) Project means a unit of improvement or construction that is used and useful upon completion.

(8) Project cost means the total actual cost of constructing the jurisdictional portions of a project. In the case of a project constructed jointly by more than one interstate pipeline, the project cost is the total cost, irrespective of the amount paid by each pipeline.

(9) Right-of-way grantor means:

(i) A person who grants a right-of-way easement to the certificate holder; or

(ii) Any successor to an interest which is subject to the easement.

(iii) This paragraph (b)(9) shall cease to have effect on December 5, 2026, unless the Commission determines that the cessation deadline should be extended to a date not more than 5 years in the future after offering the public an opportunity to provide input on the costs and benefits of this paragraph (b)(9) and considering that input. The Commission will publish a document in the Federal Register announcing its determination and revising or removing this paragraph (b)(9) accordingly.

(10) Delivery point means a tap and/or metering and appurtenant facilities, such as heaters, minor gas conditioning, treatment, odorization, and similar equipment, necessary to enable the certificate holder to deliver gas to any party.

(11) Sensitive environmental area means:

(i) The habitats of species which have been identified as endangered or threatened under the Endangered Species Act (Pub. L. 93-205, as amended) and essential fish habitat as identified under the Magnuson-Stevens Fishery Conservation and Management Act (16 U.S.C. 1801, et seq.);

(ii) National or State Forests or Parks;

(iii) Properties listed on, or eligible for inclusion in, the National Register of Historic Places, or the National Register of Natural Landmarks;

(iv) Floodplains and wetlands;

(v) Designated or proposed wilderness areas, national or state wild and scenic rivers, wildlife refuges and management areas and sanctuaries;

(vi) Prime agricultural lands, designated by the Department of Agriculture; or

(vii) Sites which are subject to use by American Indians and other Native Americans for religious purposes.

(12) Interconnection facilities means the interconnecting point, which includes the tap, metering, and M&R facilities and the related interconnecting pipeline.

(13) Emergency means a sudden unanticipated loss of gas supply or capacity that requires an immediate restoration of interrupted service for protection of life or health or for maintenance of physical property.

[Order 234, 47 FR 24266, June 4, 1982]

Editorial Note:For Federal Register citations affecting § 157.202, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 157.203 Blanket certification.

(a) Effect. A blanket certificate issued pursuant to this subpart authorizes the certificate holder, in accordance with the provisions of this subpart, to engage in any of the activities specified in § 157.208 through § 157.218 (as may be amended from time to time).

(b) Automatic authorization. A blanket certificate issued pursuant to this subpart authorizes the certificate holder to engage in transactions described in § 157.208(a), § 157.209(a), § 157.211(a)(1), § 157.213(a), § 157.215, § 157.216(a), or § 157.218 without further Commission approval.

(c) Prior notice required. A blanket certificate issued pursuant to this subpart authorizes the certificate holder to engage in activities described in § 157.208(b), § 157.210,§ 157.211(a)(2), § 157.212, § 157.213(b), § 157.214, or § 157.216(b), if the requirements of § 157.205 have been fulfilled.

(d) Landowner notification. (1) Except as identified in paragraph (d)(3) of this section, no activity described in paragraph (b) of this section is authorized unless the company makes a good faith effort to notify, in writing all affected landowners, as defined in § 157.6(d)(2), at least 45 days prior to commencing construction or at the time it initiates easement negotiations, whichever is earlier. A landowner may waive the 45-day prior notice requirement in writing as long as the notice has been provided. For activity required to restore service in an emergency, the 45-day prior notice period is satisfied in the event a company obtains all necessary easements. The notification shall include at least:

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

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

(iii) A description of the company's environmental complaint resolution procedure that must:

(A) Provide landowners with clear and simple directions for identifying and resolving their environmental mitigation problems and concerns during construction of the project and restoration of the right-of way;

(B) Provide a local or toll-free phone number and a name of a specific person to be contacted by landowners and with responsibility for responding to landowner problems and concerns, and who will indicate when a landowner should expect a response;

(C) Instruct landowners that if they are not satisfied with the response, they may call the company's Hotline; and

(D) Instruct landowners that, if they are still not satisfied with the response, they may contact the Commission's Landowner Helpline at the current telephone number and email address, which is to be provided in the notification.

(2) For activities described in paragraph (c) of this section, the company shall make a good faith effort to notify in writing all affected landowners, as defined in § 157.6(d)(2), within at least three business days following the date that a docket number is assigned to the application or at the time it initiates easement negotiations, whichever is earlier. The notice should include at least:

(i) A brief description of the company and the proposed project, including the facilities to be constructed or replaced and the location (including a general location map), the purpose, and the timing of the project and the effect the construction activity will have on the landowner's property;

(ii) A general description of what the company will need from the landowner if the project is approved, and how the landowner may contact the company, including a local or toll-free phone number and a name of a specific person to contact who is knowledgeable about the project;

(iii) The docket number (if assigned) for the company's application;

(iv) A general description of the blanket certificate program and procedures, as posted on the Commission's Web site at the time the landowner notification is prepared, and the link to the information on the Commission's Web site;

(v) A brief summary of the rights the landowner has in Commission proceedings and in proceedings under the relevant eminent domain rules; and

(vi) The following paragraph: This project is being proposed under the prior notice requirements of the blanket certificate program administered by the Federal Energy Regulatory Commission. Under the Commission's regulations, you have the right to protest this project within 60 days of the date the Commission issues a notice of the pipeline's filing. If you file a protest, you should include the docket number listed in this letter and provide the specific reasons for your protest. The protest should be mailed to the Secretary of the Federal Energy Regulatory Commission, 888 First St., NE., Room 1A, Washington, DC 20426. A copy of the protest should be mailed to the pipeline at [pipeline address]. If you have any questions concerning these procedures you can call the Commission's Office of External Affairs at (202) 208-1088; and

(vii) The description of the company's environmental complaint resolution procedure as described in paragraph (d)(1)(iii) of this section.

(3) Exceptions. (i) No landowner notice is required for replacements which would have been done under § 2.55 of this chapter but for the fact that the replacement facilities are not of the same capacity as long as they meet the location requirements of § 2.55(b)(1)(ii) of this chapter and do not cause any ground disturbance; or any replacement done for safety, DOT compliance, environmental, or unplanned maintenance reasons that are not foreseen and that require immediate attention by the certificate holder.

(ii) No landowner notice is required for abandonments which involve only the sale or transfer of the facilities, and the easement will continue to be used for transportation of natural gas.

(iii) No landowner notice is required if there is only one landowner and that landowner has requested the service or facilities.

(iv) No landowner notice is required for activities that do not involve ground disturbance or changes to operational air and noise emissions.

(4) If paragraphs (d)(1) or (d)(2) of this section require an applicant to reveal Critical Energy Infrastructure Information (CEII), as defined by § 388.113(c) of this chapter, to any person, the applicant shall follow the procedures set out in § 157.10(d).

[Order 234, 47 FR 24266, June 4, 1982]

Editorial Note:For Federal Register citations affecting § 157.203, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 157.204 Application procedure.

(a) Who may apply. Any interstate pipeline which has been issued a certificate other than a limited-jurisdiction certificate, pursuant to section 7 of the Natural Gas Act and had rates accepted by the Commission may apply for a blanket certificate under this subpart in the manner prescribed in §§ 157.6(a), 157.14(a) and 385.2011 of this chapter.

(b) Hearing procedure. Upon receiving an application for a blanket certificate under this subpart, the Commission will conduct a hearing pursuant to section 7(c) of the Natural Gas Act and §§ 1.32 and 157.11 of this chapter.

(c) Issuance. If required by the present or future public convenience and necessity, the Commission will issue a blanket certificate to the applicant.

(d) Application contents. Applications for blanket certificates shall contain:

(1) Information indicating the exact legal name of the applicant; its principal place of business; whether the applicant is an individual, partnership, corporation or otherwise; citation to the certificate proceeding in which the applicant was found to be a natural gas company; the state under the laws of which the applicant is organized or authorized to do business; and the name, title, and mailing address and telephone number of the person or persons to whom communications concerning the application are to be addressed;

(2) A statement that the applicant will comply with the terms, conditions and procedures specified in this subpart.

[Order 234, 47 FR 24266, June 4, 1982, as amended by Order 319, 48 FR 34888, Aug. 1, 1983; Order 433, 50 FR 40345, Oct. 3, 1985; Order 436, 50 FR 42490, Oct. 18, 1985; Order 493, 53 FR 15030, Apr. 27, 1988; Order 603, 64 FR 26607, May 14, 1999]

§ 157.205 Notice procedure.

(a) Applicability. No activity described in §§ 157.208(b), § 157.210, § 157.211(a)(2), § 157.212, § 157.213(b), 157.214 or 157.216(b), except for activity required to restore service in an emergency, is authorized by a blanket certificate granted under this subpart, unless, prior to undertaking such activity:

(1) The notice requirements have been fulfilled in accordance with the provisions of this section; and

(2) Either (i) no protest has been filed pursuant to paragraph (e) of this section or, (ii) if a protest has been filed, it has been withdrawn or dismissed pursuant to paragraph (g) of this section.

(b) Contents. For any activity subject to the requirements of this section, the certificate holder must file with the Secretary of the Commission an original and seven copies, as prescribed in §§ 157.6(a) and 385.2011 of this chapter, a request for authorization under the notice procedures of this section that contains:

(1) The exact legal name of the certificate holder and mailing address and telephone number of the person or persons to whom communications concerning the request are to be addressed;

(2) The docket number in which its blanket certificate was issued;

(3) Any information required in §§ 157.208 through 157.218 of this chapter for the particular activity;

(4) A verified statement that the proposed activity complies with the requirements of this subpart;

(5) A form of notice of the application suitable for publication in the Federal Register in accordance with the specifications in § 385.203(d) of this chapter. This paragraph (b)(5) shall cease to have effect on December 5, 2026, unless the Commission determines that the cessation deadline should be extended to a date not more than 5 years in the future after offering the public an opportunity to provide input on the costs and benefits of this paragraph (b)(5) and considering that input. The Commission will publish a document in the Federal Register announcing its determination and revising or removing this paragraph (b)(5) accordingly; and

(6) Identities and docket numbers of other applications related to the transaction. All related filings must be made within 10 days of the first filing. Otherwise the applications on file will be rejected under paragraph (c) of this section without prejudice to refiling when all parties are ready to proceed.

(c) Rejection of request. The Director of the Office of Energy Projects shall reject within 10 days of the date of filing a request which patently fails to comply with the provisions of paragraph (b) of this section, without prejudice to the pipeline's refiling a complete application.

(d) Publication of notice of request. (1) Unless the request has been rejected pursuant to paragraph (c) of this section, the Secretary of the Commission shall issue a notice of the request within 10 days of the date of the filing, which will then be published in the Federal Register. The notice shall designate a deadline for filing protests, or interventions to the request. The deadline shall be 60 days after the date of issuance of the notice of the request.

(2) [Reserved]

(e) Protests. (1) Any person or the Commission's staff may file a protest prior to the deadline. Copies of the protest must be served on the Secretary of the Commission and the certificate holder.

(2) Protests shall be filed in the following form:

United States of America Before the Federal Energy Regulatory Commission [Name of pipeline holding the blanket certificate] Docket No. [Include both docket no. of the blanket certificate and the prior notice transaction] Protest to Proposed Blanket Certificate Activity

(Name of Protestor) hereby protests the request filed by (Name of pipeline) to conduct a (construction of facilities, abandonment, etc.) under § 157.____ of the Commission's regulations. Protestor seeks to have this request processed as a separate application.

(Include a detailed statement of Protestor's interest in the activity and the specific reasons and rationale for the objection and whether the protestor seeks to be an intervener.)

(f) Effect of protest. If a protest is filed in accordance with paragraph (e) of this section, then the certificate holder, the person who filed the protest, any intervenors, and staff shall have 30 days from the deadline determined in accordance with paragraph (d) of this section, to resolve the protest, and to file a withdrawal of the protest pursuant to paragraph (g) of this section. Informal settlement conferences may be convened by the Director of the Office of Energy Projects or his designee. If a protest is not withdrawn or dismissed pursuant to paragraph (g) of this section, the activity shall not be deemed authorized by the blanket certificate. Instead, the request filed by the certificate holder shall be treated as an application for section 7 authorization for the particular activity. The Federal Register notice of the request shall be deemed to be notice of the section 7 application sufficient to fulfill the notice requirement of §§ 157.9 and 157.10.

(g) Withdrawal or dismissal of protests. The protestor may withdraw a protest within the 30 day period following the deadline determined in accordance with paragraph (d) of this section by submitting written notice of withdrawal to the Secretary of the Commission and serving a copy on the certificate holder, any intervenors and any other party requesting service. The withdrawal must state that the certificate holder and the protestor concur in the withdrawal. Within 10 days of the filing of a protest, the Director of the Office of Energy Projects will dismiss that protest if it does not raise a substantive issue and fails to provide any specific detailed reason or rationale for the objection. If a protest is dismissed, the notice requirements of this section will not be fulfilled until the earlier of: (1) a 30 day period following the deadline determined in paragraph (d) of this section has run; or the dismissed protesting party notifying the Secretary of the Commission that its concerns have been resolved.

(h) Final authorization. (1) If no protest is filed within the time allowed by the Secretary, the certificate holder is authorized to conduct the activity under its blanket certificate, effective on the day after time expires for filing protests and interventions unless, during that time, the certificate holder withdraws its application in accordance with § 385.216 of this chapter.

(2) If any protest is filed within the time allowed for protest and interventions and is subsequently withdrawn under paragraph (g) of this section, the certificate holder is authorized to conduct the activity under its blanket certificate, effective upon the day after the withdrawal of all protests, unless the certificate holder withdraws its application in accordance with § 385.216 of this chapter prior to that date.

[Order 234, 47 FR 24266, June 4, 1982]

Editorial Note:For Federal Register citations affecting § 157.205, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 157.206 Standard conditions.

Any activity authorized under a blanket certificate issued under this subpart is subject to the following conditions:

(a) Revisions. (1) The Commission reserves the right to amend the requirements of this subpart from time to time.

(2) The blanket certificate is not transferable in any manner and shall be effective only so long as the certificate holder continues the activities authorized by the order issuing such certificate and does so in accordance with the provisions of the Natural Gas Act, as well as applicable rules, regulations, and orders of the Commission.

(b) Environmental compliance. This paragraph only applies to activities that involve ground disturbance or changes to operational air and noise emissions.

(1) The certificate holder shall adopt the requirements set forth in § 380.15(a) and (b) of this chapter for all activities authorized by the blanket certificate and shall issue the relevant portions thereof to construction personnel, with instructions to use them.

(2) All activities shall be consistent with all applicable law including the provisions of the following statutes and regulations or compliance plans developed to implement these statutes:

(i) Clean Water Act, as amended (33 U.S.C. 1251 et seq.) and the National Pollution Discharge Elimination System Program, 40 CFR part 122 et seq.;

(ii) Clean Air Act, as amended (42 U.S.C. 1801 et seq.) and air quality regulations and state implementation plans adopted pursuant to 40 CFR parts 50-99;

(iii) National Historic Preservation Act of 1966 (16 U.S.C. 470 et seq.);

(iv) Archeological and Historic Preservation Act of 1974 (Pub. L. 93-291);

(v) Coastal Zone Management Act of 1972, as amended (16 U.S.C. 1451 et seq.);

(vi) Endangered Species Act of 1973, Pub. L. 93-205, as amended (16 U.S.C. 1531 et seq.);

(vii) Executive Order 11988, May 24, 1977 requiring Federal agencies to evaluate the potential effects of any actions it may take on a floodplain;

(viii) Executive Order 11990, May 24, 1977 requiring an evaluation of the potential effects of construction on wetland;

(ix) Wild and Scenic Rivers Act (16 U.S.C. 1274 et seq.);

(x) National Wilderness Act (16 U.S.C. 1133 et seq.);

(xi) National Parks and Recreation Act of 1978 (16 U.S.C. 1 and 230 et seq.).

(xii) Magnuson-Stevens Fishery Conservation and Management Act (16 U.S.C. 1801, et seq.)

(3) The certificate holder shall be deemed in compliance with:

(i) Paragraph (b)(2)(vi) of this section only if it adheres to the procedures in appendix I of this subpart in which case the Commission finds that endangered species and their critical habitat are protected in accordance with 16 U.S.C. 1536;

(ii) Paragraph (b)(2)(iii) of this section only if it adheres to the procedures in appendix II of this subpart in which case the Commission finds that there is no effect on any property protected by 16 U.S.C. 470f;

(iii) Paragraph (b)(2)(v) of this section only if the appropriate state agency designated to administer the state's coastal zone management plan, prior to construction of the project, waives its right of review or determines that the project complies with the state's coastal zone management plan.

(iv) Paragraphs (b)(2)(i) and (viii) of this section only if it adheres to Commission staff's current “Upland Erosion Control, Revegetation and Maintenance Plan” and “Wetland and Waterbody Construction and Mitigation Procedures” which are available on the Commission Internet home page or from the Commission staff, or gets written approval from the staff or the appropriate Federal or state agency for the use of project-specific alternatives to clearly identified portions of those documents.

(4) Any transaction authorized under a blanket certificate shall not have a significant adverse impact on a sensitive environmental area.

(5)(i) The noise attributable to any new compressor station, compression added to an existing station, or any modification, upgrade or update of an existing station, must not exceed a day-night level (Ldn) of 55 dBA at any pre-existing noise-sensitive area (such as schools, hospitals, or residences).

(ii) A compressor facility installed under this section must be designed to meet the following noise emissions criteria. For each new compressor station facility, and for each addition or modification to an existing compression station, the blanket certificate holder must file a noise survey with the Secretary within 60 days of placing the facility in service.

(A) If noise emitted from a new compressor facility operating at full load exceeds an Ldn of 55 dBA at any noise-sensitive area (NSA), or if an addition or modification to an existing compressor station operating at full load at or below an Ldn of 55 dBA at NSAs causes overall noise attributable to the station to exceed an Ldn of 55 dBA at an NSA, the blanket certificate holder must come into compliance with an Ldn of 55 dBA at NSAs within 1 year of placing the facility in service.

(B) If an addition or modification to an existing compressor station operating at full load above an Ldn of 55 dBA at NSAs causes overall noise attributable to the station to increase at an NSA, the blanket certificate holder must act within 1 year of placing the added or modified facility in service to reduce noise at NSAs to the level that existed prior to the addition or modification.

(C) If the initial noise survey demonstrates a need to take action to mitigate noise, within 60 days of completing such action, the blanket certificate holder must file a subsequent noise survey with the Secretary demonstrating that each new compressor station facility, and each addition or modification to an existing compressor station, complies with the noise level limits.

(iii) Any horizontal directional drilling or drilling of wells which will occur between 10 p.m. and 7 a.m. local time must be conducted with the goal of keeping the perceived noise from the drilling at any pre-existing noise-sensitive area (such as schools, hospitals, or residences) at or below a night level (Ln) of 55 dBA.

(6)(i) Any activity otherwise subject to authorization under § 157.208 shall not be authorized if the activity is located within 0.5 mile of a nuclear power plant which is either operating or under construction, or for which a construction permit has been filed with the Nuclear Regulatory Commission.

(ii) Any activity otherwise subject to authorization under § 157.215 shall not be authorized if the activity is located within 2.0 miles of a nuclear power plant which is either operating or under construction, or for which a construction permit has been filed with the Nuclear Regulatory Commission.

(7) The certificate holder shall act as the Commission's non-Federal representative upon acceptance of the blanket certificate for purposes of complying with the Endangered Species Act of 1973.

(c) Commencement. Any authorized construction, extension, or acquisition shall be completed and made available for service by the certificate holder and any authorized operation, or service, shall be available within one year of the date the activity is authorized pursuant to § 157.205(h). The certificate holder may apply to the Director of the Office of Energy Projects for an extension of this deadline. However, if the request for extension is due to the end-user/shipper not being ready to accept service, the certificate holder must so notify the Commission in writing no later than 10 days after expiration of the one-year period.

(d) Reports. The certificate holder shall file reports as required by this subpart.

[Order 234, 47 FR 24266, June 4, 1982]

Editorial Note:For Federal Register citations affecting § 157.206, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 157.207 General reporting requirements.

On or before May 1, or each year, or in the case of emergency reconstruction activity, prior to any activity, the certificate holder must file, in the manner prescribed in §§ 157.6(a) and 385.2011 of this chapter, an annual report signed under oath by a senior official of the company, that lists for the previous calendar year:

(a) For each new facility authorized by §§ 157.208, 157.210, 157.212, or 157.213, the information specified in § 157.208(e);

(b) For each delivery point authorized under § 157.211(a)(1), the information required by § 157.211(c);

(c) for each temporary compressor facility under § 157.209, the information required by § 157.209(b);

(d) For each storage project tested or developed under § 157.215, the information specified in § 157.215(b)(1);

(e) For each abandonment authorized under § 157.216(a), the information specified in § 157.216(d);

(f) For each change in rate schedule authorized under § 157.217, the information specified in § 157.217(b);

(g) For each change in customer name authorized under § 157.218, the information specified in § 157.218(b); and

(h) If any activity required to be reported under this section was not undertaken, a statement to that effect.

[Order 436, 50 FR 42490, Oct. 18, 1985, as amended by Order 493, 53 FR 15030, Apr. 27, 1988; Order 603, 64 FR 26607, May 14, 1999; Order 603, 66 FR 15347, Mar. 19, 2001; Order 633, 68 FR 31605, May 28, 2003; Order 686, 71 FR 63693, Oct. 31, 2006; Order 686-A, 72 FR 37436, July 10, 2007]

§ 157.208 Construction, acquisition, operation, replacement, and miscellaneous rearrangement of facilities.

(a) Automatic authorization. If the project cost does not exceed the cost limitations set forth in column 1 of table 1 to paragraph (d) of this section, or if the project is required to restore service in an emergency, the certificate holder is authorized to make miscellaneous rearrangements of any facility, or acquire, construct, replace, or operate any eligible facility. The certificate holder shall not segment projects in order to meet the cost limitations set forth in column 1 of table 1 to paragraph (d).

(b) Prior notice. If the project cost is greater than the amount specified in column 1 of table 1 to paragraph (d) of this section, but less than the amount specified in column 2 of table 1 to paragraph (d), the certificate holder is authorized to make miscellaneous rearrangements of any facility, or acquire, construct, replace, or operate any eligible facility. The certificate holder shall not segment projects in order to meet the cost limitations set forth in column 2 of table 1 to paragraph (d).

(c) Contents of request. In addition to the requirements of § 157.205(b), requests filed for activities described under paragraph (b) of this section shall contain:

(1) A description of the purpose of the proposed facilities including their relationship to other existing or planned facilities;

(2) A detailed description of the proposed facilities specifying length, diameter, wall thickness and maximum operating pressure for pipeline; and for compressors, the size, type, and number of compressor units, horsepower required, horsepower existing and proposed, volume of fuel gas, suction and discharge pressure and compression ratio;

(3) A USGS 7 1/2 minute series (scale 1:24000) topographic map (or map of equivalent or greater detail, as appropriate) showing the location of the proposed facilities, and indicating the location of any sensitive environmental areas within one-quarter mile of project-related construction activities;

(4) A map showing the relationship of the proposed facilities to the applicant's existing facilities;

(5) A flow diagram or comparative study showing daily design capacity, daily maximum capacity and operating pressures with and without the proposed facilities for that portion of the certificate holder's system affected by the proposal;

(6) The estimated cost and method of financing the proposed facilities;

(7) A statement explaining how the public convenience and necessity requires the approval of the project;

(8) For acquisitions of facilities:

(i) A statement referencing the date of issuance, docket number and title of the proceeding for any certificate issued by the Commission authorizing the facilities proposed to be acquired; and

(ii) The amounts recorded in the accounts of the vendor (seller or lessor) that apply to the facilities proposed to be acquired and the accumulated provisions for depreciation, depletion, and amortization;

(9) A concise analysis discussing the relevant issues outlined in § 380.12 of this chapter. The analysis must identify the existing environmental conditions and the expected significant impacts that the proposed action, including proposed mitigation measures, will cause to the quality of the human environment, including impact expected to occur to sensitive environmental areas. When compressor facilities are proposed, the analysis must also describe how the proposed action will be made to comply with applicable State Implementation Plans developed under the Clean Air Act. The analysis must also include a description of the contacts made, reports produced, and results of consultations which took place to ensure compliance with the Endangered Species Act, National Historic Preservation Act and the Coastal Zone Management Act. Include a copy of the agreements received for compliance with the Endangered Species Act, National Historic Preservation Act, and Coastal Zone Management Act, or if no written concurrence is issued, a description of how the agency relayed its opinion to the company. Describe how drilling for wells or horizontal direction drilling would be designed to meet the goal of limiting the perceived noise at NSAs to an Ldn of 55 dBA or what mitigation would be offered to landowners.

(10) A commitment to having the Environmental Inspector's report filed every week.

(d) Limits and inflation adjustment. The limits specified in table 1 to this paragraph (d) and table 1 to § 157.215(a)(5) shall be adjusted each calendar year to reflect the “GDP implicit price deflator” published by the Department of Commerce for the previous calendar year. The Director of the Office of Energy Projects is authorized to compute and publish limits for future calendar years as a part of table 1 to this paragraph (d) and table 1 to § 157.215(a)(5), pursuant to § 375.308(x)(1) of this chapter.

Table 1 to Paragraph (d)

Year | Limit

Auto. proj. cost limit (col. 1) | Prior notice proj. cost limit (col. 2)

1982 | $4,200,000 | $12,000,000

1983 | 4,500,000 | 12,800,000

1984 | 4,700,000 | 13,300,000

1985 | 4,900,000 | 13,800,000

1986 | 5,100,000 | 14,300,000

1987 | 5,200,000 | 14,700,000

1988 | 5,400,000 | 15,100,000

1989 | 5,600,000 | 15,600,000

1990 | 5,800,000 | 16,000,000

1991 | 6,000,000 | 16,700,000

1992 | 6,200,000 | 17,300,000

1993 | 6,400,000 | 17,700,000

1994 | 6,600,000 | 18,100,000

1995 | 6,700,000 | 18,400,000

1996 | 6,900,000 | 18,800,000

1997 | 7,000,000 | 19,200,000

1998 | 7,100,000 | 19,600,000

1999 | 7,200,000 | 19,800,000

2000 | 7,300,000 | 20,200,000

2001 | 7,400,000 | 20,600,000

2002 | 7,500,000 | 21,000,000

2003 | 7,600,000 | 21,200,000

2004 | 7,800,000 | 21,600,000

2005 | 8,000,000 | 22,000,000

2006 | 9,600,000 | 27,400,000

2007 | 9,900,000 | 28,200,000

2008 | 10,200,000 | 29,000,000

2009 | 10,400,000 | 29,600,000

2010 | 10,500,000 | 29,900,000

2011 | 10,600,000 | 30,200,000

2012 | 10,800,000 | 30,800,000

2013 | 11,000,000 | 31,400,000

2014 | 11,200,000 | 31,900,000

2015 | 11,400,000 | 32,400,000

2016 | 11,600,000 | 32,800,000

2017 | 11,800,000 | 33,200,000

2018 | 12,000,000 | 33,800,000

2019 | 12,300,000 | 34,600,000

2020 | 12,500,000 | 35,200,000

2021 | 12,600,000 | 35,600,000

2022 | 13,100,000 | 37,100,000

2023 | 14,000,000 | 39,700,000

2024 | 14,500,000 | 41,100,000

(e) Reporting requirements. For each facility completed during the calendar year pursuant to paragraph (a) of this section and § 157.213(a), the certificate holder shall file in the manner prescribed in §§ 157.6(a) and 385.2011 of this chapter as part of the required annual report under § 157.207(a) the information described in paragraphs (e)(1)-(5) of this section. For each facility completed during the calendar year pursuant to paragraph (b) of this section, and §§ 157.210, 157.212, and 157.213(b), the certificate holder shall file in the manner prescribed above only the information described in paragraph (e)(3) of this section.

(1) A description of the facilities installed pursuant to this section, including a description of the length and size of pipelines, compressor horsepower, metering facilities, taps, valves, and any other facilities constructed;

(2) The specific purpose, location, and beginning and completion date of construction of the facilities installed, the date service commenced, and, if applicable, a statement indicating the extent to which the facilities were jointly constructed;

(3) The actual installed cost of each facility item listed pursuant to paragraph (e)(1), separately stating the cost of materials and labor as well as other costs allocable to the facilities;

(4)(i) A description of the contacts made, reports produced, and results of consultations which took place to ensure compliance with the Endangered Species Act, the National Historic Preservation Act and the Coastal Zone Management Act;

(ii) Documentation, including images, that restoration of work areas is progressing appropriately;

(iii) A discussion of problems or unusual construction issues, including those identified by affected landowners, and corrective actions taken or planned; and

(iv) For new or modified compression, a noise survey verifying compliance with § 157.206(b)(5).

(5) For acquisitions of facilities:

(i) A statement referencing the date of issuance, docket number and title of the proceeding for any certificate issued by the Commission authorizing the facilities acquired; and

(ii) The amounts recorded in the accounts of the vendor (seller or lessor) that apply to the facilities acquired and the accumulated provisions for depreciation, depletion, and amortization.

(f) Special conditions. (1) For purposes of comparing the project cost of leased facilities with the per-project cost limitations in table 1 to paragraph (d) of this section, the project cost of leased facilities shall be the annual lease charge multiplied by the number of years of the lease.

(2) In the interest of safety and reliability of service, facilities authorized by the certificate shall not be operated at pressures exceeding the maximum operating pressure set forth in the request. In the event that the certificate holder thereafter wishes to change the maximum operating pressure of supply or delivery lateral facilities constructed under section 7(c) of the Natural Gas Act or facilities constructed under this section, it shall file an appropriate request pursuant to the procedures set forth in § 157.205(b). Such request shall include the reasons for the proposed change. Nothing contained herein authorizes the certificate holder to operate any facility at a pressure above the maximum prescribed by State law, if such law requires a lower pressure than authorized hereby.

(g) If the actual cost of the project exceeds the per-project cost authorized under a blanket certificate in table 1 to paragraph (d) of this section, the certificate holder shall apply to the Director of the Office of Energy Projects for a waiver of those project cost limits.

[Order 234, 47 FR 24266, June 4, 1982]

Editorial Note:For Federal Register citations affecting § 157.208, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 157.209 Temporary compression facilities.

(a) Automatic authorization. If the cost does not exceed the cost limitations set forth in column 1 of table 1 to § 157.208(d), the certificate holder may install, operate and remove temporary facilities provided that the temporary compressor facilities shall not be used to increase the volume or service above that rendered by the involved existing permanent compressor unit(s).

(b) Reporting requirements. As part of the certificate holder's annual report of projects authorized under paragraph (a) of this section, the certificate holder must report the following in the manner prescribed in §§ 157.6(a) and 385.2011 of this chapter;

(1) A description of the temporary compression facility, including the size, type and number of compressor units;

(2) The location at which temporary compression was installed, operated and removed, including its location relative to existing facilities;

(3) A description of the permanent compression facility which was unavailable, and a statement explaining the reason for the temporary compression;

(4) The dates for which the temporary compression was installed, operated and removed; and

(5) If applicable, the information required in § 157.208(e)(4).

[Order 603, 64 FR 26608, May 14, 1999, as amended by Order 699, 72 FR 45325, Aug. 14, 2007; 89 FR 16684, Mar. 8, 2024]

§ 157.210 Mainline natural gas facilities.

Subject to the notice requirements of §§ 157.205(b) and 157.208(c), the certificate holder is authorized to acquire, construct, modify, replace, and operate natural gas mainline facilities, including compression and looping, that are not eligible facilities under § 157.202(b)(2)(i). The cost of a project may not exceed the cost limitation provided in column 2 of table 1 to § 157.208(d). The certificate holder must not segment projects in order to meet this cost limitation.

[Order 686, 71 FR 63693, Oct. 31, 2006, as amended at 89 FR 16684, Mar. 8, 2024]

§ 157.211 Delivery points.

(a) Construction and operation—(1) Automatic authorization. The certificate holder may acquire, construct, replace, modify, or operate any delivery point, excluding the construction of certain delivery points subject to the prior notice provisions in paragraph (a)(2) of this section if:

(i) The natural gas is being delivered to, or for the account of, a shipper for whom the certificate holder is, or will be, authorized to transport gas; and

(ii) The certificate holder's tariff does not prohibit the addition of new delivery points.

(2) Prior notice. Subject to the notice procedure in § 157.205, the certificate holder may acquire, construct, replace, modify, or operate any delivery point if:

(i) The natural gas is being delivered to, or for the account of, an end-user that is currently being served by a local distribution company; and

(ii) The natural gas is being delivered to a shipper for whom the certificate holder is, or will be, authorized to transport gas; and

(iii) The certificate holder's tariff does not prohibit the addition of new delivery points.

(b) Contents of request. In addition to the requirements of § 157.205(b), requests for activities authorized under paragraph (a)(2) must contain:

(1) The name of the end-user, the location of the delivery point, and the distribution company currently serving the end-user;

(2) A description of the facility and any appurtenant facilities;

(3) A USGS 7 1/2-minute series (scale 1:24,000 or 1:25,000) topographic map (or map of equivalent or greater detail, as appropriate) showing the location of the proposed facilities;

(4) The quantity of gas to be delivered through the proposed facility;

(5) A description, with supporting data, of the impact of the service rendered through the proposed delivery tap upon the certificate holder's peak day and annual deliveries.

(c) Reporting requirements. As part of the certificate holder's annual report of projects authorized under paragraph (a) of this section, the certificate holder must report in the manner prescribed in §§ 157.6(a) and 385.2011 of this chapter:

(1) A description of the facilities acquired, constructed, replaced, modified or operated pursuant to this section;

(2) The location and maximum quantities delivered at such delivery point;

(3) The actual cost and the completion date of the delivery point; and

(4) The date of each agreement obtained pursuant to § 157.206(b)(3) and the date construction began.

[Order 436, 50 FR 42491, Oct. 18, 1985, as amended by Order 493, 53 FR 15030, Apr. 27, 1988; Order 603, 64 FR 26608, May 14, 1999; Order 603-B, 65 FR 11464, Mar. 3, 2000]

§ 157.212 Synthetic and liquefied natural gas facilities.

Subject to the notice requirements of §§ 157.205(b) and 157.208(c), the certificate holder is authorized to acquire, construct, modify, replace, and operate natural gas facilities that are used to transport either a mix of synthetic and natural gas or exclusively revaporized liquefied natural gas and that are not “related jurisdictional natural gas facilities” as defined in § 153.2(e) of this chapter. The cost of a project may not exceed the cost limitation provided in column 2 of table 1 to § 157.208(d). The certificate holder must not segment projects in order to meet this cost limitation.

[Order 686, 71 FR 63693, Oct. 31, 2006, as amended at 89 FR 16684, Mar. 8, 2024]

§ 157.213 Underground storage field facilities.

(a) Automatic authorization. If the project cost does not exceed the cost limitations provided in column 1 of table 1 to § 157.208(d), the certificate holder may acquire, construct, modify, replace, and operate facilities for the remediation and maintenance of an existing underground storage facility, provided the storage facility's certificated physical parameters—including total inventory, reservoir pressure, reservoir and buffer boundaries, and certificated capacity remain unchanged—and provided compliance with environmental and safety provisions is not affected. The certificate holder must not alter the function of any well that is drilled into or is active in the management of the storage facility. The certificate holder must not segment projects in order to meet this cost limitation.

(b) Prior Notice. Subject to the notice requirements of §§ 157.205(b) and 157.208(c), the certificate holder is authorized to acquire, construct, modify, replace, and operate natural gas underground storage facilities, provided the storage facility's certificated physical parameters—including total inventory, reservoir pressure, reservoir and buffer boundaries, and certificated capacity remain unchanged—and provided compliance with environmental and safety provisions is not affected. The cost of a project may not exceed the cost limitation provided in column 2 of table 1 to § 157.208(d). the certificate holder must not segment projects in order to meet this cost limitation.

(c) Contents of request. In addition to the requirements of §§ 157.206(b) and 157.208(c), requests for activities authorized under paragraph (b) of this section must contain, to the extent necessary to demonstrate that the proposed project will not alter a storage reservoir's total inventory, reservoir pressure, reservoir or buffer boundaries, or certificated capacity:

(1) A description of the current geological interpretation of the storage reservoir, including both the storage formation and the caprock, including summary analysis of any recent cross-sections, well logs, quantitative porosity and permeability data, and any other relevant data for both the storage reservoir and caprock;

(2) The latest isopach and structural maps of the storage field, showing the storage reservoir boundary, as defined by fluid contacts or natural geological barriers; the protective buffer boundary; the surface and bottomhole locations of the existing and proposed injection/withdrawal wells and observation wells; and the lengths of open-hole sections of existing and proposed injection/withdrawal wells;

(3) Isobaric maps (data from the end of each injection and withdrawal cycle) for the last three injection/withdrawal seasons, which include all wells, both inside and outside the storage reservoir and within the buffer area;

(4) A detailed description of present storage operations and how they may change as a result of the new facilities or modifications. Include a detailed discussion of all existing operational problems for the storage field, including but not limited to gas migration and gas loss;

(5) Current and proposed working gas volume, cushion gas volume, native gas volume, deliverability (at maximum and minimum pressure), maximum and minimum storage pressures, at the present certificated maximum capacity or pressure, with volumes and rates in MMcf and pressures in psia;

(6) The latest field injection/withdrawal capability studies including curves at present and proposed working gas capacity, including average field back pressure curves and all other related data;

(7) The latest inventory verification study for the storage field, including methodology, data, and work papers;

(8) The shut-in reservoir pressures (average) and cumulative gas-in-place (including native gas) at the beginning of each injection and withdrawal season for the last 10 years; and

(9) A detailed analysis, including data and work papers, to support the need for additional facilities (wells, gathering lines, headers, compression, dehydration, or other appurtenant facilities) for the modification of working gas/cushion gas ratio and/or to improve the capability of the storage field.

[Order 686, 71 FR 63693, Oct. 31, 2006, as amended by Order 686-A, 72 FR 37436, July 10, 2007; 89 FR 16684, Mar. 8, 2024]

§ 157.214 Increase in storage capacity.

(a) Prior notice. Subject to the notice requirements of § 157.205, the certificate holder is authorized to increase the maximum volume of natural gas authorized to be stored in a storage field to the extent that geological data and operating experience have demonstrated that a volume of natural gas greater than that currently certificated may be safely stored without the construction of additional facilities.

(b) Contents of request. In addition to the requirements of § 157.205(b), requests filed for activities described in paragraph (a) shall contain:

(1) Current and requested maximum storage capacity;

(2) Current and requested maximum storage pressure;

(3) Average depth of the storage formation;

(4) Copies of any geological or engineering studies that demonstrate the feasibility of the increase in storage volume; and

(5) A statement setting forth the purpose of the proposed increased capacity.

(c) Reporting requirements. For any storage facility whose capacity is increased pursuant to this section, the certificate holder shall submit, in the manner prescribed in § 385.2011 of this chapter, semi-annual reports (to coincide with the termination of the injection and withdrawal cycles) containing the information listed in subdivisions (1) through (8) of this paragraph. The certificate holder shall continue to file semi-annual reports until the storage inventory volume has reached, or closely approximates, the maximum specified in the request. Thereafter, the reports shall continue on a semi-annual basis for a period of one year. The filing of reports shall be discontinued thereafter unless otherwise ordered by the Commission. (Volumes shall be stated at 14.73 psia and 60 °F, and pressures shall be stated in psia.)

(1) The daily volume of natural gas injected into and withdrawn from the storage reservoir.

(2) The volume of natural gas in the reservoir at the end of the reporting period.

(3) The maximum daily injection or withdrawal rate experienced during the reporting period and the average working pressure on such maximum days taken at a central measuring point where the total volume injected or withdrawn is measured.

(4) Results of any tracer program by which the leakage of injected gas may be determined. If the leakage of gas exists, the report should show the estimated total volume of gas leakage, the volume of recycled gas and the remaining inventory of gas in the reservoir at the end of the reporting period.

(5) Any surveys of pressures in gas wells, water levels in observation wells, pump test results for the aquifer-type reservoirs, and the results of back-pressure tests conducted during the reporting period.

(6) The latest revised structure and isopachous contour maps showing the location of the wells, the location and extent of the gas bubble in the storage reservoir for aquifer-type reservoirs and in any other reservoirs of the project in which gas bubbles are known to exist. This map need not be filed if there is no material change from the map previously filed.

(7) Discussion of current operating problems and conclusions.

(8) Such other data or reports which may aid the Commission in the evaluation of the storage project.

[Order 234, 47 FR 24266, June 4, 1982, as amended by Order 493, 53 FR 15030, Apr. 27, 1988]

§ 157.215 Underground storage testing and development.

(a) Automatic authorization. The certificate holder is authorized to acquire, construct and operate natural gas pipeline and compression facilities, including injection, withdrawal, and observation wells for the testing or development of underground reservoirs for the possible storage of gas, if:

(1) The testing and development of a particular storage project will be completed within a three-year-period;

(2) The quantity of natural gas injected into the prospective storage fields pursuant to the blanket certificate does not exceed a total of 10,000,000 Mcf at any time in all fields with no more than 2,000,000 Mcf injected into any single field;

(3) Gas will be injected for testing purposes only during off-peak periods;

(4) The storage field developed pursuant to this section will not be utilized to render service without further authorization from the Commission, except that gas may be withdrawn on occasion for testing purposes; and

(5) The total expenditures per calendar year pursuant to this section do not exceed the amount specified in table 1 to this paragraph (a)(5) as adjusted pursuant to § 157.208(d). These costs shall include expenditures for leases, wells, pipeline, compressors, and related facilities, but shall exclude the cost of the natural gas to be used for testing purposes.

Table 1 to Paragraph (a)(5)

Year | Limit

1982 | $2,700,000

1983 | 2,900,000

1984 | 3,000,000

1985 | 3,100,000

1986 | 3,200,000

1987 | 3,300,000

1988 | 3,400,000

1989 | 3,500,000

1990 | 3,600,000

1991 | 3,800,000

1992 | 3,900,000

1993 | 4,000,000

1994 | 4,100,000

1995 | 4,200,000

1996 | 4,300,000

1997 | 4,400,000

1998 | 4,500,000

1999 | 4,550,000

2000 | 4,650,000

2001 | 4,750,000

2002 | 4,850,000

2003 | 4,900,000

2004 | 5,000,000

2005 | 5,100,000

2006 | 5,250,000

2007 | 5,400,000

2008 | 5,550,000

2009 | 5,600,000

2010 | 5,700,000

2011 | 5,750,000

2012 | 5,850,000

2013 | 6,000,000

2014 | 6,100,000

2015 | 6,200,000

2016 | 6,300,000

2017 | 6,400,000

2018 | 6,500,000

2019 | 6,600,000

2020 | 6,700,000

2021 | 6,800,000

2022 | 7,100,000

2023 | 7,600,000

2024 | 7,900,000

(b) Reporting requirements—(1) Annual reports. For any storage project tested or developed pursuant to this section, the certificate holder shall file, in the manner prescribed in §§ 157.6(a) and 385.2011 of this chapter as part of the annual report required under § 157.207(a), the following information:

(i) A description of the facilities constructed and the type of storage reservoir, i.e., gas expansion or dry gas, water-drive or aquifer;

(ii) The location of the facilities;

(iii) The cost of such facilities, the date construction began, and the date they were placed in service;

(iv) The monthly volumes of gas injected into and withdrawn from each reservoir;

(v) An estimate of the storage capacity and daily deliverability of each project; and

(vi) A description of the contacts made, reports produced, and results of consultations which took place to ensure compliance with the Endangered Species Act, the National Historic Preservation Act and the Coastal Zone Management Act.

(2) Quarterly reports. If the reservoir to be tested and developed is an aquifer-type reservoir, the certificate holder shall file, in the manner prescribed in §§ 157.6(a) and 385.2011 of this chapter unless otherwise ordered by the commission, for each such project quarterly reports, under oath, until the project is either certificated for regular service or abandoned. The quarterly report shall contain the following information in addition to the data required by paragraph (b)(1) of this section:

(i) The daily volumes of natural gas injected into and withdrawn from the aquifer during the quarter and the volume of gas in the aquifer at the end of each month;

(ii) The maximum daily injection or withdrawal rate experienced during the quarter and the average working pressure on such maximum days taken at a central measuring point where the total volume injected or withdrawn is measured;

(iii) Results of any tracer program by which leakage of gas may be determined;

(iv) Any pressure surveys of gas wells and water levels in observation wells conducted during the quarter by individual well, and copies of any core analyses, gamma ray, neutron or other electric log surveys and back-pressure tests taken during the quarter;

(v) A map of the storage project showing the location of the wells, the latest revised structure contours, and the location and extent of the gas bubble. This map need not be filed if there is no material change from the map previously filed; and

(vi) Such other data or reports which may aid the Commission in the evaluation of the project.

(c) Accounting. The cost of any project ultimately determined to be infeasible for storage shall be charged to Account No. 822 of part 201, Underground Storage Exploration and Development Expenses.

[Order 234, 47 FR 24266, June 4, 1982]

Editorial Note:For Federal Register citations affecting § 157.215, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 157.216 Abandonment.

(a) Automatic authorization. The certificate holder is authorized pursuant to section 7(b) of the Natural Gas Act to abandon gas supply facilities, and:

(1) A receipt or delivery point, or related supply or delivery lateral, provided the facility has not been used to provide:

(i) Interruptible transportation service during the one year period prior to the effective date of the proposed abandonment, or

(ii) Firm transportation service during the one year period prior to the effective date of the proposed abandonment, provided the point is no longer covered under a firm contract; or

(2)(i) An auxiliary facility as described in § 2.55(a) of this chapter when the abandonment:

(A) Will not exceed the cost limit in § 157.208(d) for activities under the automatic provisions;

(B) Will have no adverse impact on customers' certificated services; and

(C) Cannot satisfy the right-of-way, facility site, and work space limitations for the pre-granted abandonment authority in § 2.55(a)(3);

(ii) A replacement facility that was or could have been constructed under § 2.55(b) of this chapter, provided the current cost to construct the facilities would not exceed the cost limit in § 157.208(d) for activities under the automatic provisions and the certificate holder obtains the written consent of each customer served using the facility during the past 12 months;

(iii) Any other facility that did or could now qualify for automatic authorization as described in § 157.203(b), provided the certificate holder obtains the written consent of each customer served using the facility during the past 12 months.

(b) Prior notice. Subject to the notice requirements of § 157.205, the certificate holder is authorized pursuant to section 7(b) of the Natural Gas Act to abandon:

(1) Any receipt or delivery point if all of the existing customers of the pipeline served through the receipt or delivery point consent in writing to the abandonment. When filing a request for authorization of the proposed abandonment under the notice procedures of § 157.205, the certificate holder shall notify, in writing, the State public service commission having regulatory authority over retail service to the customers served through the delivery point.

(2)(i) An auxiliary facility as described in § 2.55(a) of this chapter when the abandonment:

(A) Will not exceed the cost limit in § 157.208(d) for activities under the prior notice provisions;

(B) Will have no adverse impact on customers' certificated services; and

(C) Cannot satisfy the right-of-way, facility site, and work space limitations for the pre-granted abandonment authority in § 2.55(a)(3).

(ii) A replacement facility that was or could have been constructed under § 2.55(b) of this chapter, provided the current cost to construct the facilities would not exceed the cost limit in § 157.208(d) for activities under the prior notice provisions and the certificate holder obtains the written consent of each customer served using the facility during the past 12 months;

(iii) Any other facility that did or could now qualify for prior notice authorization as described in § 157.203(c), provided the certificate holder obtains the written consent of each customer served using the facility during the past 12 months.

(c) Contents of request. In addition to the requirements of § 157.205(b), requests filed for activities described under paragraph (b) shall describe:

(1) The location, type, size, and length of the subject facilities. For facilities not constructed or acquired under blanket certificate authority, an estimate of the current cost to replicate such facilities;

(2) The docket authorizing the construction and operation of the facilities to be abandoned;

(3) For each facility an oath statement that all of the customers served during the past year by the subject facilities have consented to the abandonment, or an explanation of why the customers' consent is not available;

(4) A proposed accounting treatment of any facilities to be abandoned.

(5) For any abandonment resulting in earth disturbance, a USGS 7 1/2-minute-series (scale 1:24,000 or 1:25,000) topographic map (or map of equivalent or greater detail, as appropriate) showing the location of the proposed facilities and a concise analysis discussing the relevant issues outlined in § 380.12 of this chapter.

(d) Reporting requirements. The annual report filed by the certificate holder shall contain, for each abandonment authorized under paragraph (a) of this section:

(1) A description of the facilities abandoned under this section. For facilities not constructed or acquired under blanket certificate authority, an estimate of the current cost to replicate such facilities;

(2) The docket number(s) of the certificate(s) authorizing the construction and operation of the facilities to be abandoned;

(3) The accounting treatment of the facilities abandoned; and

(4) The date earth disturbance, if any, related to the abandonment began and the date the facilities were abandoned; and

(5) The date of the agreements obtained pursuant to § 157.206(b)(3), if earth disturbance was involved.

[Order 234, 47 FR 24266, June 4, 1982, as amended by Order 234-A, 47 FR 38877, Sept. 3, 1982; Order 603, 64 FR 26609, May 14, 1999; Order 603-A, 64 FR 54536, Oct. 7, 1999; Order 686, 71 FR 63694, Oct. 31, 2006; 72 FR 54820, Sept. 27, 2007; Order 790-B, 80 FR 43949, July 24, 2015; 80 FR 50559, Aug. 20, 2015]

§ 157.217 Changes in rate schedules.

(a) Automatic authorization. The certificate holder is authorized to permit an existing customer, at the customer's request, to change from part 157 individually certificated transportation or storage service to part 284 transportation or storage service, and to abandon the part 157 service, if:

(1) The combined volumetric limitations on deliveries to the customer under both rate schedules are not increased, for either annual or peak day limitations;

(2) The conversion will reflect all the maximum rates and charges associated with the service;

(3) The changes are consistent with the terms of the effective tariffs on file with the Commission. The certificate holder is granted a limited waiver of its tariff requiring posting of available capacity.

(4) The certificate holder shall make a filing to reflect removal of the part 157 rate schedule from its tariff. This tariff filing must be filed in the electronic format required by § 154.4 of this chapter.

(b) Reporting requirements. In the annual report for any year in which the certificate holder has permitted an existing customer to change from one rate schedule to another pursuant to this section, the certificate holder shall state:

(1) The name of the customer;

(2) The rate schedules and associated rates involved; and

(3) The effective date of the change.

[Order 234, 47 FR 24266, June 4, 1982, as amended by Order 603, 64 FR 26609, May 14, 1999; Order 603-A, 64 FR 54537, Oct. 7, 1999; Order 714, 73 FR 57535, Oct. 3, 2008]

§ 157.218 Changes in customer name.

(a) Automatic authorization. The effective certificates of the certificate holder may be amended to the extent necessary to reflect the change in the name of an existing customer, if the certificate holder has filed any necessary conforming changes in its Index of Customers, including the customer's old name.

(b) Reporting requirements. For each customer name change authorized during a calendar year, the certificate holder shall include as a part of its annual report:

(1) The old and new names of the customer; and

(2) A brief explanation of the reason for the name change.

(c) Sunsetting provisions. This section shall cease to have effect on December 5, 2026, unless the Commission determines that the cessation deadline should be extended to a date not more than 5 years in the future after offering the public an opportunity to provide input on the costs and benefits of this section and considering that input. The Commission will publish a document in the Federal Register announcing its determination and revising or removing this section accordingly.

[Order 234, 47 FR 24266, June 4, 1982, as amended by Order 603, 64 FR 26609, May 14, 1999; Order 914, 90 FR 48404, Oct. 21, 2025]

§ 158.1 Notice to audited person.

An audit conducted by the Commission's staff under authority of the Natural Gas Act may result in a notice of deficiency or audit report or similar document containing a finding or findings that the audited person has not complied with a requirement of the Commission with respect to, but not limited to, the following: A filed tariff or tariffs, contracts, data, records, accounts, books, communications or papers relevant to the audit of the audited person; matters under the Standards of Conduct or the Code of Conduct; and the activities or operations of the audited person. The notice of deficiency, audit report or similar document may also contain one or more proposed remedies that address findings of noncompliance. Where such findings, with or without proposed remedies, appear in a notice of deficiency, audit report or similar document, such document shall be provided to the audited person, and the finding or findings, and any proposed remedies, shall be noted and explained. The audited person shall timely indicate in a written response any and all findings or proposed remedies, or both, in any combination, with which the audited person disagrees. The audited person shall have 15 days from the date it is sent the notice of deficiency, audit report or similar document to provide a written response to the audit staff indicating any and all findings or proposed remedies, or both, in any combination, with which the audited person disagrees, and such further time as the audit staff may provide in writing to the audited person at the time the document is sent to the audited person. The audited person may move the Commission for additional time to provide a written response to the audit staff and such motion shall be granted for good cause shown. Any initial order that the Commission subsequently may issue with respect to the notice of deficiency, audit report or similar document shall note, but not address on the merits, the finding or findings, or the proposed remedy or remedies, or both, in any combination, with which the audited person disagreed. The Commission shall provide the audited person 30 days to respond to the initial Commission order concerning a notice of deficiency, audit report or similar document with respect to the finding or findings or any proposed remedy or remedies, or both, in any combination, with which it disagreed.

[Order 675-A, 71 FR 29784, May 24, 2006]

§ 158.2 Response to notification.

Upon issuance of a Commission order that notes a finding or findings, or proposed remedy or remedies, or both, in any combination, with which the audited person has disagreed, the audited person may: Acquiesce in the findings and/or proposed remedies by not timely responding to the Commission order, in which case the Commission may issue an order approving them or taking other action; or challenge the finding or findings and/or any proposed remedies, with which it disagreed by timely notifying the Commission in writing that it requests Commission review by means of a shortened procedure or, if there are material facts in dispute which require cross-examination, a trial-type hearing.

[Order 675, 71 FR 9706, Feb. 27, 2006]

§ 158.3 Shortened procedure.

If the audited person subject to a Commission order described in § 158.1 notifies the Commission that it seeks to challenge one or more audit findings, or proposed remedies, or both, in any combination, by the shortened procedure, the Commission shall thereupon issue a notice setting a schedule for the filing of memoranda. The person electing the use of the shortened procedure, and any other interested entities, including the Commission staff, shall file, within 45 days of the notice, an initial memorandum that addresses the relevant facts and applicable law that support the position or positions taken regarding the matters at issue. Reply memoranda shall be filed within 20 days of the date by which the initial memoranda are due to be filed. Only participants who filed initial memoranda may file reply memoranda. Subpart T of part 385 of this chapter shall apply to all filings. Within 20 days after the last date that reply memoranda under the shortened procedure may be timely filed, the audited person who elected the shortened procedure may file a motion with the Commission requesting a trial-type hearing if new issues are raised by a party. To prevail in such a motion, the audited person must show that a party to the shortened procedure raised one or more new issues of material fact relevant to resolution of a matter in the shortened procedure such that fundamental fairness requires a trial-type hearing to resolve the new issue or issues so raised. Parties to the shortened procedure and the Commission staff may file responses to the motion. In ruling upon the motion, the Commission may determine that some or all of the issues be litigated in a trial-type hearing.

[Order 675, 71 FR 9706, Feb. 27, 2006]

§ 158.4 Form and style.

Each memoranda must be complete in itself. All pertinent data should be set forth fully, and each memorandum should set out the facts and argument as prescribed for briefs in § 385.706 of this chapter.

[Order 141, 12 FR 8603, Dec. 19, 1947, as amended by Order 225, 47 FR 19057, May 3, 1982]

§ 158.5 Verification.

The facts stated in the memorandum must be sworn to by persons having knowledge thereof, which latter fact must affirmatively appear in the affidavit. Except under unusual circumstances, such persons should be those who would appear as witnesses if hearing were had to testify as to the facts stated in the memorandum.

§ 158.6 Determination.

If no formal hearing is had the matter in issue will be determined by the Commission on the basis of the facts and arguments submitted.

§ 158.7 Assignment for oral hearing.

In case consent to the shortened procedure is not given, or if at any stage of the proceeding prior to the submission of the case to the Commission any party in interest requests a hearing, the proceeding will be assigned for hearing as provided for by subpart E of part 385 of this chapter. The Commission may also in its discretion set the proceeding for hearing on its own motion at any stage thereof.

[Order 141, 12 FR 8603, Dec. 19, 1947, as amended by Order 225, 47 FR 19057, May 3, 1982]

§ 158.8 Burden of proof.

The burden of proof to justify every accounting entry shall be on the person making, authorizing, or requiring such entry.

Certification of Compliance with Accounting Regulations

§ 158.10 Examination of accounts.

All natural gas companies not classified as Class C or Class D prior to January 1, 1984 shall secure for each year, the services of an independent certified public accountant, or independent licensed public accountant (licensed on or before December 31, 1970), certified or licensed by a regulatory authority of a State or other political subdivision of the United States, to test compliance in all material respects of those schedules that are indicated in the General Instructions set out in the applicable Annual Report, Form No. 2 or Form No. 2-A, with the Commission's Uniform System of Accounts and published accounting releases. The Commission expects that identification of questionable matters by the independent accountant will facilitate their early resolution and that the independent accountant will seek advisory rulings by the Commission on such items. This examination shall be deemed supplementary to periodic Commission examinations of compliance.

[Order 581, 60 FR 53065, Oct. 11, 1995]

§ 158.11 Report of certification.

Each natural gas company not classified as Class C or Class D prior to January 1, 1984 must file with the Commission by May 18 of the following calendar year, a letter or report of the independent accountant certifying approval, covering the subjects and in the format prescribed in the General Instructions of the applicable Form No. 2 or Form No. 2-A. The letter or report must also identify which, if any, of the examined schedules do not conform to the Commission's requirements and must describe the discrepancies that exist. The Commission will not be bound by the certification of compliance made by an independent accountant under this paragraph.

[Order 710, 73 FR 19399, Apr. 10, 2008]

§ 158.12 Qualifications of accountants.

The Commission will recognize only independent certified public accountants, or independent licensed public accountants who were licensed on or before December 31, 1970, who are in fact independent. For example, an accountant will not be considered independent with respect to any person or any of its parents or subsidiaries in who he has, or had during the period of report, any direct financial interest. The Commission will determine the fact of independence by considering all the relevant circumstances including evidence bearing on the relationships between the accountant and that person or any affiliate thereof.

(Sec. 10, 52 Stat. 826; 15 U.S.C. 717i)

[37 FR 26006, Dec. 7, 1972, as amended at 60 FR 53065, Oct. 11, 1995]

§ 225.1 Promulgation.

This part is prescribed and promulgated as the regulations governing the preservation of records by natural gas companies subject to the jurisdiction of the Commission, to the extent and in the manner set forth therein.

[Order 617, 65 FR 48160, Aug. 7, 2000]

§ 225.2 General instructions.

(a) Scope of this part. (1) The regulations in this part must apply to all books of account and other records prepared by or on behalf of the natural gas company. See item 40 of the schedule for those records that come into possession of the natural gas company in connection with the acquisition of property, such as purchases, consolidation, merger, etc.

(2) The regulations in this part should not be construed as excusing compliance with other lawful requirements of any other governmental body, Federal or State, prescribing other record keeping requirements, or for preservation of records for periods longer than those prescribed in this part.

(3) To the extent that any Commission regulations may provide for a different retention period, the records should be retained for the longer of the retention periods.

(4) Records other than those listed in the schedule may be destroyed at the option of the natural gas company: Provided, however, That records which are used in lieu of those listed shall be preserved for the periods prescribed for the records used for substantially similar purposes. And, provided further, That retention of records pertaining to added services, functions, plant, etc., the establishment of which cannot be presently foreseen, shall conform to the principles embodied herein.

(5) Notwithstanding the provisions of the Records Retention Schedule, the Commission may, upon the request of the company, authorize a shorter period of retention for any record listed therein upon a showing by the company that preservation of such record for a longer period is not necessary or appropriate in the public interest or for the protection of investors or consumers.

(b) Designation of supervisory official. Each natural gas company subject to the regulations in this part shall designate one or more persons with official responsibility to supervise the natural gas company's program for preservation and the authorized destruction of its records.

(c) Protection and storage of records. The natural gas company shall provide reasonable protection for records subject to the regulations in this part from damage by fires, floods, and other hazards and, in the selection of storage spaces, safeguard the records from unnecessary exposure to deterioration from excessive humidity, dryness, or lack of proper ventilation.

(d) Record storage media. Each natural gas company has the flexibility to select its own storage media subject to the following conditions.

(1) The storage media must have a life expectancy at least equal to the applicable record retention period provided in § 225.3 unless there is a quality transfer from one media to another with no loss of data.

(2) Each natural gas company is required to implement internal control procedures that assure the reliability of and ready access to data stored on machine readable media. Internal control procedures must be documented by a responsible supervisory official.

(3) Each transfer of data from one media to another must be verified for accuracy and documented. Software and hardware required to produce readable records must be retained for the same period the media format is used.

(e) Destruction of records. At the expiration of the records retention period, natural gas companies may use any appropriate method to destroy records.

(f) Premature destruction or loss of records. When records are destroyed or lost before the expiration of the prescribed period of retention, a certified statement listing, as far as may be determined, the records destroyed and describing the circumstances of accidental or other premature destruction or loss must be filed with the Commission within ninety (90) days from the date of discovery of the destruction.

(g) Schedule of records and periods of retention. (1) Records related to plant in service must be retained until the facilities are permanently removed from service, all removal and restoration activities are completed, and all costs are retired from the accounting records unless accounting adjustments resulting from reclassification and original costs studies have been approved by the regulatory commission having jurisdiction. If the plant is sold, the associated records or copies thereof, must be transferred to the new owners.

(2) Records related to additions, retirements, and betterments thereto must be retained until the Commission has determined the actual legitimate original cost of the facilities.

(h) Retention periods designated “Destroy at option”. “Destroy at option” constitutes authorization for destruction of records at managements' discretion if it does not conflict with other legal retention requirements or usefulness of such records in satisfying pending regulatory actions or directives.

(i) Records of services performed by associated companies. The natural gas companies must assure the availability of records of services performed by associated or affiliated companies with supporting cost information for the periods indicated in § 225.3 as necessary to be able to readily furnish detailed information as to the nature of the transaction, the amounts involved, and the accounts used to record the transactions.

(j) Index of records. Natural gas companies must arrange, file, and index records so they may be readily identified and made available to Commission representatives.

(k) Rate case. Notwithstanding the minimum retention periods provided in these regulations, if a natural gas company intends to reflect costs in a current, pending, or future rate case, or if a natural gas company has abandoned or retired a plant subsequent to the test period of its last rate case, it must retain all relevant records.

(l) Pending complaint litigation or governmental proceeding. Notwithstanding the minimum requirements, if a natural gas company is involved in pending litigation, complaint procedures, proceedings remanded by the court, or governmental proceedings, it must retain all relevant records.

(m) Life or mortality study data. Life or mortality study data for depreciation purposes must be retained for 25 years or for 10 years after plant is retired whichever is longer.

[Order 450, 37 FR 6304, Mar. 28, 1972, as amended by Order 258, 47 FR 42724, 42725, Sept. 29, 1982; Order 335, 48 FR 44483, Sept. 29, 1983; Order 617, 65 FR 48160, Aug. 7, 2000]

§ 225.3 Schedule of records and periods of retention.

Table of Contents Corporate and General 1. Reports to stockholders. 2. Organizational documents. 3. Contracts including amendments and agreements. 4. Accountants' and auditors' reports. Information Technology Management 5. Automatic data processing records. General Accounting Records 6. General and subsidiary ledgers. 7. Journals: General and subsidiary. 8. Journal vouchers and journal entries. 9. Cash books. 10. Voucher registers. 11. Vouchers. Insurance 12. Insurance records. Operations and Maintenance 13. Production—Gas. 14. Transmission and distribution—Gas. 14.1. Underground storage of natural gas. 15. Maintenance work orders and job orders. Plant and Depreciation 16. Plant ledgers. 17. Construction work in progress ledgers. 18. Retirement work in progress ledgers. 19. Summary sheets. 20. Appraisals and valuations. 21. Engineering records. 22. Contracts relating to natural gas. 23. Reclassification of natural gas plant account records. 24. Accumulated depreciation and depletion of natural gas plant account records. Purchase and Stores 25. Procurement. 26. Material ledgers. 27. Materials and supplies received and issued. 28. Records of sales of scrap and materials and supplies. Revenue Accounting and Collection 29. Customers' service applications and contracts. 30. Rate schedules. 31. Maximum demand and demand meter record cards. 32. Miscellaneous billing data. 33. Revenue summaries. Tax 34. Tax records. Treasury 35. Statements of funds and deposits. 36. Records of deposits with banks and others. 37. Records of receipts and disbursements. Miscellaneous 38. Statistics. 39. Budgets and other forecasts. 40. Records of predecessors companies. 41. Reports to Federal and State regulatory commissions. 42. Advertising.

Schedule of Records and Periods of Retention

Item No. and description | Retention period

Corporate and General

1. Reports to stockholders: Annual reports or statements to stockholders | 5 years.

2. Organizational documents:

(a) Minute books of stockholders', directors', and directors' committee meetings | 5 years or termination of the corporation's existence, whichever occurs first.

(b) Titles, franchises, and licenses: Copies of formal orders of regulatory commissions served upon the natural gas company | 6 years after final non-appealable order.

3. Contracts including amendments and agreements (except contracts provided for elsewhere):

(a) Service contracts, such as for management, accounting, and financial services | All contracts, related memoranda, and revisions should be retained for 4 years after expiration or until the conclusion of any contract disputes pertaining to such contracts, whichever is later.

(b) Contracts with others for transportation or for the purchase, sale or interchange of product | All contracts, related memoranda, and revisions should be retained for 4 years after expiration or until the conclusion of any contract disputes or governmental proceedings pertaining to such contracts, whichever is later.

(c) Memoranda essential to clarifying or explaining provisions of contracts listed above, including requests for discounts | For the same periods as contracts to which they relate.

(d) Card or book records of contracts, leases, and agreements made that show dates of expirations, renewals, memoranda of receipts, and payments under such contracts | For the same periods as contracts to which they relate.

4. Accountants' and auditors' reports:

(a) Reports of examinations and audits by accountants and auditors not in the regular employ of the natural gas company (such as reports of public accounting firms and Commission accountants) | 5 years after the date of the report.

(b) Internal audit reports and working papers | 5 years after the date of the report.

Information Technology Management

5. Automatic data processing records (retain original source data used as input for data processing and data processing report printouts for the applicable periods prescribed elsewhere in the schedule): Software program documentation and revisions thereto. | Retain as long as it represents an active viable program or for periods prescribed for related output data, whichever is shorter.

General Accounting Records

6. General and subsidiary ledgers:

(a) Ledgers:

(1) General ledgers | 10 years.

(2) Ledgers subsidiary or auxiliary to general ledgers except ledgers provided for elsewhere | 10 years.

(b) Indexes:

(1) Indexes to general ledgers | 10 years.

(2) Indexes to subsidiary ledgers except ledgers provided for elsewhere | 10 years.

(c) Trial balance sheets of general and subsidiary ledgers | 2 years.

7. Journals: General and subsidiary | 10 years.

8. Journal vouchers and journal entries including supporting detail:

(a) Journal vouchers and journal entries | 10 years.

(b) Analyses, summarizations, distributions, and other computations which support journal vouchers and journal entries:

(1) Charging plant accounts | 25 years. See § 225.2(g).

(2) Charging all other accounts | 6 years.

9. Cash books: General and subsidiary or auxiliary books | 5 years after close of fiscal year.

10. Voucher registers: Voucher registers or similar records when used as a source document | 5 years. See § 225.2(g).

11. Vouchers:

(a) Paid and canceled vouchers (1 copy-analysis sheets showing detailed distribution of charges on individual vouchers and other supporting papers) | 5 years. See § 225.2(g).

(b) Original bills and invoices for materials, services, etc., paid by vouchers | 5 years. See § 225.2(g).

(c) Paid checks and receipts for payments of specific vouchers | 5 years.

(d) Authorization for the payment of specific vouchers | 5 years. See § 225.2(g).

(e) Lists of unaudited bills (accounts payable), list of vouchers transmitted, and memoranda regarding changes in audited bills | Destroy at option.

(f) Voucher indexes | Destroy at option.

Insurance

12. Insurance records:

(a) Records of insurance policies in force, showing coverage, premiums paid, and expiration dates | Destroy at option after expiration.

(b) Records of amounts recovered from insurance companies in connection with losses and of claims against insurance companies, including reports of losses, and supporting papers | 6 years. See § 225.2(g).

Operations and Maintenance

13. Production—Gas:

(a) Recording instrument charts such as pressure (static and/or differential), temperature, specific gravity, heating value, etc | If the measurement data have not been disputed or adjusted, destroy after 1 year.

(b) Test of heating value at stations and outlying points | If the measurement data have not been disputed or adjusted, destroy after 1 year.

(c) Records of gas produced, out, and holder stock | If the measurement data have not been disputed or adjusted, destroy after 1 year.

(d) Analysis of (gas produced) B.T.U. and sulphur content | If the measurement data have not been disputed or adjusted, destroy after 1 year.

(e) Well records, including clearing, bailing, shooting etc., records; rock pressure; open flow; production, gas analysts' reports etc | 1 year after field or relevant production area abandoned

(f) Gas measuring records | If the measurement data have not been disputed or adjusted, destroy after 1 year.

14. Transmission and distribution—Gas:

(a) Substation and transmission line log | If the measurement data have not been disputed or adjusted, destroy after 1 year.

(b) System operator's daily logs and reports of operation | If the measurement data have not been disputed or adjusted, destroy after 1 year.

(c) Gas measuring records | If the measurement data have not been disputed or adjusted, destroy after 1 year.

(d) Transmission line operating reports | If the measurement data have not been disputed or adjusted, destroy after 1 year.

(e) Compression operation and reports | If the measurement data have not been disputed or adjusted, destroy after 1 year.

(f) Recording instrument charts such as pressure (static and/or differential), temperature, specific heating value, etc | If the measurement data have not been disputed or adjusted, destroy after 1 year.

14.1 Underground storage of natural gas:

(a) Well records, reports, and logs which include data relating to pressures, injected volumes, withdrawn volumes, core analysis, daily volumes of gas injected into and withdrawn from reservoir, cushion, and working gas volumes for each reservoir | 1 year after reservoir, field, or relevant storage area is abandoned.

(b) Records containing information relating to reservoir gas leakage, showing the total gas leakage, and recycled gas | 1 year after reservoir, field, or relevant storage area is abandoned.

(c) Records on back pressure tests field data | 1 year or until superseded.

(d) Records on back pressure test results, gas analysis | 1 year or until superseded.

15. Maintenance work orders and job orders:

(a) Authorizations for expenditures for maintenance work to be covered by work orders, including memoranda showing the estimates of costs to be incurred | 5 years.

(b) Work order sheets to which are posted in detail the entries for labor, material, and other charges in connection with maintenance, and other work pertaining to natural gas company operations | 5 years.

(c) Summaries of expenditures on maintenance and job orders and clearances to operating other accounts (exclusive of plant accounts) | 5 years.

Plant and Depreciation

16. Plant ledgers:

(a) Ledgers of natural gas company's plant accounts including land and other detailed ledgers showing the cost of plant by class | 25 years. See § 225.2(g).

(b) Continuing plant inventory ledger, book or card records showing description, location, quantities, cost, etc., of physical units (or items) of natural gas plant owned | 25 years. See § 225.2(g).

17. Construction work in progress ledgers:

(a) Construction work in progress ledgers | 5 years after clearance to the plant account, provided continuing plant inventory records are maintained; otherwise 5 years after plant is retired.

(b) Work order sheets to which are posted in summary form or in detail the entries for labor, materials, and other charges for natural gas company's plant additions and the entries closing the work orders to plant in service at completion | 5 years after clearance to the plant account, provided continuing plant inventory records are maintained; otherwise 5 years after plant is retired.

(c) Authorizations for expenditures for additions to natural gas company plant, including memoranda showing the detailed estimates of cost, and the bases therefor (including original and revised or subsequent authorizations) | 5 years after clearance to the plant account, provided continuing plant inventory records are maintained; otherwise 5 years after plant is retired.

(d) Requisitions and registers of authorizations for natural gas company plant expenditures | 5 years after clearance to the plant account, provided continuing plant inventory records are maintained; otherwise 5 years after plant is retired.

(e) Completion or performance reports showing comparison between authorized estimates and actual expenditures for natural gas company plant additions | 5 years after clearance to the plant account, provided continuing plant inventory records are maintained; otherwise 5 years after plant is retired.

(f) Analysis or cost reports showing quantities of materials used, unit costs, number of man-hours etc., in connection with completed construction project | 5 years after clearance to the plant account, provided continuing plant inventory records are maintained; otherwise 5 years after plant is retired.

(g) Records and reports pertaining to progress of construction work, the order in which jobs are to be completed, and similar records which do not form a basis of entries to the accounts | Destroy at option.

(h) Well-drilling logs and well construction records | 1 year after field or well is abandoned.

18. Retirement work in progress ledgers, work orders, and supplemental records:

(a) Work order sheets to which are posted the entries for removal costs, materials recovered, and credits to natural gas company plant accounts for cost of plant retirement | 5 years after plant is retired.

(b) Authorizations for retirement of natural gas company plant, including memoranda showing the basis for determination of cost of plant to be retired, and estimates of salvage and removal costs | 5 years after plant is retired.

(c) Registers of retirement work | 5 years.

19. Summary sheets, distribution sheets, reports, statements, and papers directly supporting debits and credits to natural gas company plant accounts not covered by construction or retirement work orders and their supporting records | 5 years.

20. Appraisals and valuations:

(a) Appraisals and valuations made by the company of its properties or investments or of the properties or investments of any associated companies. Includes all records essential thereto | 3 years after appraisal.

(b) Determinations of amounts by which properties or investments of the company or any of its associated companies will be either written up or written down as a result of:

(1) Mergers or acquisitions | 10 years after completion of transaction or as ordered by the Commission.

(2) Asset impairments | 10 years after recognition of asset impairment.

(3) Other bases | 10 years after the asset was written up or down.

21. The original or reproduction of engineering records, drawings, and other supporting data for proposed or as-constructed gas facilities: Maps, diagrams, profiles, photographs, field survey notes, plot plan, detail drawings, records of engineering studies, and similar records showing the location of proposed or as-constructed facilities | Retained until retired or abandoned.

22. Contracts relating to natural gas plant:

(a) Contracts relating to acquisition or sale of plant | 6 years after plant is retired or sold.

(b) The primary records of gas acreage owned, leased or optioned excluding deeds and leases but including such records as lease sheets, leasehold cards, and option agreements | 6 years after plant is retired or sold.

23. Records pertaining to reclassification of natural gas plant accounts to conform to prescribed systems of accounts including supporting papers showing the bases for such reclassifications | 6 years.

24. Records of accumulated provisions for depreciation and depletion of gas plant and supporting computation of expense:

(a) Detailed records or analysis sheets segregating the accumulated depreciation according to functional classification of plant | 25 years.

(b) Records reflecting the service life of property and the percentage of salvage and cost of removal for property retired from each account for depreciable natural gas plant | 25 years.

Purchases and Stores

25. Procurement:

(a) Agreements entered into for the acquisition of goods or the performance of services. Includes all forms of agreements not specifically set forth in Subsection 7 such as but not limited to: Letters of intent, exchange of correspondence, master agreements, term contracts, rental agreements, and the various types of purchase orders:

(1) For goods or services relating to plant construction | 6 years. See § 225.2(g).

(2) For other goods or services | 6 years.

(b) Supporting documents including accepted and unaccepted bids or proposals (summaries of unaccepted bids or proposals may be kept in lieu of originals) evidencing all relevant elements of the procurement | 6 years. See § 225.2(g).

26. Material ledgers: Ledger sheets of materials and supplies received, issued, and on hand | 6 years after the date records/ledgers were created.

27. Materials and supplies received and issued: Records showing the detailed distribution of materials and supplies issued during accounting periods | 6 years. See § 225.2(g).

28. Records of sales of scrap and materials and supplies:

(a) Authorization for sale of scrap and materials and supplies | 3 years.

(b) Contracts for sale of scrap and materials and supplies | 3 years.

Revenue Accounting and Collection

29. Customers' service applications and contracts: Contracts, including amendments for extensions of service, for which contributions are made by customers and others | 4 years after expiration.

30. Rate schedules: General files of published rate sheets and schedules of natural gas company service (including schedules suspended or superseded) | 6 years after published rate sheets and schedules are superseded or no longer used to charge for services.

31. Maximum demand, pressure, temperature, and specific gravity charts and demand meter record card | If the measurement data have not been disputed or adjusted, destroy after 1 year.

32. Miscellaneous billing data: Billing department's copies of contracts with customers (other than contracts in general files) | Destroy at option.

33. Revenue summaries: Summaries of monthly operating revenues according to classes of service. Including summaries of forfeited discounts and penalties | 5 years.

Tax

34. Tax records:

(a) Copies of tax returns and supporting schedules filed with taxing authorities, supporting working papers, records of appeals of tax bills, and receipts for payment. See Subsection 11(b) for vouchers evidencing disbursements:

(1) Income tax returns | 2 years after final tax liability is determined.

(2) Property tax returns | 2 years after final tax liability is determined.

(3) Sales and other use taxes | 2 years.

(4) Other taxes | 2 years after final tax liability is determined.

(5) Agreements between associate companies as to allocation of consolidated income taxes | 2 years after final tax liability is determined.

(6) Schedule of allocation of consolidated Federal income taxes among associate companies | 2 years after final tax liability is determined.

(b) Filings with taxing authorities to qualify employee benefit plans | 5 years after discontinuance of plan.

(c) Information returns and reports to taxing authorities | 3 years after final tax liability is determined.

Treasury

35. Statements of funds and deposits:

(a) Statements of periodic deposits with fund administrators or trustees | Retain records for the most recent 3 years.

(b) Statements of periodic withdrawals from fund | Retain records for the most recent 3 years.

(c) Statements prepared by fund administrator or trustees of fund activity including: | Retain records until the fund is dissolved or terminated.

(1) Beginning of the year fund balance

(2) Deposits with the fund;

(3) Acquisition of investments held by the fund;

(4) Disposition of investments held by the fund;

(5) Disbursements from the fund, including party to whom disbursement was made; and,

(6) End of year fund balance.

36. Records of deposits with banks and others:

(a) Statements from depositories showing the details of funds received, disbursed, transferred, and balances on deposit | Destroy at option after completion of audit by independent accountants.

(b) Check stubs, registers, or other records of checks issued | 3 years.

37. Records of receipts and disbursements:

(a) Daily or other periodic statements of fund receipts or disbursements | Destroy at option after completion of annual audit by independent accountants.

(b) Records or periodic statements of outstanding vouchers, checks, drafts, etc., issued and not presented | Destroy at option after completion of annual audit by independent accountants.

(c) Reports of associates showing working fund transactions and summaries thereof | Destroy at option after completion of annual audit by independent accountants.

(d) Reports of revenue collections by field cashiers, pay stations, etc | Destroy at option after completion of annual audit by independent accountants.

Miscellaneous

38. Statistics: Financial, operating, and statistical reports used for internal administrative or operating purposes | 5 years.

39. Budgets and other forecasts (prepared for internal administrative or operating purposes) of estimated future income, receipts, and expenditures in connection with financing, construction and operations, including acquisitions and disposals of properties or investments | 3 years.

40. Records of predecessor companies | Retain consistent with the requirements for the same types of records of the natural gas company.

41. Reports to Federal and State regulatory commissions including annual financial, operating, and statistical reports | 5 years.

42. Advertising: Copies of advertisements by or for the company on behalf of itself or any associate company in newspapers, magazines, and other publications, including costs and other records relevant thereto (excluding advertising of appliances, employment opportunities, routine notices, and invitations for bids all of which may be destroyed at option) | 2 years.

[Order 617, 65 FR 48161, Aug. 7, 2000; 65 FR 50638, Aug. 21, 2000]

§§ 250.1-250.5 [Reserved]

§ 250.6 Form of application to be filed by distributor under section 7(a), seeking gas service of not more than 2,000 Mcf per day (3d year of operation) for a single community (see § 156.3(d) of this chapter).

1. Name of applicant (indicate whether individual, corporation or municipality).

2. Address.

3. Name, title, mailing address, and telephone number of person to be contacted concerning the application.

4. Name of natural gas company from whom service is desired.

5. Are you now rendering gas service? If so, briefly describe operations.

6. Nature of service sought, giving a brief description of proposal, including location of community, population, number of residences and kind of service sought and to be rendered, showing:

(a) Is this an initial connection with the pipe line, or is it an extension or improvement of existing facilities?

(b) Estimate of maximum day requirements for residential, commercial and industrial customers for each of the first three years of proposed operations (Mcf at 14.73 psia), and how the estimates were derived;

(c) Estimate of annual requirements for residential, commercial and industrial customers for each of the first three years of proposed operations (Mcf at 14.73 psia), and how the estimates were derived.

7. Do you have or do you need a franchise to render the proposed service? If you have filed an application for such a franchise, with whom was it filed and what action has been taken on it?

8. Do you have or do you need a state certificate approving the proposed distribution system project? If you have filed an application for such a certificate, with whom was it filed and what action has been taken on it?

9. When do you propose to start construction and when do you estimate it will be completed? When do you propose to start selling gas?

10. How much are the facilities expected to cost? Show separately the estimated cost of the distribution system, the connecting supply lines, legal fees, financing fees and engineering fees, and briefly state how the estimates were derived.

11. Have you used the services of an engineering consultant? If so, the consultant should state his experience in the design of distribution systems, cost data of systems now in service compared with his initial estimates, and the actual rate at which new customers were attached in the new distribution systems.

12. How do you propose to finance the proposed facilities? Submit evidence that the money will be available. (This evidence need not be submitted if you have a state certificate for your project.)

13. For each of the first three years of operation of the proposed facilities, show (a) the estimated gross annual revenues for the natural gas estimated to be sold to residential, commercial and industrial customers as shown in item 6(c) and the rates you propose to charge, and (b) the cost of gas purchased by you (state the rate to be paid to the pipeline supplier and the pipeline's rate schedule under which you will purchase said gas), other operating and maintenance expenses and operating revenue deductions, and (c) the net operating revenues. If you have received a certificate of public convenience and necessity issued by a local regulatory commission, it may be submitted in lieu of this requirement.

14. Municipalities should submit a bond amortization and interest schedule for the life of the bond issue related to the project and computation of the average debt service coverage ratio over the life of the issue. State briefly how all estimates were derived. Exhibits to be furnished:

Exhibit A. A geographical map showing clearly all of the transmission facilities proposed to be installed and operated by you between your distribution system and the transmission pipeline system of the proposed supplier, including:

(a) Location, length and size of your transmission lines;

(b) Location and size (related horsepower) of your transmission compressor stations (if any);

(c) Location and designation of each point of connection of your proposed transmission facilities with proposed pipeline supplier;

(d) And if known, location, length and size of facilities to be installed by the proposed supplier.

Exhibit B. A flow diagram showing the maximum daily capacity of the proposed connecting pipeline to carry gas from the supplier to the community to be served. The diagram should show expected operating pressures on the connecting pipeline at the point of connection with the supplier and at the other terminal of the connecting pipeline flow of gas through the connecting pipeline in Mcf per day; length of the connecting pipeline and its inside and outside diameter.

[Order 280, 29 FR 4879, Apr. 7, 1964]

§§ 250.7-250.15 [Reserved]

§ 250.16 Format of compliance plan for transportation services and affiliate transactions.

(a) Who must comply. An interstate natural gas pipeline that transports natural gas for others pursuant to Subparts B or G of Part 284 of this chapter and is affiliated, as that term is defined in § 358.3 of this chapter, in any way with a natural gas marketing or brokering entity and conducts transportation transactions with its marketing or brokering affiliate must comply with the requirements of this section. The requirements of this section also apply to pipeline sales operating units to the extent provided in § 284.286 of this chapter.

(b) Tariff requirements. An interstate pipeline must maintain tariff provisions containing the following:

(1) The procedures used to address and resolve complaints by shippers and potential shippers including a provision that the pipeline will respond within 48 hours and in writing within 30 days to such complaints.

(2) [Reserved]

(c) Log of data used to allocate capacity. (1) An interstate pipeline that relies upon contract information or other data to allocate capacity must maintain a log showing, for each transportation contract (both for marketing affiliates and non-affiliates) on its system: the shipper's name (including a designation whether the shipper is a local distribution company, an interstate pipeline, an intrastate pipeline, an end-user, a producer, a marketer, or a pipeline sales operating unit); the shipper's affiliation with the pipeline; the contract number; and the applicable dates or other information used to allocate capacity under its tariff. The log data relating to each contract must be maintained as long as the contract is used to allocate capacity and for three years after the contract data is no longer used for capacity allocation.

(2) The current log of allocation data for marketing affiliates must be posted on the pipeline's Internet Web site, operated pursuant to § 284.12 of this chapter. The posting must conform with the requirements of § 284.12 of this chapter and the pipeline's tariff requirements relating to Internet Web sites. Access to the information must be provided using the same protocols and procedures used for the pipeline's Internet Web site.

(3) The log of affiliate and non-affiliate information must be provided to the Commission upon request and must be made available to the public under 18 CFR part 385, subpart D. When requested by the Commission, the information must be provided, within a reasonable time, according to the specifications and format contained in Form No. 592, which can be obtained on the Commission's website, https://www.ferc.gov.

(d) Transportation Discount Information. (1) A pipeline that provides transportation service at a discounted rate must maintain, for each billing period, the following information: the name of the shipper being provided the discount; the affiliate's role in the transportation transaction (i.e., shipper, marketer, supplier, seller); the duration of the discount; the maximum rate or fee; the rate or fee actually charged during the billing period; and the quantity of gas scheduled at the discounted rate during the billing period for each delivery point. The discount information with respect to each transaction must be maintained for three years from the date the transaction commences.

(2) The discount information must be made available to the Commission upon request and to the public under 18 CFR part 385, subpart D. When requested by the Commission, the information must be provided, within a reasonable time, according to the specifications and format contained in Form No. 592, which can be obtained on the Commission's website, https://www.ferc.gov.

(e) Penalty for failure to comply. (1) Any person who transports gas for others pursuant to subpart B or G of part 284 of this chapter and who knowingly violates the requirements of §§ 358.4 and 358.5 of this chapter, this section, or § 284.13 of this chapter will be subject, pursuant to sections 311(c), 501, and 504(b)(6) of the Natural Gas Policy Act of 1978, to a civil penalty, which the Commission may assess, of not more than $1,584,648 for any one violation.

(2) For purposes of this paragraph, in the case of a continuing violation, each day of the violation will constitute a separate violation.

[Order 566, 59 FR 32898, June 27, 1994]

Editorial Note:For Federal Register citations affecting § 250.16, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 260.1 FERC Form No. 2, Annual report for Major natural gas companies.

(a) Prescription. The form of Annual Report of Natural Gas Companies (Class A and Class B), designated herein as FERC Form No. 2, is prescribed.

(b) Filing requirements. Each natural gas company, as defined by the Natural Gas Act (15 U.S.C. 717, et seq.) which is a major company (a natural gas company whose combined gas transported or stored for a fee exceed 50 million Dth in each of the three previous calendar years) must prepare and file with the Commission, as follows:

(1) The annual report for the year ending December 2004 must be filed on April 25, 2005.

(2) The annual report for each year thereafter must be filed on April 18 of the subsequent year.

(3) Newly established entities must use projected data to determine whether FERC Form No. 2 must be filed.

(4) The form must be filed in electronic format only, as indicated in the general instructions set out in that form. The format for the electronic filing is available through the Commission's website, https://www.ferc.gov. One copy of the report must be retained by the respondent in its files.

[Order 121, 46 FR 6887, Jan. 22, 1981, as amended by Order 390, 49 FR 32527, Aug. 14, 1984; Order 493, 53 FR 15030, Apr. 27, 1988; Order 581, 60 FR 53071, Oct. 11, 1995; Order 628, 68 FR 269, Jan. 3, 2003; 69 FR 9044, Feb. 26, 2004; Order 899, 88 FR 74031, Oct. 30, 2023]

§ 260.2 FERC Form No. 2-A, Annual report for Nonmajor natural gas companies.

(a) Prescription. The form of Annual Report for Nonmajor Natural Gas Companies, designated herein as FERC Form No. 2—A, is prescribed.

(b) Filing requirements. Each natural gas company, as defined by the Natural Gas Act, not meeting the filing threshold for FERC Form No. 2, but having total gas sales or volume transactions exceeding 200,000 Dth in each of the three previous calendar years, must prepare and file with the Commission, as follows:

(1) The annual report for the year ending December 2004 must be filed on April 25, 2005.

(2) The annual report for each year thereafter must be filed on April 18 of the subsequent year.

(3) Newly established entities must use projected data to determine whether FERC Form No. 2-A must be filed.

(4) The form must be filed in electronic format only, as indicated in the General Instructions set out in that form. The format for the electronic filing is available through the Commission's website, https://www.ferc.gov. One copy of the report must be retained by the respondent in its files.

(Natural Gas Act, as amended, 15 U.S.C. 717-717w; Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432; Federal Power Act, as amended, 16 U.S.C. 792-828c; Department of Energy Organization Act, 42 U.S.C. 7101-7352; E.O. 12009, 3 CFR part 142 (1978))

[Order 101, 45 FR 60900, Sept. 15, 1980, as amended by Order 390, 49 FR 32527, Aug. 14, 1984; Order 493, 53 FR 15031, Apr. 27, 1988; Order 581, 60 FR 53071, Oct. 11, 1995; Order 628, 68 FR 269, Jan. 3, 2003; 69 FR 9044, Feb. 26, 2004; Order 899, 88 FR 74031, Oct. 30, 2023]

§§ 260.4-260.7 [Reserved]

§ 260.8 System flow diagrams: Format No. FERC 567.

(a) Each Major natural gas pipeline company, having a system delivery capacity in excess of 100,000 Mcf per day (measured at 14.73 p.s.i.a. and 60 °F), shall file with the Commission by June 1 of each year five (5) copies of a diagram or diagrams reflecting operating conditions on its main transmission system during the previous twelve months ended December 31. For purposes of system peak deliveries, the heating season overlapping the year's end shall be used. Facilities shall be those installed and in operation on December 31 of the reporting year. All volumes shall be reported on a uniform stated pressure and temperature base. Receipt and delivery point information required in various exhibits must be labeled with a location point name and code in accordance with the location name and code adopted by the pipeline in accordance with § 284.13(f) of this chapter.

(b) The diagram or diagrams shall include the following items of information:

(1) Nominal diameter (inches) of each pipeline.

(2) Miles of pipeline (to nearest 0.1 mile) between points of intake, delivery, river crossings, storage fields, crossovers, compressor stations and connections with other pipeline companies.

(3) Direction of flow in the pipelines. If direction of flow can be reversed at compressor stations, so indicate.

(4) Maximum permissible operating pressure for each pipeline at discharge side of each compressor station or other critical point, determined by the Department of Transportation's safety standards.

(5) Total horsepower of compressor engines installed at each compressor station.

(6) Designed suction pressure for each compressor station, p.s.i.g.

(7) Designed discharge pressure for each station, p.s.i.g.

(8) Maximum volume, Mcf per day that can be compressed at each compressor station under conditions of suction and discharge set forth in paragraphs (b) (6) and (7) of this section. If direction of flow affects these factors provide the information for each direction of flow.

(9) The fuel requirement at each compressor station under conditions described in paragraph (b)(8) of this section.

(10) Pressure in the pipeline at points of emergency interconnection with other pipeline companies which can normally be expected to exist, and the volume which could be delivered or received at such emergency interconnection points at such pressures. Give the name of the interconnecting company.

(11) For each storage field, connected to the system and operated by the respondent pipeline company, the maximum dependable daily and seasonal withdrawal volumes available under normal conditions of operation.

(12) Volumes delivered: (i) The average daily volumes delivered at each takeoff point, (ii) the volumes delivered at each takeoff point on the day of maximum coincidental delivery, and (iii) the maximum daily volumes (noncoincidental) delivered to each customer under rates subject to FERC jurisdiction.

(13) The average daily volume received at each intake point to the transmission pipeline system.

(14) The volume received into the transmission pipeline system at each intake point on the day of maximum coincidental delivery.

(15) The information required by paragraphs (b)(12), (13) and (14), of this section may be furnished in tabular form, or by reference to FERC Form No. 2, providing, that the information is suitably keyed to the diagram by appropriate identifying symbol or number.

[Order 303-A, 31 FR 7226, May 18, 1966, as amended by Order 345, 32 FR 7332, May 17, 1967; Order 430, 36 FR 7052, Apr. 14, 1971; Order 215, 47 FR 10203, Mar. 10, 1982; Order 390, 49 FR 32527, Aug. 14, 1984; Order 587-W, 80 FR 67312, Nov. 2, 2015]

§ 260.9 Reports by natural gas pipeline companies on service interruptions and damage to facilities.

(a)(1) Every natural gas company must report to the Director, Division of Pipeline Certificates, at the earliest feasible time:

(i) Damage to any jurisdictional natural gas facilities other than liquefied natural gas facilities caused by a hurricane, earthquake or other natural disaster or terrorist activity that results in a loss of or reduction in pipeline throughput or storage deliverability; and

(ii) Serious interruptions of service to any shipper involving jurisdictional natural gas facilities other than liquefied natural gas facilities. Such serious interruptions of service shall include interruptions of service to communities, major government installations and large industrial plants outside of communities or any other interruptions which are significant in the judgment of the pipeline company. Interruptible service interrupted in accordance with the provisions of filed tariffs, interruptions of service resulting from planned maintenance or construction and interruptions of service of less than three hours duration need not be reported.

(2) In the event of damage to a natural gas company's jurisdictional natural gas facilities other than liquefied natural gas facilities by reason other than hurricane, earthquake or other natural disaster or terrorist activity, the natural gas company should report such damage if, in the natural gas company's judgment, such damage creates the potential for serious delivery problems on its own system or the pipeline grid.

(b) Any report of damage to facilities required by paragraph (a)(1)(i) of this section, any report of service interruption required by paragraph (a)(1)(ii) of this section and any report made pursuant to paragraph (a)(2) of this section in a natural gas company's discretion must be submitted by the natural gas company by e-mail to pipelineoutage@ferc.gov or by facsimile transmission to the Director, Division of Pipeline Certificates, Office of Energy Projects at FAX number (202) 208-2853.

(1) Reports required by paragraph (a)(1)(i) or (ii) or made in a natural gas company's discretion pursuant to paragraph (a)(2) shall be made at the earliest feasible time and must state:

(i) The location and cause of the service interruption or damage to natural gas pipeline or storage facilities;

(ii) The nature of any damage to pipeline or storage facilities;

(iii) Specific identification of any facilities damaged;

(iv) The time the service interruption or damage to facilities occurred;

(v) The customers affected by the interruption of service or damage to facilities;

(vi) Emergency actions taken to maintain service; and

(vii) Company contact and telephone number.

(2) Following a report required by paragraph (a)(1)(i) of this section of damage to natural gas facilities resulting in loss of pipeline throughput or storage deliverability or a report pursuant to paragraph (a)(2) of this section in a natural gas company's discretion, the natural gas company shall report to the Director, Division of Pipeline Certificates, at the earliest feasible time when pipeline throughput or storage deliverability has been restored.

(c) If so directed by the Commission or the Director, Division of Pipeline Certificates, the company must provide any supplemental information so as to provide a full report of the circumstances surrounding the occurrence.

(d) In any instance in which an incident or damage report involving jurisdictional natural gas facilities is required by Department of Transportation reporting requirements under the Natural Gas Pipeline Safety Act of 1968, a copy of such report shall be submitted to the Director, Division of Pipeline Certificates, within 30 days of the reportable incident.

(e) When a report of damage to facilities is required by paragraph (a)(1)(i) of this section or a report of service interruption is required by paragraph (a)(1)(ii) of this section, a copy of the e-mail or facsimile report required pursuant to paragraph (b) of this section must be sent to each State commissions for the States in which the reported service interruptions or damage has occurred.

[Order 401, 35 FR 7413, May 13, 1970, as amended by Order 508, 53 FR 45901, Nov. 15, 1988; Order 581, 60 FR 53071, Oct. 11, 1995; Order 621, 65 FR 80307, Dec. 21, 2000; Order 682, 71 FR 51104, Aug. 29, 2006]

§§ 260.11-260.15 [Reserved]

§ 260.200 Original cost statement of utility property.

Any natural gas company becoming subject to the jurisdiction of the Commission shall file, insofar as applicable, the following statements properly sworn to by the officer in responsible charge of their compilation:

Statement A

Statement A showing the origin and development of the company, including, particularly, a description (giving names of parties and dates) of each consolidation and merger to which the company, or a predecessor, was a party and each acquisition of a gas operating unit or system. Any affiliation existing between the parties shall be stated.

Statement B

Statement B showing for each acquisition of a gas operating unit or system by the reporting company or any of its predecessors: (1) The original cost (estimated only if not determinable from existing records), (2) the cost of the acquiring company, (3) the amount entered in the books as of the date of acquisition, (4) the difference between the original cost and the amount entered in the books, (5) a summary of all transactions affecting such difference, including retirements, between the date of each acquisition and the end of the calendar year prior to the year in which the filing is made, and (6) the amount of such difference remaining at the latter date.

If the depreciation, retirement, or amortization reserve was adjusted as of the date of acquisition and in connection therewith, a full disclosure of the pertinent facts shall be made.

The amount to be included in account 114, Gas Plant Acquisition Adjustments, shall be subdivided so as to show the amounts applicable to (a) gas plant in service, (b) gas plant leased to others, and (c) gas plant held for future use.

The procedure followed in determining the original cost of the gas plant acquired as operating units or systems shall be described in sufficient detail so as to permit a clear understanding of the nature of the investigations and analyses which were made for that purpose.

Where estimates are used in arriving at original cost or the amount to be included in account 114, a full disclosure of the method and underlying facts shall be given. The proportion of the original cost of each acquisition which has been determined from actual recorded costs and the proportion estimated shall be shown for each functional class of plant. In addition there shall be furnished in respect to each predecessor or vendor company for which complete construction costs are not available, a description of such plant records as are available, including the years covered thereby.

Statement C

Statement C showing any amounts arrived at by appraisals in the gas plant accounts (and not eliminated) in lieu of cost to the reporting company. This statement should describe the appraisal and give the complete journal entry at the time the appraisal was originally recorded. If the entry had the effect of appreciating or writing up the gas plant account, the amount of the appreciation or writeup should be traced, by proper description and explanation of changes, from the date recorded through the end of the calendar year prior to the year in which the filing is made.

Statement D

Statement D showing in detail gas plant as classified in the books of account immediately prior to reclassification in accordance with the Uniform System of Accounts, including, under appropriate descriptive headings, any unclassified amounts applicable jointly to the gas department and other departments of the utility.

Statement E

Statement E showing the adjustments necessary to state accounts 101, 103-107, 114, and 116, and amount of common utility plant includible in account 118, as prescribed in the Uniform System of Accounts.

Statement F

Statement F showing gas plant classified according to the accounts prescribed in the Uniform System of Accounts, and showing also the amount includible in account 116, Other Gas Plant Adjustments, and the amount of common utility plant includible in account 118, Other Utility Plant.

Statement G

Statement G showing a comparative balance sheet reflecting the accounts and amounts appearing in the books before the adjusting entries have been made and after such entries shall have been made. The balance sheet shall be classified by the accounts set forth in the Uniform System of Accounts Prescribed for Natural Gas Companies.

Statement H

Statement H giving a suggested plan for depreciating, amortizing, or otherwise disposing of, in whole or in part, the amounts includible in account 114, Gas Plant Acquisition Adjustments, and account 116, Other Gas Plant Adjustments.

Statement I

Statement I furnishing the following statistical information relative to gas plant:

Production Plant manufactured gas

Show separately for each producing plant the name and location of plant, date of original construction, type of plant (whether coal gas, coke ovens, water gas, etc.), rated 24-hour capacity in Mcf of each unit and of the total plant, and date of installation of each unit installed after original construction. Show also the original cost according to the System of Accounts for each plant, by accounts 304 to 319, inclusive.

natural gas

For each “field” includible in account 101, Gas Plant in Service, furnish the number of acres each of gas producing lands owned, of gas producing lands leased by the company, and of land on which gas rights only are owned, as included in accounts 325.1, 325.2, 325.3, respectively. The same information, classified by subaccounts, shall be furnished for producing and nonproducing acreage includible in account 104, Gas Plant Leased to Others, and in account 105, Gas Plant Held for Future Use.

For each “field” state number of feet of each size pipe used in field gathering lines.

For each “field” state number of wells included in accounts 330 and 331 segregated to show the number of wells on each type of producing lands classified under accounts 325.1, 325.2, 325.3.

When pumping or compressing plants exist within the production plant, include the same information as that requested for compressor stations under transmission plant.

State type and character of purification equipment and residual refining equipment included in accounts 336 and 337, respectively.

Show the original cost according to the System of Accounts for natural gas production plant by each “field” and by accounts 325.1 to 340.

Storage Plant

Show separately for each location the name of plant, date of construction, type and total capacity (Mcf) of each gas holder. State also the original cost according to the System of Accounts for each location, by accounts 350.1 to 351, inclusive.

If depleted gas fields are being repressured, the statements furnished shall reflect the number of acres involved and the original cost according to the System of Accounts (accounts 350.1 to 351, inclusive).

Transmission Plant

State the number of feet of each size of main.

State separately for each compressor boosting station the name of plant, location, date of original construction, rated capacity, type and character of power unit, and rated capacity and type of compressor units. Also state the capacity, type, and date of installation of each additional power or compressor unit. Show for each station the original cost according to the System of Accounts by accounts 365.1, 365.2, 366, 368, and 369.

Distribution Plant

State number of feet of each size of main and the number of active meters, house regulators, and services. Give a general description of the district regulators and number, by sizes.

Where pumping or compressor stations exist within the distribution plant, include the same information requested for similar stations under transmission plant.

General Plant

Describe the principal structures and improvements.

State the number and type of transportation vehicles and appurtenant equipment.

Give a description of store, shop, and laboratory equipment and miscellaneous equipment.

Furnish maps, drawn to scale, upon which indicate transmission mains, location of production plants (artificial and natural), producing and nonproducing leaseholds (indicating thereon producing wells, dry holes and depleted wells), gathering systems, booster and compressor stations, communities served (noting as to wholesale or retail), and large industrial consumers. Where gas is purchased from or sold to other gas utilities, indicate location of measuring stations or gates. If scale maps are not available, furnish sketch maps upon which should be indicated approximate distances between the locations above specified.

[Order 477, 38 FR 7215, Mar. 19, 1973]

§ 260.300 FERC Form No. 3-Q, Quarterly financial report of electric utilities, licensees, and natural gas companies.

(a) Prescription. The quarterly report for electric utilities, licensees, and natural gas companies, designated herein as FERC Form No. 3-Q, is prescribed for the reporting quarter ending March 31, 2004, and each quarter thereafter.

(b) Filing requirements—(1) Who must file. Each natural gas company, (as defined in the Natural Gas Act (15 U.S.C. 717, et. seq.) must prepare and file with the Commission a FERC Form No. 3-Q pursuant to the General Instructions set out in that form.

(2) Each Major natural gas company must file this quarterly financial report form as follows:

(i) The quarterly financial report for the period January 1 through March 31, 2004, must be filed on or before July 9, 2004.

(ii) The quarterly financial report for the period April 1 through June 30, 2004, must be filed on or before September 8, 2004.

(iii) The quarterly financial report for the period July 1 through September 30, 2004, must be filed on or before December 9, 2004.

(iv) The quarterly financial report for the period January 1 through March 31, 2005, must be filed on or before May 31, 2005.

(v) The quarterly financial report for the period April 1 through June 30, 2005, must be filed on or before August 29, 2005.

(vi) The quarterly financial report for the period July 1 through September 30, 2005 must be filed on or before November 29, 2005.

(vii) Subsequent quarterly financial reports must be filed within 60 days from the end of the reporting quarter.

(3) Each Nonmajor natural gas company must file a quarterly financial report as follows:

(i) The quarterly financial report for the period January 1 through March 31, 2004, must be filed on or before July 23, 2004.

(ii) The quarterly financial report for the period April 1 through June 30, 2004, must be filed on or before September 22, 2004.

(iii) The quarterly financial report for the period July 1 through September 30, 2004, must be filed on or before December 23, 2004.

(iv) The quarterly financial report for the period January 1 through March 31, 2005, must be filed on or before June 13, 2005.

(v) The quarterly financial report for the period April 1 through June 30, 2005, must be filed on or before September 12, 2005.

(vi) The quarterly financial report for the period July 1 through September 30, 2005 must be filed on or before December 13, 2005.

(vii) Subsequent quarterly financial reports must be filed within 70 days from the end of the reporting quarter.

(4) This report must be filed as prescribed in § 385.2011 of this chapter as indicated in the General Instructions set out in the quarterly financial report form, and must be properly completed and verified. Filing on electronic media pursuant to § 385.2011 of this chapter will be required commencing with the quarterly financial report ending March 31, 2004, due on or before July 9, 2004 for major natural gas companies, and due on or before July 23, 2004 for nonmajor natural gas companies. One copy of the report must be retained by the respondent in its files.

[69 FR 9044, Feb. 26, 2004, as amended by Order 646-A, 69 FR 32443, June 10, 2004]

§ 260.400 Cash management programs.

Natural gas companies subject to the provisions of the Commission's Uniform System of Accounts prescribed in part 201 and § 260.1 or § 260.2 of this title that participate in cash management programs must file these agreements with the Commission. The documentation establishing the cash management program and entry into the program must be filed within 10 days of the effective date of the rule or entry into the program. Subsequent changes to the cash management agreement must be filed with the Commission within 10 days of the change.

[Order 634-A, 68 FR 62003, Oct. 31, 2003, as amended at 69 FR 9044, Feb. 26, 2004]

§ 260.401 FERC Form No. 552, Annual Report of Natural Gas Transactions.

(a) Prescription. The annual report for natural gas market participants, designated as FERC Form No. 552, is prescribed for the calendar year ending December 31, 2008 and each calendar year thereafter.

(b) Filing requirements—(1) Who must file. Unless otherwise exempted or granted a waiver by Commission rule or order, each natural gas market participant, i.e., any buyer or seller that engaged in physical natural gas transactions the previous calendar year, must prepare and file with the Commission a FERC Form No. 552 pursuant to the definitions and general instructions set forth in that form. However a de minimis exemption, a natural gas market participant is exempt from this filing requirement if:

(i) It engages in reportable physical natural gas sales that amount to less than 2,200,000 MMBtus for the previous calendar year; and

(ii) It engages in reportable physical natural gas purchases that amount to less than 2,200,000 MMBtus for the previous calendar year.

(2) Form No. 552 must be filed as prescribed in § 385.2011 of this chapter as indicated in the General Instructions set out in the annual reporting form, and must be properly completed and verified. Each market participant must file Form No. 552 by May 1, 2009 for calendar year 2008 and by May 1 of each year thereafter for the previous calendar year. Each report must be prepared in conformance with the Commission's software and guidance posted and available for downloading from the FERC Web site (http://www.ferc.gov). One copy of the report must be retained by the respondent in its files.

[73 FR 1031, Jan. 4, 2008, as amended at 73 FR 55739, Sept. 26, 2008; Order 704-C, 75 FR 35643, June 23, 2010]

§ 270.101 General definitions.

(a) NGPA definitions. Terms defined in the Natural Gas Policy Act of 1978 (NGPA) will have the same meaning for purposes of this subchapter as they have under the NGPA, unless further defined in this subchapter.

(b) Subchapter H definitions. For purposes of this part:

(1) NGPA means the Natural Gas Policy Act of 1978.

(2) Surface location means the point on the Earth's surface from which drilling of a well is commenced except that in the case of a well drilled in permanent surface waters, “the Earth's surface” means the mean elevation of the surface of the water.

(3) Jurisdictional agency means the state or federal agency identified in § 270.401.

(4) Tight formation gas means natural gas that a jurisdictional agency has determined to be produced from a designated tight formation.

(5) Designated tight formation means the portion of a natural gas bearing formation that was:

(i) Designated as a tight formation by the Commission, pursuant to section 501 of the NGPA, or

(ii) Determined to be a tight formation pursuant to section 503 of the NGPA.

(6) Occluded natural gas produced from coal seams means naturally occurring natural gas released from entrapment from the fractures, pores and bedding planes of coal seams.

(7) Natural gas produced from Devonian shale means natural gas produced from fractures, micropores and bedding planes of shales deposited during the Paleozoic Devonian Period.

(8) Shales deposited during the Paleozoic Devonian Period can be defined as either:

(i) The gross Devonian age stratigraphic interval encountered by a well bore, at least 95 percent of which has a gamma ray index of 0.7 or greater; or

(ii) One continuous interval within the gross Devonian age stratigraphic interval, encountered by a well bore, as long as at least 95 percent of the selected Devonian shale interval has a gamma ray index of 0.7 or greater (but if the interval selected is more than 200 feet thick, the bottom and top 100 foot portions must meet the five percent test independently).

(9) Gamma ray index means when measuring the Devonian age stratigraphic interval, the gamma ray index at any point is to be calculated by dividing the gamma ray log value at that point by the gamma log value at the shale base line established over the entire Devonian age interval penetrated by the well bore.

(10) Mcf means one thousand cubic feet of natural gas at 60 degrees Fahrenheit under a pressure equivalent to that of 30.00 inches of mercury at 32 degrees Fahrenheit, under standard gravitational force (980.665 centimeters per second squared).

(11) Data well means a well for which permeability and/or pre-stimulation production rate data are available for a pay section in the formation for which a tight formation designation is being sought.

§ 270.201 Applicability.

(a) This part applies to determinations of jurisdictional agencies for tight formation gas, occluded natural gas produced from coal seams, and natural gas produced from Devonian shale that is produced through:

(1) A well the surface drilling of which began after December 31, 1979, but before January 1, 1993;

(2) A recompletion commenced after January 1, 1993, in a well the surface drilling of which began after December 31, 1979, but before January 1, 1993; or

(3) A recompletion commenced after December 31, 1979, but before January 1, 1993, where such gas could not have been produced from any completion location in existence in the well bore before January 1, 1980.

(b) This part also applies to determinations of jurisdictional agencies that designate a formation, or portion thereof, as a tight formation.

§ 270.202 Definition of determination.

For purposes of this subpart, a determination has been made by a jurisdictional agency when such determination is administratively final before such agency.

§ 270.203 Determinations by jurisdictional agencies.

A jurisdictional agency must make determinations to which this part applies in accordance with procedures applicable to it under the law of its jurisdiction for making such determinations or for making comparable determinations.

§ 270.204 Notice to the Commission.

Within 15 days after making a determination under this part, the jurisdictional agency must give written notice of the determination to the Commission. The notice must include the following:

(a) A list of all participants in the proceeding as well as any persons who submitted or who sought an opportunity to submit written comments (whether or not such persons participated in the proceeding);

(b) A statement indicating whether the matter was opposed before the jurisdictional agency;

(c) A copy of the application together with a copy or description of all other materials upon which the jurisdictional agency relied in the course of making the determination, together with any information which may be inconsistent with the determination.

(d) An explanatory statement, including appropriate factual findings and references, which is sufficient to enable a person examining the notice to ascertain the basis for the determination without reference to information or data not contained in the notice.

§ 270.301 General requirements.

(a) An application for determination may be filed with the jurisdictional agency and signed by any person the jurisdictional agency designates as eligible to make filings with respect to the well for which the application is made.

(b) The documents required by this subpart are the minimum required in support of a request for a determination. The jurisdictional agency may require additional support as it deems appropriate, and may more specifically identify the documents indicated as the minimum required.

(c) Each applicant must pay the fee prescribed in § 381.401 of this chapter. The applicant will be billed annually by the Commission for each jurisdictional agency determination received by the Commission. The applicant must submit the fee, or petition for waiver pursuant to § 381.106 of this chapter, within 30 days following the billing date.

§ 270.302 Occluded natural gas produced from coal seams.

A person seeking a determination that natural gas is occluded natural gas produced from coal seams must file an application with the jurisdictional agency which contains the following items:

(a) FERC Form No. 121;

(b) All well completion reports.

(c) A radioactivity, electric or other log which will define the coal seams.

(d) Evidence to establish that the natural gas was produced from a coal seam;

(e) A statement by the applicant, under oath, that gas is produced from a coal seam through:

(1)(i) A well the surface drilling of which began after December 31, 1979, but before January 1, 1993;

(ii) A recompletion commenced after January 1, 1993, in a well the surface drilling of which began after December 31, 1979, but before January 1, 1993; or

(iii) A recompletion that was commenced after December 31, 1979 but before January 1, 1993, where such gas could not have been produced from any completion location in existence in the well bore before January 1, 1980; and

(2) The applicant has no knowledge of any information not described in the application which is inconsistent with his conclusion.

§ 270.303 Natural gas produced from Devonian shale.

A person seeking a determination that natural gas is produced from Devonian shale shall file an application with the jurisdictional agency which contains the following items:

(a) FERC Form No. 121;

(b) All well completion reports;

(c) A gamma ray log with superimposed indications of the shale base line and the gamma ray index of 0.7 over the Devonian age stratigraphic section designated pursuant to § 270.101(b)(8);

(d) A reference to a standard stratigraphic chart or text establishing that the producing interval is a shale of Devonian age; and

(e) A sworn statement:

(1) Calculating the percentage of footage of the producing interval which is not Devonian shale as indicated by a Gamma ray index of less than 0.7;

(2) Demonstrating that the percentage of potentially disqualifying non-shale footage for the stratigraphic section selected is equal to or less than 5 percent of the Devonian stratigraphic age interval designated pursuant to § 270.101(b)(7);

(3) Attesting that the natural gas is being produced from Devonian shale through:

(i) A well the surface drilling of which began after December 31, 1979, but before January 1, 1993;

(ii) A recompletion commenced after January 1, 1993, in a well the surface drilling of which began after December 31, 1979, but before January 1, 1993; or

(iii) A recompletion that was commenced after December 31, 1979 but before January 1, 1993, where such gas could not have been produced from any completion location in existence in the well bore before January 1, 1980; and

(4) Attesting that the applicant has no knowledge of any information not described in the application which is inconsistent with his conclusion.

§ 270.304 Tight formation gas.

A person seeking a determination that natural gas is tight formation gas must file with the jurisdictional agency an application which contains the following items:

(a) FERC Form No. 121;

(b) All well completion reports;

(c) A map that identifies the surface location of the well and the completion location in the well in the designated tight formation, along with the geographic boundaries of the designated tight formation, or a location plat identifying the surface location of the well and the completion location in the designated tight formation, along with a list of the tract (or tracts) of land that comprise the designated tight formation;

(d) A complete copy of the well log, including the log heading identifying the designated tight formation stratigraphically; and

(e) A statement by the applicant, under oath, that:

(1) The natural gas is being produced from a designated tight formation through:

(i) A well the surface drilling of which began after December 31, 1979, but before January 1, 1993;

(ii) A recompletion commenced after January 1, 1993, in a well the surface drilling of which began after December 31, 1979, but before January 1, 1993; or

(iii) Through a recompletion that was commenced after December 31, 1979 but before January 1, 1993, where such gas could not have been produced from any completion location in existence in the well bore before January 1, 1980; and

(2) The applicant has no knowledge of any information not described in the application which is inconsistent with his conclusion.

§ 270.305 Determination of tight formation areas.

(a) General requirement. A jurisdictional agency determination designating a portion of a formation as a tight formation must be made in the form and manner prescribed in this subpart.

(b) Guidelines for designating tight formations. A jurisdictional agency determination designating a portion of a formation as a tight formation must be made in accordance with the following guidelines:

(1) Within the geographic boundaries of the portion of the formation being recommended for tight formation designation, the estimated in situ gas permeability, throughout the pay section, is expected to be 0.1 millidarcy (md) or less. The expected in situ permeability is to be determined through an arithmetic mean averaging of the known permeabilities obtained from the wells that penetrate, and have a pay section in, such portion of such formation.

(2) Within the geographic boundaries of the portion of the formation being recommended for tight formation designation, the stabilized production rate of natural gas, against atmospheric pressure, of wells completed for production in such portion of such formation, without stimulation, is not expected to exceed the production rate determined in accordance with the table in this paragraph (b)(2). Such expected stabilized, pre-stimulation production rate is to be determined through an arithmetic mean averaging of the known stabilized, pre-stimulation production rates obtained from the wells that penetrate, and have a pay section in, such portion of such formation.

If the average depth to the top of the formation (in feet) | The maximum allowable production rate of natural gas (in Mcf per day)

exceeds— | but does not exceed— | may not exceed—

0 | 1,000 | 44

1,000 | 1,500 | 51

1,500 | 2,000 | 59

2,000 | 2,500 | 68

2,500 | 3,000 | 79

3,000 | 3,500 | 91

3,500 | 4,000 | 105

4,000 | 4,500 | 122

4,500 | 5,000 | 141

5,000 | 5,500 | 163

5,500 | 6,000 | 188

6,000 | 6,500 | 217

6,500 | 7,000 | 251

7,000 | 7,500 | 290

7,500 | 8,000 | 336

8,000 | 8,500 | 388

8,500 | 9,000 | 449

9,000 | 9,500 | 519

9,500 | 10,000 | 600

10,000 | 10,500 | 693

10,500 | 11,000 | 802

11,000 | 11,500 | 927

11,500 | 12,000 | 1,071

12,000 | 12,500 | 1,238

12,500 | 13,000 | 1,432

13,000 | 13,500 | 1,655

13,500 | 14,000 | 1,913

14,000 | 14,500 | 2,212

14,500 | 15,000 | 2,557

(c) Notice to the Commission. Any jurisdictional agency making a determination that a formation, or portion thereof, qualifies as a tight formation will provide timely notice, in writing, of such determination, to the Commission. Such notice shall include the following to substantiate the jurisdictional agency's findings:

(1) Geological and geographical descriptions of the formation, or portion thereof, which is determined to qualify as a tight formation; and

(2) Geological and engineering data to support the determination, including (but not limited to):

(i) A map of the area for which a tight formation determination is being sought that clearly locates and identifies all data wells and all dry holes that penetrate the subject formation and all wells that are currently producing from the subject formation.

(ii) A well-by-well table of each in situ permeability value (in millidarcies), pre-stimulation stabilized production rate (in Mcf per day), and depth to the top of the formation (in feet) for each well, and the arithmetic mean of each set of data.

(iii) For any data that the jurisdictional agency excludes from the above calculations, a statement explaining why the data was excluded.

(iv) The underlying well test, well logs, cross-sections, or other data sources, and all calculations performed to derive the formation tops, permeability values, and pre-stimulation stabilized production rates shown in the well-by-well table.

(v) Any other information that the jurisdictional agency deems relevant and/or that the jurisdictional agency relied upon in making its determination.

§ 270.306 Devonian shale wells in Michigan.

A person seeking a determination that natural gas is being produced from the Devonian Age Antrim shale in Michigan shall file an application that contains the following items:

(a) FERC Form No. 121;

(b) All well completion reports;

(c) A gamma ray log from the closest available well bore (producing or dry hole) that is within a one mile radius of the well for which a determination is sought, with superimposed indications of:

(1) The shale base line and the gamma ray index of 0.7 over the Devonian age stratigraphic section penetrated by the well bore; and

(2) The boundary between the Antrim shale and the overlying formation (Berea Sandstone, Ellsworth, Bedford, or Sunbury shales, or their equivalents);

(d) A location plat showing the well for which the determination is sought and the well for which a gamma ray log has been filed;

(e) A mud log from the well for which the determination is sought, with a detailed description of samples taken from 10-foot, or less, intervals through-out the Devonian age stratigraphic section penetrated by the well bore;

(f) A driller's log, or similar report, from the well for which the determination is sought, indicating the general characteristics of the strata penetrated and the corresponding depths at which they are encountered throughout the Devonian age stratigraphic section penetrated by the well bore;

(g) A reference to a standard stratigraphic chart or text establishing that the producing interval is a shale of Devonian age; and

(h) A sworn statement:

(1) Calculating the percentage of footage of the producing interval (or the Antrim Shale in the event the well is a dry hole) in the well for which a gamma ray log was submitted which is not Devonian shall as indicated by a gamma ray index of less than 0.7;

(2) Demonstrating that the percentage of potentially disqualifying non-shale footage for the Devonian age stratigraphic section penetrated by the well bore for which the submitted gamma ray log is equal to or less than 5 percent;

(3) Attesting that the natural gas is being produced from the Devonian Age Antrim shale through:

(i) A well the surface drilling of which began after December 31, 1979, but before January 1, 1993;

(ii) A recompletion commenced after January 1, 1993, in a well the surface drilling of which began after December 31, 1979, but before January 1, 1993; or

(iii) A recompletion that was commenced after December 31, 1979 but before January 1, 1993, where such gas could not have been produced from any completion location in existence in the well bore before January 1, 1980 and

(4) Attesting the applicant has no knowledge of any information not described in the application which is inconsistent with his conclusion.

§ 270.401 Jurisdictional agency.

(a) Definition. With respect to a well the surface location of which is on lands within the boundaries of a State (including Federal lands and offshore State lands), “jurisdictional agency” means the Federal or State agency having regulatory jurisdiction with respect to the production of natural gas.

(b) The jurisdictional agency for wells located on Federal lands in each state are:

(1) Alabama—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.

(2)(i) Alaska, Anchorage Field Office—Assistant District Manager for Mineral Resources, Bureau of Land Management, 6881 Abbott Loop Road, Anchorage, AK 99507.

(ii) Alaska, Northern Field Office—Assistant District Manager for Mineral Resources, Bureau of Land Management, 1150 University Avenue, Fairbanks, AK 99709.

(3)(i) Arizona, except for the Navaho and Hopi Indian Reservations—Deputy State Director for Mineral Resources, Bureau of Land Management, PO Box 555, Phoenix, AZ 85000-0555.

(ii) Arizona, Navaho and Hopi Indian Reservations—District Manager, Bureau of Land Management, Albuquerque District Office (NGPA), 435 Montano Road, NE., Albuquerque, NM 87107.

(4) Arkansas—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.

(5) California, except Naval Petroleum Reserve No. 1 (Elk Hills) and No. 2 (Buena Vista)—Chief, Branch of Fluid and Solid Minerals, Bureau of Land Management, Division of Mineral Resources (C-920), 2800 Cottage Way, Suite W-1834, Sacramento, CA 95825.

(6) Colorado—Deputy State Director for Resource Services, Bureau of Land Management, Colorado State Office (CO-930), 2850 Youngfield Street, Lakewood, CO 80215.

(7) Florida and Georgia—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.

(8) Idaho—Deputy State Director Resources and Science, Bureau of Land Management, Idaho State Office (931), 1387 Vinnell Way, Boise, ID 83709.

(9) Illinois, Indiana, and Iowa—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.

(10) Kansas—Deputy State Director for Resource Services, Bureau of Land Management, Colorado State Office (CO-931), 2850 Youngfield Street, Lakewood, CO 80215.

(11) Kentucky, Louisiana, Maryland, Michigan, Mississippi, and Missouri—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.

(12) Montana—Chief, Branch of Fluid and Solid Minerals, Bureau of Land Management, Division of Mineral Resources, PO Box 36800, Billings, MT 59107.

(13) Nebraska—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.

(14) Nevada—State Director, Bureau of Land Management, Nevada State Office (NV-92000), PO Box 12000, Reno, NV 89520.

(15)(i) New Mexico, Northern New Mexico—Field Office Manager, Bureau of Land Management, Albuquerque Field Office (NGPA), 435 Montano Road, NE., Albuquerque, NM 87107.

(ii) New Mexico, Southern New Mexico—Field Office Manager, Bureau of Land Management, Roswell Field Office (NGPA), 2909 West Second Street, Roswell, NM 88201.

(16) New York and North Carolina—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.

(17) North Dakota—Chief, Branch of Fluid Minerals, Bureau of Land Management, Division of Mineral Resources, PO Box 36800, Billings, MT 59107.

(18) Ohio—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.

(19)(i) Oklahoma, except the Osage Reservation—Field Office Manager, Bureau of Land Management, Tulsa Field Office (NGPA), 7906 East 33rd Street, Suite 101, Tulsa, OK 74145.

(ii) Oklahoma, the Osage Reservation only—Superintendent, Osage Indian Agency, Bureau of Indian Affairs, U. S. Department of the Interior, Pawhuska, OK 74056.

(20) Oregon—Deputy State Director, Planning, Use, and Protection, Bureau of Land Management, Oregon State Office, PO Box 2965, Portland, OR 97208.

(21) Pennsylvania and South Carolina—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.

(22) South Dakota—Chief, Branch of Fluid Minerals, Bureau of Land Management, Division of Mineral Resources, PO Box 36800 Billings, MT 59107.

(23) Tennessee—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.

(24) (i) Texas, east of the 100th Meridian—Field Office Manager, Bureau of Land Management, Tulsa Field Office (NGPA), 7906 East 33rd Street, Suite 101, Tulsa, OK 74145.

(ii) Texas, west of the 100th Meridian—Field Office Manager, Bureau of Land Management, Roswell Field Office (NGPA), 2909 West Second Street, Roswell, NM 88201.

(25) (i) Utah, except for the Navajo and Hopi Indian Reservations—Deputy State Director for Natural Resources, Bureau of Land Management, Utah State Office (U-930), 324 South State Street, Suite 301, Salt Lake City, UT 84111.

(ii) Utah, the Navajo and Hopi Indian Reservations only—Field Office Manager, Bureau of Land Management, Albuquerque Field Office (NGPA), 435 Montano Road, NE., Albuquerque, NM 87107.

(26) Virginia—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.

(27) Washington—Deputy State Director for Mineral Resources, Bureau of Land Management, Oregon State Office, PO Box 2965, Portland, OR 97208.

(28) West Virginia—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.

(29) (i) Wyoming, excluding Naval Petroleum Reserve No. 3 (Teapot Dome) Casper Field Office—Field Office Manager, Bureau of Land Management, 1701 East E Street, Casper, WY 82601.

(ii) Rawlins Field Office—Field Office Manager, Bureau of Land Management, PO Box 2407, Rawlins, WY 82301.

(iii) Rock Springs Field Office—Field Office Manager, Bureau of Land Management, 280 Highway 191 North, Rock Springs, WY 82901.

(iv) Worland Field Office—Field Office Manager, Bureau of Land Management, PO Box 119, Worland, WY 82401.

(c) The jurisdictional agency for wells located on Other lands in each state are:

(1) Alabama—State Oil and Gas Board, 420 Hackberry Lane, P O Box 869999, Tuscaloosa, AL 35486-9780.

(2) Alaska—Department of Natural Resources, Oil & Gas Division, 550 West 7th Avenue, Anchorage, AK 99501.

(3) Arizona—Oil and Gas Conservation Commission, 416 West Congress Street, Suite 100, Tucson, AZ 85701

(4) Arkansas—Oil & Gas Commission, PO Box 1472, El Dorado, AR 71730-1472.

(5) California—Department of Conservation, Division of Oil & Gas, 801 K Street, MS24-01, Sacramento, CA 95814.

(6) Colorado—Oil & Gas Conservation Commission, 1120 Lincoln, Suite 801, Denver, CO 80203.

(7) Florida—Administrator Oil and Gas, Bureau of Geology, Department of Natural Resources, 903 West Tennessee Street, Tallahassee, FL 32304.

(8) Georgia—Department of Natural Resources, Geologic & Water Resources Division, 19 Martin Luther King Drive, SW, Atlanta, GA 30334.

(9) Idaho—Idaho Public Utilities Commission, Statehouse Mail, Boise, ID 83720.

(10) Illinois—Department of Natural Resources, Oil & Gas Division, 524 South 2nd Street, Springfield, IL 62701.

(11) Indiana—Department of Natural Resources, Oil & Gas Division, 402 West Washington Street, Room 256 Indianapolis, IN 46204.

(12) Kansas—Kansas Corporation Commission, Finney State Office Building, 130 South Market, Room 2078, Wichita, KS 67202-3802.

(13) Kentucky—Public Service Commission, 211 Sower Blvd., PO Box 6615, Frankfort, KY 40602-0615.

(14) Louisiana—Department of Natural Resources, Office of Conservation, PO Box 94275, Baton Rouge, LA 70804.

(15) Maryland—Department of Natural Resources, Tawes State Office Building., Annapolis, MD 21404.

(16) Michigan—Department of Environmental Quality, Geological Survey Division, Hollister Building, PO Box 30473, Lansing MI 48909.

(17) Mississippi—State Oil & Gas Board, 500 Graymont Avenue, Suite E, Jackson, MS 39202.

(18) Missouri—Department of Natural Resources Geology and Survey Division, PO Box 250, 111 Fairgrounds Road, Rolla, MO 65402.

(19) Montana—Department of Natural Resources and Oil and Gas Conservation Division, 2535 St. John's Avenue, Billings, MT 59102.

(20) Nebraska—Oil & Gas Conservation Commission, Box 399, Sidney, NE 69162.

(21) Nevada—Department of Conservation and Natural Resources, Division of Mineral Resources, Capitol Complex, 201 S. Fall Street, Carson City, NV 89710.

(22) New Mexico—Department of Energy and Minerals and Natural Resources, Oil Conservation Division, 2040 S. Pacheco Street, Sante Fe, NM 87505.

(23) New York—New York State Department of Environmental Conservation, Division of Mineral Resources, Bureau of Oil and Gas Regulation, 50 Wolf Road, Albany, NY 12233-6500.

(24) North Carolina—Department of Natural Resources and Community Development, 512 North Salisbury Street, Raleigh, NC 27611.

(25) North Dakota—Industrial Commission, State Capitol, 600 East Boulevard Avenue, Department 405, Bismarck, ND 58505.

(26) Ohio—Department of Natural Resources, Division of Oil and Gas 4383 Fountain Square Drive, Columbus, OH 43224-1362.

(27) Oklahoma—-Corporation Commission, 300 Jim Thorpe Building, PO Box 52000-2000, Oklahoma City, OK 73152-2000.

(28) Oregon—Department of Geology & Mineral Industries, 800 N.E. Oregon Street, #28 Portland, OR 972332.

(29) Pennsylvania “ Department of Conservation and Natural Resources, PO Box 8767, Harrisburg, PA 17105-8767.

(30) South Carolina—South Carolina Public Service Commission, PO Drawer 11649, Columbia, SC 29211.

(31) South Dakota—Oil and Gas Supervisor, Department of Environment and Natural Resources, 2050 West Main, Suite 1, Rapid City, SD 57702.

(32) Tennessee—Office of Conservation, Division of Geology, 401 Church Street, Nashville, TN 37243.

(33) Texas—Railroad Commission Oil and Gas Division, 1701 North Congress Avenue, PO Box 12967, Austin, TX 78711-2967.

(34) Utah—-Department of Natural Resources, Division of Oil, Gas and Mining, PO Box 145801 West North Temple, Suite 1210, Salt Lake City, UT 84114-5801.

(35) Virginia—Department of Mines, Minerals & Energy, Division of Gas and Oil, PO Box 1416, Abingdon, VA 24210.

(36) Washington—Department of Natural Resources, Geology and Earth Resources Division, PO Box 47001, Olympia, WA 98504.

(37) West Virginia—-Division of Environmental Protection, Office of Oil and Gas, #10 McJunkin Road, Nitro, WV 25143-2506.

(d) Federal lands. For purposes of this section, Federal lands means:

(1) All lands leased under:

(i) The Mineral Lands Leasing Act, as amended, 30 U.S.C. 181 et seq.; and

(ii) The Mineral Leasing Act for Acquired Lands, as amended, 30 U.S.C. 351 et seq.; and

(2) All Indian lands which are under the supervision of the United States Geological Survey or any successor federal agency (30 CFR part 221); and

(3) All Indian lands which are under the supervision of the Osage Indian Agency, Bureau of Indian Affairs, U.S. Department of the Interior.

(e) Divided-interest leases. Unless an agreement under this paragraph provides otherwise, where a well is located on a divided-interest lease involving Federal (or Indian) and private (or State) ownership:

(1) The Federal jurisdictional agency will make the determination where the majority lease interest is Federal (or Indian);

(2) The State jurisdictional agency will make the determination where the majority lease interest is private (or State); and

(3) The State jurisdictional agency will make the determination where the lease is divided equally.

(f) Drilling units. Unless an agreement under paragraph (e) of this section provides otherwise, where a drilling unit is drained by two or more wells, the Federal jurisdictional agency will make the determination if the completion location of the well in question is located on a Federal (or Indian) lease, and the State jurisdictional agency will make the determination if the completion location of the well in question is located on a private (or State) lease.

(g) Agreements. If a jurisdictional agency that has jurisdiction over Federal lands enters into an agreement with a jurisdictional agency that has jurisdiction over State lands that either authorizes the State jurisdictional agency to make determinations for wells located on Federal lands or the Federal agency to make determinations for wells located on State lands, such agreement shall be filed with the Commission. Upon the filing of such an agreement, the agency so authorized will be considered to be the jurisdictional agency for wells on the lands subject to the agreement.

§ 270.501 Publication of notice from jurisdictional agency.

(a) Upon receipt of a notice of determination by a jurisdictional agency under § 270.204, the Commission will send an acknowledgment to the applicant and make the notice available through the Commission's website, https://www.ferc.gov.

(b) The acknowledgment will contain the following:

(1) The date on which the jurisdictional agency notice was received;

(2) Certain information contained in FERC Form No. 121;

(3) A statement that the application and a copy or description of other materials in the record on which such determination was made is available for inspection, except to the extent the material is treated as confidential under § 270.506, at the offices of the Commission; and

(4) A statement that persons objecting to the final determination may, in accordance with this subpart, file a protest with the Commission within 20 days after the date that notice of receipt of a determination is issued by the Commission pursuant to this section.

[Order 616, 65 FR 45865, July 26, 2000, as amended by Order 899, 88 FR 74031, Oct. 30, 2023]

§ 270.502 Commission review of final determinations.

(a) Review by Commission. Except as provided in paragraphs (b), (c) and (d) of this section, a determination submitted to the Commission by a jurisdictional agency will become final 45 days after the date on which the Commission received notice of the determination, unless within the 45 day period, the Commission:

(1) Makes a preliminary finding that:

(i) The determination is not supported by substantial evidence in the record on which the determination was made; or

(ii) The determination is not consistent with information which is contained in the public records of the Commission and which was not part of the record on which the jurisdictional agency made the determination, and

(2) Issues written notice of such preliminary finding, including the reasons therefor. Copies of the written notice will be sent to the jurisdictional agency that made the determination, to the persons identified in the notice under § 270.204 of such determination, and to any persons who have filed a protest.

(b) Incomplete notice. Notwithstanding the provisions of paragraph (a) of this section, the 45-day period for Commission review of a determination will not begin if:

(1) The notice forwarded to the Commission pursuant to § 270.204 does not contain all the material specified therein; and

(2) The Commission notifies the jurisdictional agency, within 45 days after the date on which the Commission receives notice of the determination, that the notice is incomplete.

(c) Withdrawal of notice. (1) The jurisdictional agency may withdraw a notice of determination by giving notice as specified in paragraph (c)(2) of this section at any time prior to the issuance of a final order with respect to such determination under paragraphs (g)(1) and (g)(2) of this section, or at any time prior to the date such determination becomes final under paragraph (a) or (g)(4) of this section. Such notice must include the jurisdictional agency's reasons for the withdrawal.

(2) Withdrawal of a notice of determination will take effect at such time as the jurisdictional agency has notified the Commission, and the parties to the proceeding before the agency, of such withdrawal.

(3) Withdrawal of a notice of determination shall nullify such notice of determination.

(d) Withdrawal of application. (1) An applicant may withdraw an application for a determination which is before the Commission by giving notice as specified in paragraph (d)(2) of this section at any time prior to the issuance of a final order with respect to such determination under paragraphs (g)(1) and (g)(2) of this section, or at any time prior to the date such determination becomes final under paragraph (a) or (g)(4) of this section.

(2) Withdrawal of an application will take effect at such time as the applicant has notified the Commission and the jurisdictional agency.

(3) Withdrawal of an application will nullify such application and the notice of determination on such application.

(e) Public notice. The Commission will publish notice of the preliminary finding in the Federal Register and will post the notice on the Commission's website, https://www.ferc.gov. The notice will set forth the reasons for the preliminary finding.

(f) Procedures following notice of preliminary finding. Any state or federal agency or any person may submit, within 30 days after issuance of the preliminary finding, written comments, and request an informal conference with the Commission staff. Any jurisdictional agency, any state agency and any person receiving notice under paragraph (a)(2) of this section may request an informal conference with the Commission staff. All timely requests for conferences will be granted. Notice of, and permission to attend, such conferences will be given to persons identified in paragraph (a)(2) of this section and to state or federal agencies or persons who submitted comments under this paragraph.

(g) Final orders. (1) In any case in which a protest was filed with the Commission and a preliminary finding was issued, the Commission will issue a final order within 120 days after issuance of the preliminary finding.

(2) In any case in which no protest was filed with the Commission and a preliminary finding was issued, the Commission may issue a final order within 120 days after issuance of the preliminary finding.

(3) A final order issued under paragraph (g)(1) or (g)(2) of this section will either affirm, reverse, or remand the determination of the jurisdictional agency. Such order will state the specific basis for the Commission's action. Notice of the issuance of such order will be given to the jurisdictional agency, to participants in the proceeding before the jurisdictional agency, and to participants in the proceeding before the Commission under paragraph (d) of this section and under § 270.503.

(4) In the event that the Commission fails to issue a final order within 120 days after issuance of the preliminary finding, the determination of the jurisdictional agency shall become final.

[Order 616, 65 FR 45865, July 26, 2000, as amended by Order 899, 88 FR 74031, Oct. 30, 2023]

§ 270.503 Protests to the Commission.

(a) Who may file. Any person may file a protest with the Commission with respect to a determination of a jurisdictional agency within 20 days after the date that notice of receipt of a determination is issued by the Commission pursuant to § 270.204.

(b) Grounds. Protests may be based only on the grounds the final determination is:

(1) Not supported by substantial evidence;

(2) Not consistent with information which is contained in the public records of the Commission and which was not part of the record on which the determination was made;

(3) Not consistent with information submitted with the protests for inclusion in the public records of the Commission, which information was not part of the record on which the determination was made; or

(4) Not based on an application which complied with the filing requirements set forth in this part.

§ 270.504 Contents of protests to the Commission.

Each protest must include:

(a) An identification of the determination protested;

(b) The name and address of the person filing the protest;

(c) A statement of whether or not the person filing the protest participated in the proceeding before the jurisdictional agency, and if not, the reason for the nonparticipation;

(d) A statement of the effect the determination will have on the protestor;

(e) A statement of the precise grounds under § 270.503(f) for the protest, and all supporting documents or references to any information relied on which is in the record on which the determination is based or is in or to be inserted in the public files of the Commission; and

(f) A statement that the protestor has served, in accordance with § 385.2010 of this chapter, a copy of the protest together with all supporting documents on the jurisdictional agency and all persons listed in the notice of determination filed pursuant to § 270.204.

§ 270.505 Procedure for reopening determinations.

(a) Grounds. At any time subsequent to the time a determination becomes final pursuant to this subpart, the Commission, on its own motion, or in response to a petition filed by any person aggrieved or adversely affected by the determination, may reopen the determination if it appears that:

(1) In making the determination, the Commission or the jurisdictional agency relied on any untrue statement of material fact; or

(2) There was omitted a statement of material fact necessary in order to make the statements made not misleading, in light of the circumstances under which they were made to the jurisdictional agency or the Commission.

(b) Contents of petition. A petition to reopen the determination proceedings must contain the following information, under oath:

(1) The name and address of the person filing the petition;

(2) The interest of the petitioner in the outcome of the determination proceeding;

(3) The statement of material fact that is alleged to be untrue or omitted;

(4) A statement explaining why the outcome of the determination proceeding would have been different had the statement or omission not occurred; and

(5) Copies of all documents relied on by the petitioner, or references to such documents if they are contained in the public files of the Commission.

(c) Procedures after reopening. In the event the Commission reopens a determination pursuant to this section it will:

(1) Give notice to the jurisdictional agency and all persons who participated before both that agency and the Commission in the proceedings resulting in the determination in question;

(2) Permit the jurisdictional agency and other persons receiving notice pursuant to paragraph (c)(1) of this section to submit whatever documentary evidence such agency or persons deem relevant; and

(3) Take such other action or hold or cause to be held such proceedings as it deems necessary or appropriate for a full disclosure of the facts.

(d) Final order of Commission. Within 150 days after issuance of the notice under paragraph (c)(1) of this section, the Commission shall issue a final order. If the Commission finds that the grounds referred to in paragraph (a) of this section exist, it will vacate the determination.

§ 270.506 Confidentiality.

(a) Except as provided in paragraph (b) of this section, the Commission will accord confidential protection to, and not disclose to the public, any information submitted by a jurisdictional agency under § 270.204, if:

(1) The jurisdictional agency, on its own motion or on request of the applicant, afforded such information confidential treatment before the jurisdictional agency; and

(2) The agency order or the applicant's request stated grounds for confidential treatment which fall within one of the exemptions described in paragraphs (1) through (9) of 5 U.S.C. 552(b).

(b) Upon receipt of a request for disclosure of information treated as confidential under paragraph (a) of this section, the Commission will determine in accordance with 5 U.S.C. 552 whether the information is exempt. 5 U.S.C. 552(b). If it determines the information is not exempt, the information will be made public. If it determines the information is exempt, the Commission will not make it public unless determines that its conduct of the proceeding to review the jurisdictional agency determination requires making such information available to the public or to particular parties, subject to conditions (including a protective order) as the Commission may prescribe. Before making any information public under this paragraph, the Commission will provide at least 5 days notice to the person who submitted the information.

§ 280.101 Definitions.

(a) NGPA definitions. Terms defined in the NGPA shall have the same meaning for purposes of this subchapter as they have under the NGPA, unless further defined in this subpart.

(b) Other definitions. For purposes of this subchapter:

(1) NGPA means the Natural Gas Policy Act of 1978.

(2) OCS means the Outer Continental Shelf as defined in section 2(35) of the NGPA.

[44 FR 12409, Mar. 7, 1979, as amended by Order 92, 45 FR 49252, July 24, 1980]

§ 281.201 Purpose.

The purpose of this subpart is to implement section 401 of the NGPA in order to provide that effective November 1, 1979, the curtailment plans of interstate pipelines protect, to the maximum extent practicable, deliveries of natural gas for essential agricultural uses and for high-priority uses in accordance with the provisions of this subpart.

[44 FR 26862, May 8, 1979]

§ 281.202 Applicability.

This subpart applies to the following interstate pipe lines:

Alabama-Tennessee Pipeline Company. Algonquin Gas Transmission Company. Arkansas Louisiana Natural Gas Company. Cities Service Gas Company. Colorado Interstate Gas Company. Columbia Gas Transmission Corporation. Consolidated Gas Supply Corporation. East Tennessee Natural Gas Company. Eastern Shore Natural Gas Company. El Paso Natural Gas Company. Florida Gas Transmission Company. Great Lakes Gas Transmission Company. Inter-City Minnesota Pipelines, Ltd., Inc. Kansas-Nebraska Natural Gas Company, Inc. Lawrenceburg Gas Transmission Company. Michigan-Wisconsin Pipeline Company. Mid-Louisiana Gas Company. Midwestern Gas Transmission Company. Mississippi River Transmission Company. Montana Dakota Utilities Company. National Fuel Gas Supply Company. North Penn Gas Company. Northern Natural Gas Company. Northwest Pipeline Corporation. Panhandle Eastern Pipeline Company. South Georgia Natural Gas Company. Southern Natural Gas Company. Southwest Gas Corporation. Tennessee Gas Pipeline Company, a Division of Tenneco, Inc. Tennessee Natural Gas Lines. Texas Eastern Transmission Corporation. Texas Gas Transmission Corporation. The Inland Gas Company. Transwestern Pipeline Company. Trunkline Gas Company. United Gas Pipe Line Company. Western Gas Interstate Company.

[44 FR 26862, May 8, 1979, as amended at 44 FR 48184, Aug. 17, 1979]

§ 281.203 Definitions and cross references.

(a) Definitions. For purposes of this subpart:

(1) Direct sale customer means an essential agricultural user of high priority use which purchases natural gas directly from an interstate pipeline and consumes such natural gas for a high-priority use or an essential agricultural use.

(2) Essential agricultural use means any use of natural gas which is certified by the Secretary of Agriculture as an “essential agricultural use” under section 401(c) of the NGPA, as identified in 7 CFR part 2900, et seq.

(3) Essential agricultural user means a person who uses natural gas for an essential agricultural use.

(4) High-priority use means any use of natural gas which qualifies the user as a high-priority user.

(5) High-priority user means any person who uses natural gas:

(i) In a residence;

(ii) In a small commercial establishment;

(iii) In a school or a hospital; or

(iv) For police protection, for fire protection, in a sanitation facility or a correctional facility.

(6) End-use curtailment plan means a provision in the tariff of an interstate pipeline that requires that under circumstances of supply shortage natural gas deliveries will be curtailed based at least in part upon factors which consider the end-use of the natural gas.

(7) Indirect sale customer of an interstate pipeline means an essential agricultural end-user served by a local distribution company which is served directly by the interstate pipeline.

(8) Residence means a dwelling using natural gas predominantly for residential purposes such as space heating, air conditioning, hot water heating, cooking, clothes drying, and other residential uses and includes apartment buildings and other multi-unit buildings.

(9) Small commercial establishment means any establishment (including institutions and local, state and Federal Government agencies) engaged primarily in the sale of goods or services where natural gas is used:

(i) In amounts of less than 50 Mcf on a peak day; and

(ii) For purposes other than those involving manufacturing or electric power generation.

(10) Hospital means a facility, the primary function of which is delivering medical care to patients who remain at the facility including nursing and convalescent homes. Outpatient clinics or doctors' offices are not included in this definition.

(11) School means a facility, the primary function of which is to deliver instruction to regularly enrolled students in attendance at such facility. Facilities used for both educational and noneducational activities are not included under this definition unless the latter activities are merely incidental to the delivery of instruction.

(12) Local distribution company means a local distribution company served directly by an interstate pipeline.

(13) Rolling base period means a time period in which entitlements of the customers of an interstate pipeline are established pursuant to the pipeline's currently effective curtailment plan and which is periodically updated to reflect recent gas requirements of such customers.

(14) Entitlements of a direct sale customer or a local distribution company customer with respect to a particular interstate pipeline means the amount of natural gas that customer is permitted to receive under the interstate pipeline's currently effective curtailment plan.

(15) Interstate pipeline purchaser means an interstate pipeline which received deliveries of natural gas from another interstate pipeline.

(16) Alternative fuel means alternative fuel as it is defined in Subpart C of this part.

(b) Cross references. (1) Essential agricultural requirements are calculated in accordance with § 281.208.

(2) Index of entitlements is that index of entitlements prepared in accordance in § 281.204(b).

[44 FR 26862, May 8, 1979, as amended by Order 29-C, 44 FR 61344, Oct. 25, 1979; Order 55-B, 45 FR 54739, July 18, 1980]

§ 281.204 Tariff filing requirements.

(a) General rule. Each interstate pipeline listed in § 281.202 shall file tariff sheets or sections, in accordance with § 154.4 of this chapter, including an index of entitlements, which provides that if the interstate pipeline is in curtailment, natural gas will be delivered in accordance with the provisions of this subpart. If the interstate pipeline has curtailment provisions in its currently effective tariff, the tariff sheets or sections shall amend the existing curtailment provisions. If the interstate pipeline has no curtailment plan in its currently effective tariff, when it files tariff sheets or sections to amend its currently effective tariff to include a curtailment plan such curtailment plan shall comply with the requirements of this subpart. The tariff sheets or sections shall be filed no later than October 1, 1979, with a proposed effective date of November 1, 1979. The Data Verification Committee report prepared in accordance with § 281.213 shall be filed with the tariff sheets or sections.

(b) Index of entitlements. (1) The index of entitlements for an interstate pipeline shall identify the natural gas entitlements in priority of service categories 1 and 2 (established in accordance with § 281.205(a)) for each direct sale customer, each local distribution company customer and each interstate pipeline purchaser on a daily, monthly, seasonal or other periodic basis used in the currently effective curtailment plan.

(2) Periodic update. Each interstate pipeline shall update its index of entitlements annually to reflect changes in Priority 2 entitlements. The new index of requirements shall be filed on September 15 of each year with a proposed effective date of November 1, except that if the interstate pipeline uses a rolling base period in its currently effective curtailment plan it shall file its new index of entitlements on the date upon which other end-uses of the customers of the interstate pipeline are updated in accordance with the currently effective tariff.

(3) Alternative fuel determination. The index of entitlements shall not include the volumes of natural gas for which volumes the essential agricultural user has the ability to use an alternative fuel, as determined under Subpart C of this part. Each interstate pipeline shall amend its index of entitlements pursuant to paragraph (b)(2) of this section to remove from the priority 2 entitlements and place in an appropriate priority of service category any such volumes or natural gas included in any index of entitlements that is effective on or after October 31, 1979.

(c) Other tariff provisions. (1) Every tariff filed under this subpart shall contain provisions that will require the interstate pipeline:

(i) To provide for deliveries of sufficient volumes of natural gas to respond to emergency situations (including environmental emergencies) during periods of curtailment where additional supplies are required to forestall irreparable injury to life or to property; and

(ii) To provide for deliveries of sufficient volumes of natural gas to provide for minimum plant protection when the plant is shut down.

(2) Volumetric delivery requirements. Notwithstanding any other provisions of this subpart, an interstate pipeline which is delivering natural gas in accordance with this subpart shall not be required to deliver to any customer volumes of natural gas on a daily, monthly, seasonal or other periodic basis which exceed the volumes of natural gas that the interstate pipeline may deliver to such customer without causing the interstate pipeline to violate any daily, monthly, seasonal or other periodic volumetric limitations established in the contract between the interstate pipeline and such customer.

(Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432; Department of Energy Organization Act, 42 U.S.C. 7101-7352; E.O. 12009, 42 FR 46267; Administrative Procedure Act, 5 U.S.C. 551 et seq.)

[44 FR 26862, May 8, 1979, as amended at 44 FR 45923, Aug. 6, 1979; 44 FR 62490, Oct. 31, 1979; Order 55-B, 45 FR 54739, July 18, 1980; Order 145, 46 FR 27913, May 22, 1981; Order 714, 73 FR 57535, Oct. 3, 2008]

§ 281.205 General rules.

(a) Priority of service categories—(1) Priority 1. Each interstate pipeline shall establish a new high-priority use category of service designated priority one (1) which shall include all the high-priority entitlements calculated in accordance with § 281.206 and those storage injection volumes calculated in accordance with paragraph (c)(2) of this section.

(2) Priority 2. Each interstate pipeline shall establish a new priority of service category designated priority two (2) which shall include all the essential agricultural use requirements calculated in accordance with § 281.207 and those storage injection volumes calculated in accordance with paragraph (c)(2) of this section.

(3) Other priority of service categories. Each interstate pipeline may retain the priority of service categories in its currently effective tariff, but such categories shall be placed at priorities below the new priorities 1 and 2. Each interstate pipeline shall reduce the entitlements in all other existing categories of service to the extent such entitlements have been placed into the new priority of service categories 1 or 2.

(b) Method of curtailment. All deliveries to all customers of the interstate pipeline for all volumes of natural gas not included in priorities 1 and 2 shall be fully curtailed by the interstate pipeline before priorities 1 and 2 entitlements are curtailed. Deliveries for priority 2 entitlements shall be fully curtailed by the interstate pipelines (in accordance with the currently effective curtailment plan) before priority 1 entitlements are curtailed by the interstate pipelines. Nothing in this paragraph is intended to alter the operation of any “small customer” or “small distributor” exemption or waiver (as defined in an interstate pipeline's currently effective curtailment plan).

(c) Storage—(1) General rule. Interstate pipelines shall classify customer storage injection volumes in the same manner as that used in the currently effective curtailment plan.

(2) Storage sprinkling. Interstate pipelines which classify customer storage injection volumes on the basis of the actual end-use of the natural gas shall recalculate storage injection volumes placed in each priority of service category based upon the index of entitlements to be filed on September 15.

(3) Other treatment of storage. Except as provided in paragraph (c)(2) of this section, no interstate pipeline shall recalculate or reclassify any customer storage injection volumes, and no customer storage injection volumes shall be included as priority 1 or 2 entitlements.

[44 FR 26862, May 8, 1979, as amended by Order 29-C, 44 FR 61344, Oct. 25, 1979; Order 145, 46 FR 27913, May 22, 1981]

§ 281.206 Priority 1 reclassification.

(a) Definitions. For purposes of this section “high-priority entitlements” means, with respect to a particular interstate pipeline.

(1) In the case of a direct sale customer, the volume of natural gas such direct sale customer is entitled to receive for high-priority uses (as defined in § 281.203) under the currently effective curtailment plan of the interstate pipeline;

(2) In the case of a local distribution company, the volume of natural gas which such local distribution company is entitled to receive on account of the high-priority uses (as defined in § 281.203) of its high-priority user customers under the currently effective curtailment plan of the interstate pipeline;

(3) In the case of an interstate pipeline purchaser the volume of natural gas such interstate pipeline purchaser is entitled to receive from an interstate pipeline supplier for the high-priority entitlements of its direct sale customers, local distribution company customers and interstate pipeline customers.

(b) Direct sale customer and local distribution company customers. (1)(i) Subject to paragraph (b)(2) of this section, and § 281.211 each direct sale customer may request each of its direct interstate pipeline suppliers to reclassify its high-priority entitlements in its currently effective curtailment plan as priority 1 entitlements.

(ii) Subject to paragraph (b)(2) of this section, and § 281.211 each local distribution company must request each of its direct interstate pipeline suppliers to reclassify its high priority entitlements in its currently effective curtailment plan as priority 1 entitlements.

(2) The direct sale customer or local distribution company customer shall designate the entitlements in each priority of service category in the currently effective curtailment plan for which priority 1 reclassification is requested. It shall request that those entitlements for which priority 1 reclassification is requested be excluded from the category of service in which they are included in the currently effective plan.

(3) Subject to § 281.210, the interstate pipeline shall reclassify all such high-priority entitlements as priority 1 entitlements and shall reduce by an equal amount the entitlements in such other priority of service categories as designated by the direct sale customer or local distribution company customer, (in accordance with paragraph (b)(2) of this section).

(c) Interstate pipeline. (1) Subject to paragraph (b)(2) of this section, and § 281.211 an interstate pipeline purchaser may request each of its direct interstate pipeline suppliers to reclassify its high-priority entitlements in its currently effective curtailment plan (equal to the attributed priority 1 entitlements calculated in accordance with § 281.209) as priority 1 entitlements in the currently effective curtailment plan of the interstate pipeline supplier.

(2) The interstate pipeline purchaser shall designate the entitlements in each priority of service category in the currently effective curtailment plan for which priority 1 reclassification is requested. It shall request that those entitlements for which priority 1 classification is requested be excluded from the category of service in which they are included in the currently effective plan.

(3) Subject to § 281.210, the interstate pipeline supplier shall reclassify all such high-priority entitlements as priority 1 entitlements and shall reduce the high-priority entitlements in other priority of service categories as designated by the interstate pipeline customer, (in accordance with paragraph (c)(2) of this section).

[44 FR 26862, May 8, 1979]

§ 281.207 Priority 2 classification.

(a) Direct sale customer. (1) Subject to paragraph (a)(2) of this section, and § 281.211 a direct sale customer may request each of its direct interstate pipeline suppliers to classify its essential agricultural requirements (calculated in accordance with § 281.208) as priority 2 entitlements.

(2) The essential agricultural user shall designate the entitlements in each priority of service category in the currently effective curtailment plan which reflect the essential agricultural requirements. It shall request that entitlements which are reflected in priority of service categories in the currently effective curtailment plan are removed from such priority of service categories.

(3) Subject to § 281.210, the interstate pipeline shall classify all such essential agricultural requirements as priority 2 entitlements and reduce the entitlements in such other priority of service categories as designated by the direct sale customer, (in accordance with paragraph (b)(2) of this section).

(b) Indirect sale customer. Subject to § 281.211 an indirect sale customer which is an essential agricultural user may ask each of its local distribution company direct suppliers to request each interstate pipeline supplier to classify the indirect essential agricultural requirements as priority 2 entitlements.

(c) Local distribution companies. (1) The local distribution company shall attribute (in accordance with § 281.209) the indirect essential agricultural requirements for which reclassification is sought under paragraph (b) of this section to its direct interstate pipeline suppliers. Subject to paragraph (b)(2) of this section, and § 281.211 the local distribution company shall request each of its direct interstate pipeline suppliers to classify the attributed indirect essential agricultural requirements as priority 2 entitlements.

(2) The local distribution company shall designate the entitlements in each priority of service in the currently effective curtailment plan which reflect the attributed indirect essential agricultural requirements. It shall request that those entitlements which are reflected in each category in the currently effective curtailment plan are removed from such priority of service category.

(3) Subject to § 281.210, the interstate pipeline shall classify all such attributed indirect essential agricultural requirements as priority 2 entitlements and shall reduce the entitlements of the local distribution company in such other priority of service categories as designated by the local distribution company, (in accordance with paragraph (b)(2) of this section).

(d) Interstate pipeline. (1) Subject to paragraph (d)(2) of this section, and § 281.211 an interstate pipeline purchaser may request each of its direct interstate pipeline suppliers to classify the attributed priority 2 entitlements (calculated under § 281.209) as priority 2 entitlements in the currently effective curtailment plan of the interstate pipeline supplier.

(2) The interstate pipeline purchaser shall designate the entitlements in each priority of service category in the currently effective curtailment plan of the interstate pipeline supplier which reflects the attributed priority 2 entitlements and request that those entitlements which are reflected in such priority of service categories in the currently effective curtailment plan are removed from such priority of service category.

(3) Subject to § 281.210, the interstate pipeline supplier shall classify the attributed priority 2 entitlements as priority 2 entitlements and shall reduce the entitlements of the interstate pipeline purchaser in such other priority of service categories as designated by the interstate pipeline purchaser, (in accordance with paragraph (d)(2) of this section).

[44 FR 26862, May 8, 1979]

§ 281.208 Calculation of essential agricultural requirements and attributable priority 2 entitlements.

(a) Scope. This section sets forth the method by which:

(1) An essential agricultural user calculates total essential agricultural requirements, direct essential agricultural requirements, and indirect essential agricultural requirements;

(2) A local distribution company calculates attributable indirect essential agricultural requirements for its essential agricultural user customers; and

(3) An interstate pipeline purchaser calculates it attributable priority 2 entitlements.

(b) Calculation by an essential agricultural user—(1) Total essential agricultural requirements—(i) General Rule. (A) The essential agricultural requirements of an essential agricultural user are those volumes (expressed in daily, monthly, seasonal or other appropriate periodic volumes) designated by the Secretary of Agriculture and calculated in accordance with 7 CFR 2900.4; less

(B) Alternative fuel volumes (determined under § 281.304).

(ii) Definitions. Current requirements as used in 7 CFR part 2900 means the lesser of

(A) The energy consumption from the most recent 12 month period for which actual data is available, with necessary adjustments; or

(B) The maximum volume of natural gas for which the essential agricultural user has installed capability to use for essential agricultural uses.

(2) Attribution of total essential agricultural requirement and indirect essential agricultural requirements. (i) The essential agricultural user shall attribute its total essential agricultural requirements among all its sources of supply of natural gas in accordance with § 281.209.

(ii) The direct essential agricultural requirement with respect to a particular interstate pipeline supplier is that part of the total essential agricultural requirements attributed under § 281.209 to the direct interstate pipeline supplier. The indirect essential agricultural requirement with respect to a particular local distribution company supplier is that part of the total essential agricultural requirements attributed under § 281.209 to a direct local distribution company supplier.

(c) Calculation by local distribution companies. (1) A local distribution company shall attribute under § 281.209 the indirect essential agricultural requirements of each of its essential agricultural user customers (calculated under paragraph (b)(2) of this section) among all the interstate pipelines which are direct suppliers of the local distribution company.

(2) That part of the indirect essential agricultural requirements which the local distribution company attributes to a particular interstate pipeline supplier is the attributed indirect essential agricultural requirements attributed to that interstate pipeline.

(d) Interstate pipelines. (1) An interstate pipeline purchaser may attribute under § 281.209 the priority 2 entitlements it includes in its index of entitlements among its direct interstate pipeline suppliers.

(2) The attributable priority 2 entitlements attributed to a particular interstate pipeline supplier is that part of the priority 2 entitlements of the interstate pipeline purchaser which it attributes to a particular interstate pipeline supplier.

[44 FR 26862, May 8, 1979, as amended at 44 FR 62490, Oct. 31, 1979]

§ 281.209 Attribution.

(a) Applicability. (1) This section sets forth the rules for attributing total essential agricultural requirements by an essential agricultural user, indirect essential agricultural requirements of an essential agricultural user by its local distribution company supplier and priority 1 and 2 entitlements by an interstate pipeline purchaser.

(2) This section does not apply to an essential agricultural user or local distribution company which receives all its natural gas supplies from a single source, or an interstate pipeline purchaser which does not receive natural gas from any other interstate pipeline.

(b) Natural gas supplies included for purposes of attribution. (1) For purposes of attribution in accordance with this section, natural gas from all direct sources, including but not limited to pipeline production, production by independent producers, production by affiliates, SNG facilities and natural gas purchased from local distribution companies, and interstate pipelines shall be included.

(2)(i) An essential agricultural user, which attributes under paragraph (d) a portion of the volumes which are its total essential agricultural requirements to a direct source of natural gas other than a direct supplier may not seek classification to priority 2 under § 281.207 for such portion of its total essential agricultural requirements.

(ii) A local distribution company which attributes under paragraph (e) a portion of the volumes which are its indirect essential agricultural requirements to a direct source of natural gas other than a direct supplier may not seek classification to priority 2 under § 281.207 for such portion of its indirect essential agricultural requirements.

(iii) An interstate pipeline purchaser which attributes under paragraph (f) a portion of the volumes of its priority 1 or 2 entitlements to a direct source of natural gas other than a direct supplier may not seek reclassification to priority 1 or classification to priority 2, respectively, for such portion of its priority 1 and 2 entitlements.

(c) Definitions. For purposes of this section:

(1) Direct supplier means, with respect to an essential agricultural user, an interstate pipeline or local distribution company which directly supplies such essential agricultural user, with respect to a local distribution company, an interstate pipeline which directly supplies such local distribution company and, with respect to an interstate pipeline purchaser, and interstate pipeline which directly supplies the interstate pipeline purchaser.

(2) Base period of a direct supplier means the fixed historical period in which entitlements of the customer of the direct supplier were established for purposes of the currently effective curtailment plan of such direct supplier.

(3) Annual quantity entitlements with respect to a particular direct supplier means the total entitlements an essential agricultural user, local distribution company or interstate pipeline is entitled to purchase from that direct supplier in a calendar year under the currently effective curtailment plan.

(d) Essential agricultural user. (1) An essential agricultural user shall calculate its attributable essential agricultural requirements attributable to a particular direct supplier by multiplying its total essential agricultural requirements by the Annual Quantity Entitlements from such direct supplier and dividing the product (numerator) by the sum of all Annual Quantity Entitlements and all volumes received from sources not providing an Annual Quantity Entitlement to such user (denominator).

(2) If an essential agricultural user does not have annual quantity entitlements only with respect to one of its direct suppliers, the attributable essential agricultural requirements attributable to such direct supplier shall be that part of the total essential agricultural requirements not attributed under paragraph (d)(1) of this section.

(3) If an essential agricultural user does not have Annual Quantity Entitlements with respect to more than one of its direct suppliers, the attributable essential agricultural requirements attributable to a particular direct supplier shall be calculated by multiplying its total essential agricultural requirements by the total volume of natural gas received from such supplier in 1972 and dividing the product (numerator) by the total supplies of natural gas received from all sources in 1972 (denominator).

(e) Local distribution company. A local distribution company shall calculate its attributable indirect essential agricultural requirements among its direct suppliers in the same manner as it attributed its supplies to its direct suppliers for purposes of establishing entitlements in the currently effective curtailment plans of such direct supplier.

(f) Interstate pipelines. An interstate pipeline shall attribute Priority 1 and 2 entitlements respectively among its direct pipeline suppliers in the same manner as it attributed its supplies to its direct pipeline suppliers for purposes of establishing entitlements in the currently effective curtailment plans of such direct suppliers.

[44 FR 26862, May 8, 1979, as amended by Order 29-C, 44 FR 61344, Oct. 25, 1979]

§ 281.210 Conflicting data.

(a) Interstate pipelines. Notwithstanding any other provision of this subpart, if the records of an interstate pipeline contain information which directly conflicts with a request for reclassification of priority 1 entitlements under § 281.206, or classification of priority 2 entitlements under § 281.207, the interstate pipeline may not include such volumes in priority 1 or 2 of its index of entitlements.

(b) Local distribution companies. Notwithstanding the provisions of § 281.207(c), if the records of a local distribution company contain information which directly conflicts with a request from an essential agricultural user to have the local distribution company to seek classification of volumes in priority 2, the local distribution company may not seek classification for such volumes.

[44 FR 26862, May 8, 1979]

§ 281.211 Filing and documentation.

(a) Priority 1—(1) Direct sales customers and local distribution companies. (i) Each request of a direct sale customer and local distribution company customer for reclassification of high-priority entitlements (as defined in § 281.206) to priority 1 entitlements shall be made in writing no later than July 31, 1979, and shall be accompanied by the data described in paragraph (a)(1)(ii) of this section.

(ii)(A) A table indicating high-priority entitlements (as defined in § 281.206) and the end-use of the natural gas in each priority of service category in the currently effective curtailment plan for which priority 1 reclassification is requested.

(B) A copy of the end-use data used to establish the high-priority requirements and designated end-use of the natural gas.

(2) Interstate pipelines. (i) Each interstate pipeline purchaser which reclassifies high-priority requirements of its customers as priority 1 entitlements may request that its high-priority requirements in the currently effective curtailment plan of its interstate pipeline suppliers (equal to the attributable priority 1 entitlements) be reclassified as priority 1 entitlements. Such requests shall be made in writing no later than August 31, 1979 and shall be accompanied by the data described in paragraph (a)(2)(ii) of this section.

(ii)(A) A table indicating high-priority entitlements (as defined in § 281.206) and end-use of the natural gas in each priority of service category in the currently effective curtailment plan of the interstate pipeline supplier for which priority 1 reclassification is requested.

(B) A copy of the end-use data used to establish the high-priority requirements and designated end-use of the natural gas.

(C) A table indicating the volumes and priority of service categories for which each of direct sale customers and local distribution company customers sought reclassification to priority 1.

(b) Priority 2—(1) Essential agricultural users. (i) Each request for classification of essential agricultural requirements as priority 2 entitlements shall be made in writing to the local distribution company supplier or the direct interstate pipeline supplier, as appropriate, no later than June 15 of each year, and shall set forth all calculations made in accordance with this subpart.

(ii) The request shall be accompanied by a statement that;

(A) Indicates the intended end-use(s) and volume(s) of the natural gas for which priority 2 entitlements are requested.

(B) Indicates the SIC Code activities of the essential agricultural user which qualifies it as an essential agricultural user in accordance with 7 CFR 2900.3.

(C) Includes the data and calculations used to determine essential agricultural requirements under 7 CFR 2900.4.

(D) Includes with respect to any essential agricultural user to which Subpart C applies the data and calculations necessary to determine alternative fuel volumes under § 281.304.

(iii) The statement under paragraph (b)(1)(ii) shall be signed by a responsible official of the essential agricultural user. Such official shall swear or affirm that the statements are true to the best of his information, knowledge and belief.

(2) Local distribution companies. Each request for classification of essential agricultural requirements as priority 2 requirements shall be made in writing to the direct interstate pipeline supplier no later than June 30 of each year, and shall set forth all calculations made in accordance with this subpart and all copies of all requests received from its essential agricultural uses under paragraph (b)(1) of this section.

(3) Interstate pipelines. Each request of an interstate pipeline purchaser for classification of attributable priority 2 entitlements as priority 2 entitlements shall be made in writing to the direct interstate pipeline supplier no later than July 15 of each year, and shall set forth all calculations made in accordance with this subpart and shall include copies of all requests of essential agricultural users and local distribution companies under paragraphs (b)(1) and (2) of this section.

(4) Subsequent request. (i) For 1979, changes in priority 2 entitlements for essential agricultural use establishments that have the ability to use an alternative fuel shall be filed under Subpart C of this part.

(ii) For years subsequent to 1979, the data required by this paragraph must be filed only to the extent that there has been a change in essential agricultural requirements.

(Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432; Department of Energy Organization Act, 42 U.S.C. 7101-7352; E.O. 12009, 42 FR 46267; Administrative Procedure Act, 5 U.S.C. 551 et seq.)

[44 FR 26862, May 8, 1979, as amended at 44 FR 45923, Aug. 6, 1979; 44 FR 62490, Oct. 31, 1979; Order 55-B, 45 FR 54740, July 18, 1980; Order 145, 46 FR 27913, May 22, 1981]

§ 281.212 Draft tariff and index of entitlements.

(a) Each interstate pipeline shall prepare draft tariff sheets or sections and a draft index of entitlements in accordance with this subpart.

(b) The draft tariff sheets or sections and index of entitlements shall be served on all customers of the interstate pipeline no later than August 1 of each year.

(c) Copies of all documents received by the interstate pipeline under § 281.210, the draft tariff sheets or sections and the draft index of entitlements shall be served on the Data Verification Committee no later than August 1 of each year.

(Natural Gas Policy Act of 1978, Pub. L. 95-621. Department of Energy Organization Act, 42 U.S.C. 7107 et seq.: E.O. 12009, 42 FR 46267; Administrative Procedure Act, 5 U.S.C. 551 et seq.)

[44 FR 26862, May 8, 1979, as amended at 44 FR 45923, Aug. 6, 1979; Order 145, 46 FR 27913, May 22, 1981; Order 714, 73 FR 57535, Oct. 3, 2008]

§ 281.213 Data Verification Committee.

(a) Each interstate pipeline shall establish a Data Verification Committee no later than August 1, 1979. It shall include, at a minimum, a representative of the interstate pipeline, Commission staff, a large and small local distribution company, and an essential agricultural user. The appropriate state and local regulatory bodies, and a representative of the United States Department of Agriculture may, at their option, be members.

(b) The Data Verification Committee shall review all calculations behind the draft tariff sheets or sections and the proposed index of entitlements. The Data Verification Committee may request, and the interstate pipeline shall immediately supply, any information requested by the Data Verification Committee.

(c) Any interested person may file a written protest concerning the index of entitlements. Such protests shall be filed with the Data Verification Committee no later than August 15 of each year.

(d) The Data Verification Committee shall review the draft tariff sheets or sections and index of entitlements and shall review the underlying data for uniformity in preparation.

(e) The Data Verification Committee shall prepare a report concerning the proposed index of requirements and the draft tariff sheets or sections for the interstate pipeline. It shall, at a minimum, specify all arithmetic errors and contain an evaluation of all protests. It may contain a proposed settlement of contested draft tariff sheets or sections. The report shall be submitted to the interstate pipeline no later than September 1 of each year.

(Natural Gas Act. 15 U.S.C. 717-717w; Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432; Department of Energy Organization Act, 42 U.S.C. 7101-7352; E.O. 12009, 42 FR 46267; Administrative Procedure Act, 5 U.S.C. 551 et seq.)

[44 FR 26862, May 8, 1979, as amended at 44 FR 45923, Aug. 6, 1979; Order 29-C, 44 FR 61345, Oct. 25, 1979; Order 145, 46 FR 27913, May 22, 1981; Order 714, 73 FR 57535, Oct. 3, 2008]

§ 281.214 Notice, complaint and remedy.

(a) Complaint. Any interested person may file a complaint concerning an alleged violation of this subpart under § 385.206 of this chapter.

(b) Remedy. If the Commission determines that a violation of this subpart has occurred, it shall take whatever action it deems appropriate in the circumstances. Such action may include payback, in kind or in dollars, by the person benefitting from the violation.

[44 FR 26862, May 8, 1979, as amended at 44 FR 61345, Oct. 25, 1979; Order 225, 47 FR 19058, May 3, 1982]

§ 281.215 Additional relief.

If an interstate pipeline rejects (under § 281.210 or otherwise) a request for reclassification under § 281.206 or classification under § 281.207 or if a local distribution company does not request (for any reason including the provisions of § 281.210) classification under § 281.206 on behalf of its high priority uses or reclassification on behalf of its essential agricultural users, the person aggrieved by such action may file a request for relief from curtailment under § 385.206 of this chapter. The request shall contain the information required in § 2.78(b) of the Commission Regulations.

[44 FR 26862, May 8, 1979, as amended by Order 225, 47 FR 19058, May 3, 1982]

§ 281.301 Purpose.

The purpose of this subpart is to determine the economic practicability and reasonable availability of alternative fuels, as prescribed in section 401(b) of the Natural Gas Policy Act of 1978 for use by essential agricultural use establishments that seek priority 2 entitlements for natural gas.

§ 281.302 Applicability.

This subpart applies to—

(a) Any essential agricultural use establishment for which an essential agricultural user:

(1) Has requested that natural gas be classified as priority 2 entitlements by an interstate pipeline under § 281.207; and

(2) Which has requested from any direct supplier priority 2 entitlements in excess of 300 Mcf per day; and

(b) Any essential agricultural use establishment with a new boiler, other than a diesel engine or turbine designed to use distillate fuels as the only alternative to natural gas, that:

(1) Has a capacity in excess of 300 Mcf of natural gas per day; and

(2) Is put into service for the first time after August 29, 1979.

§ 281.303 Definitions.

For purposes of this subpart—

(a) Ability to use a particular alternative fuel means that an essential agricultural use establishment had, on August 29, 1979, or thereafter acquired the installed physical capability to use the alternative fuel and has used that alternative fuel, in any amount, at any time after 1973, for an essential agricultural use.

(b) Alternative fuel means coal or residual fuel oil.

(c) Boiler means any fuel burning device that is used for generating steam or electricity or producing hot water for space heating or manufacturing processes.

(d) Capacity means the volumes of natural gas used if the boiler is operated at nameplate rated capacity for a continuous 16-hour period.

(e) Coal means lignite or any rank of bituminous coal or anthracite coal.

(f) Direct supplier means, with respect to an essential agricultural use establishment, an interstate pipeline or local distribution company which directly supplies such essential agricultural use establishment; with respect to a local distribution company, an interstate pipeline which directly supplies such local distribution company; and, with respect to an interstate pipeline purchaser, an interstate pipeline which directly supplies the interstate pipeline purchaser.

(g) Distillate fuel means Nos. 1 and 2 heating oils, diesel fuel, and No. 4 fuel oil, as defined in the standard specification for fuel oils published by the American Society for Testing and Materials, ASTM, D396 and D975.

(h) Essential agricultural requirements means volumes of natural gas certified by the Secretary of Agriculture and calculated in accordance with 7 CFR 2900.4 and § 281.208(b) of this part.

(i) Essential agricultural use means any use of natural gas, as defined in § 281.203(a)(2) of this chapter and 7 CFR 2900.3.

(j) Essential agricultural user means an essential agricultural user as defined in § 281.203(b)(3).

(k) Essential agricultural use establishment is used as defined in 7 CFR 2900.2.

(l) Local distribution company means a local distribution company served directly by an interstate pipeline.

(m) Priority 2 entitlements means the essential agricultural requirements of an essential agricultural use establishment which requirements are classified by an interstate pipeline as priority 2 in its curtailment plan under Subpart B.

(n) Residual fuel oil means Nos. 5 and 6 oil, Bunker C, and Navy Special as defined in the standard specification for fuel oils published by the American Society for Testing and Materials, ASTM, D396.

[44 FR 62490, Oct. 31, 1979, as amended by Order 55-B, 45 FR 54740, July 18, 1980]

§ 281.304 Computation of alternative fuel volume.

(a) General rule. For purposes of § 281.208(b)(1)(i)(B), and § 281.305:

(1) Alternative fuel volume of an essential agricultural user is equal to the sum of the alternative fuel volumes for each agricultural use establishment for which such user has requested from any direct supplier priority 2 entitlements in excess of 300 Mcf.

(2) Alternative fuel volume for an agricultural use establishment is that portion of such establishment's natural gas requirements for which such establishment has requested priority 2 curtailment and for which the establishment had on August 29, 1979, or thereafter, the ability to use alternative fuel.

(b) New boilers. For purposes of § 281.208(b)(1)(i)(B) and § 281.305: any new boiler of an essential agricultural use establishment shall be deemed to have alternative fuel volumes, if the boiler:

(1) Has a capacity in excess of 300 Mcf of natural gas per day;

(2) Is put into service for the first time after August 29, 1979; and

(3) Is not a diesel engine or turbine designed to use distillate fuels as the only substitute for natural gas.

[44 FR 62490, Oct. 31, 1979, as amended by Order 55-B, 45 FR 54740, July 18, 1980]

§ 281.305 General rule.

Any essential agricultural user subject to this subpart that has requested from any direct supplier priority 2 classification for volumes for any essential agricultural use establishment shall reduce its essential agricultural requirements calculated under § 281.208 to reflect the exclusion of volumes of natural gas for which its essential agricultural establishment has alternative fuel volumes under § 281.304.

§ 284.1 Definitions.

(a) Transportation includes storage, exchange, backhaul, displacement, or other methods of transportation.

(b) Appropriate state regulatory agency means a state agency which regulates intrastate pipelines and local distribution companies within such state. When used in reference to rates and charges, the term includes only those agencies which set rates and charges on a cost-of-service basis.

(c) Market center means an area where gas purchases and sales occur at the intersection of different pipelines.

(d) Major non-interstate pipeline means a pipeline that fits the following criteria:

(1) It is not a “natural gas company” under section 1 of the Natural Gas Act, or is a “natural gas company” and has obtained a service area determination under section 7(f) of the Natural Gas Act from the Commission;

(2) It delivers annually more than fifty (50) million MMBtu (million British thermal units) of natural gas measured in average deliveries for the previous three calendar years; or, if the pipeline has been operational for less than three years, its design capacity permits deliveries of more than fifty (50) million MMBtu of natural gas annually.

[44 FR 52184, Sept. 7, 1989, as amended by Order 636, 57 FR 13315, Apr. 16, 1992; Order 720, 73 FR 73517, Dec. 2, 2008; Order 720-A, 75 FR 5201, Feb. 1, 2010]

§ 284.2 Refunds and interest.

(a) Refunds. Any rate or charge collected for any sale, transportation, or assignment conducted pursuant to this part which exceeds the rates or charges authorized by this part shall be refunded.

(b) Interest. All refunds made pursuant to this section must include interest at an amount determined in accordance with § 154.501(d) of this chapter.

[44 FR 52184, Sept. 7, 1979, as amended at 44 FR 53505, Sept. 14, 1979; Order 273, 48 FR 1288, Jan. 12, 1983; Order 581, 60 FR 53072, Oct. 11, 1995]

§ 284.3 Jurisdiction under the Natural Gas Act.

(a) For purposes of section 1(b) of the Natural Gas Act, the provisions of such Act and the jurisdiction of the Commission under such Act shall not apply to any transportation or sale in interstate commerce of natural gas if such a transaction is authorized pursuant to section 311 or 312 of the NGPA.

(b) For purposes of the Natural Gas Act, the term “natural gas company” (as defined by section 2(6) of such Act) shall not include any person by reason of, or with respect to, any transaction involving natural gas if the provisions of the Natural Gas Act do not apply to such transaction by reason of paragraph (a) of this section.

(c) The Natural Gas Act shall not apply to facilities utilized solely for transportation authorized by section 311(a) of the NGPA.

[44 FR 52184, Sept. 7, 1979, as amended by Order 581, 60 FR 53072, Oct. 11, 1995]

§ 284.4 Reporting.

(a) Reports in MMBtu. All reports filed pursuant to this part must indicate quantities of natural gas in MMBtu's. An MMBtu means a million British thermal units. A British thermal unit or Btu means the quantity of heat required to raise the temperature of one pound avoirdupois of pure water from 58.5 degrees to 59.5 degrees Fahrenheit, determined in accordance with paragraphs (b) and (c) of this section.

(b) Measurement. The Btu content of one cubic foot of natural gas under the standard conditions specified in paragraph (c) of this section is the number of Btu's produced by the complete combustion of such cubic foot of gas, at constant pressure with air of the same temperature and pressure as the gas, when the products of combustion are cooled to the initial temperature of the gas and air and when the water formed by such combustion is condensed to a liquid state.

(c) Standard conditions. The standard conditions for purposes of paragraph (b) of this section are as follows: The gas is saturated with water vapor at 60 degrees Fahrenheit under a pressure equivalent to that of 30.00 inches of mercury at 32 degrees Fahrenheit, under standard gravitational force (980.665 centimeters per second squared).

[Order 581, 60 FR 53072, Oct. 11, 1995]

§ 284.5 Further terms and conditions.

The Commission may prospectively, by rule or order, impose such further terms and conditions as it deems appropriate on transactions authorized by this part.

§ 284.6 Rate interpretations.

(a) Procedure. A pipeline may obtain an interpretation pursuant to subpart L of part 385 of this chapter concerning whether particular rates and charges comply with the requirements of this part.

(b) Address. Requests for interpretations should be addressed to: FERC Part 284 Interpretations, Office of General Counsel, Federal Energy Regulatory Commission, Washington, DC 20426.

[44 FR 66791, Nov. 21, 1979; 44 FR 75383, Dec. 20, 1979, as amended by Order 225, 47 FR 19058, May 3, 1982; Order 581, 60 FR 53072, Oct. 11, 1995]

§ 284.7 Firm transportation service.

(a) Firm transportation availability. (1) An interstate pipeline that provides transportation service under subpart B or G or this part must offer such transportation service on a firm basis and separately from any sales service.

(2) An intrastate pipeline that provides transportation service under Subpart C may offer such transportation service on a firm basis.

(3) Service on a firm basis means that the service is not subject to a prior claim by another customer or another class of service and receives the same priority as any other class of firm service.

(4) An interstate pipeline that provided a firm sales service on May 18, 1992, and that offers transportation service on a firm basis under subpart B or G of this part, must offer a firm transportation service under which firm shippers may receive delivery up to their firm entitlements on a daily basis without penalty.

(b) Non-discriminatory access. (1) An interstate pipeline or intrastate pipeline that offers transportation service on a firm basis under subpart B, C or G must provide such service without undue discrimination, or preference, including undue discrimination or preference in the quality of service provided, the duration of service, the categories, prices, or volumes of natural gas to be transported, customer classification, or undue discrimination or preference of any kind.

(2) An interstate pipeline that offers transportation service on a firm basis under subpart B or G of this part must provide each service on a basis that is equal in quality for all gas supplies transported under that service, whether purchased from the pipeline or another seller.

(3) An interstate pipeline that offers transportation service on a firm basis under subpart B or G of this part may not include in its tariff any provision that inhibits the development of market centers.

(c) Reasonable operational conditions. Consistent with paragraph (b) of this section, a pipeline may impose reasonable operational conditions on any service provided under this part. Such conditions must be filed by the pipeline as part of its transportation tariff.

(d) Segmentation. An interstate pipeline that offers transportation service under subpart B or G of this part must permit a shipper to make use of the firm capacity for which it has contracted by segmenting that capacity into separate parts for its own use or for the purpose of releasing that capacity to replacement shippers to the extent such segmentation is operationally feasible.

(e) Reservation fee. Where the customer purchases firm service, a pipeline may impose a reservation fee or charge on a shipper as a condition for providing such service. Except for pipelines subject to subpart C of this part, if a reservation fee is charged, it must recover all fixed costs attributable to the firm transportation service, unless the Commission permits the pipeline to recover some of the fixed costs in the volumetric portion of a two-part rate. A reservation fee may not recover any variable costs or fixed costs not attributable to the firm transportation service. Except as provided in this paragraph, the pipeline may not include in a rate for any transportation provided under subpart B, C or G of this part any minimum bill or minimum take provision, or any other provision that has the effect of guaranteeing revenue.

(f) Limitation. A person providing service under Subpart B, C or G of this part is not required to provide any requested transportation service for which capacity is not available or that would require the construction or acquisition of any new facilities.

[Order 436, 50 FR 42493, Oct. 18, 1985]

Editorial Note:For Federal Register citations affecting § 284.7, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 284.8 Release of firm capacity on interstate pipelines.

(a) An interstate pipeline that offers transportation service on a firm basis under subpart B or G of this part must include in its tariff a mechanism for firm shippers to release firm capacity to the pipeline for resale by the pipeline on a firm basis under this section.

(b)(1) Firm shippers must be permitted to release their capacity, in whole or in part, on a permanent or short-term basis, without restriction on the terms or conditions of the release. A firm shipper may arrange for a replacement shipper to obtain its released capacity from the pipeline. A replacement shipper is any shipper that obtains released capacity.

(2) The rate charged the replacement shipper for a release of capacity may not exceed the applicable maximum rate, except that no rate limitation applies to the release of capacity for a period of one year or less if the release is to take effect on or before one year from the date on which the pipeline is notified of the release. Payments or other consideration exchanged between the releasing and replacement shippers in a release to an asset manager as defined in paragraph (h)(3) of this section are not subject to the maximum rate.

(c) Except as provided in paragraph (h) of this section, a firm shipper that wants to release any or all of its firm capacity must notify the pipeline of the terms and conditions under which the shipper will release its capacity. The firm shipper must also notify the pipeline of any replacement shipper designated to obtain the released capacity under the terms and conditions specified by the firm shipper.

(d) The pipeline must provide notice of offers to release or to purchase capacity, the terms and conditions of such offers, and the name of any replacement shipper designated in paragraph (b) of this section, on an Internet web site, for a reasonable period.

(e) The pipeline must allocate released capacity to the person offering the highest rate and offering to meet any other terms and conditions of the release. If more than one person offers the highest rate and meets the terms and conditions of the release, the released capacity may be allocated on a basis provided in the pipeline's tariff, provided however, if the replacement shipper designated in paragraph (b) of this section offers the highest rate, the capacity must be allocated to the designated replacement shipper.

(f) Unless otherwise agreed by the pipeline, the contract of the shipper releasing capacity will remain in full force and effect, with the net proceeds from any resale to a replacement shipper credited to the releasing shipper's reservation charge.

(g) To the extent necessary, a firm shipper on an interstate pipeline that offers transportation service on a firm basis under subpart B or G of this part is granted a limited-jurisdiction blanket certificate of public convenience and necessity pursuant to section 7 of the Natural Gas Act solely for the purpose of releasing firm capacity pursuant to this section.

(h)(1) The following releases need not comply with the bidding requirements of paragraphs (c) through (e) of this section:

(i) A release of capacity to an asset manager as defined in paragraph (h)(3) of this section;

(ii) A release of capacity to a marketer participating in a state-regulated retail access program as defined in paragraph (h)(4) of this section;

(iii) A release for more than one year at the maximum tariff rate; and

(iv) A release for any period of 31 days or less.

(v) If a release is exempt from bidding under paragraph (h)(1) of this section, notice of the release must be provided on the pipeline's Internet Web site as soon as possible, but not later than the first nomination, after the release transaction commences.

(2) When a release of capacity is exempt from bidding under paragraph (h)(1)(iv) of this section, a firm shipper may not roll over, extend or in any way continue the release to the same replacement shipper using the 31 days or less bidding exemption until 28 days after the first release period has ended. The 28-day hiatus does not apply to any re-release to the same replacement shipper that is posted for bidding or that qualifies for any of the other exemptions from bidding in paragraph (h)(1) of this section.

(3) A release to an asset manager exempt from bidding requirements under paragraph (h)(1)(i) of this section is any pre-arranged release that contains a condition that the releasing shipper may call upon the replacement shipper to deliver to, or purchase from, the releasing shipper a volume of gas up to 100 percent of the daily contract demand of the released transportation or storage capacity, as provided in paragraphs (h)(3)(i) through (h)(3)(iii) of this paragraph.

(i) If the capacity release is for a period of one year or less, the asset manager's delivery or purchase obligation must apply on any day during a minimum period of the lesser of five months (or 155 days) or the term of the release.

(ii) If the capacity release is for a period of more than one year, the asset manager's delivery or purchase obligation must apply on any day during a minimum period of five months (or 155 days) of each twelve-month period of the release, and on five-twelfths of the days of any additional period of the release not equal to twelve months.

(iii) If the capacity release is a release of storage capacity, the asset manager's delivery or purchase obligation need only be up to 100 percent of the daily contract demand under the release for storage withdrawals or injections, as applicable.

(4) A release to a marketer participating in a state-regulated retail access program exempt from bidding requirements under paragraph (h)(1)(ii) of this section is any prearranged capacity release that will be utilized by the replacement shipper to provide the gas supply requirement of retail consumers pursuant to a retail access program approved by the state agency with jurisdiction over the local distribution company that provides delivery service to such retail consumers.

[Order 636, 57 FR 13318, Apr. 16, 1992, as amended by Order 636-A, 57 FR 36217, Aug. 12, 1992; Order 577, 60 FR 16983, Apr. 4, 1995; Order 577-A, 60 FR 30187, June 8, 1995. Redesignated and amended by Order 637, 65 FR 10220, Feb. 25, 2000; Order 637-A, 65 FR 35765, June 5, 2000; Order 712, 73 FR 37092, June 30, 2008; Order 712-A, 73 FR 72714, Dec. 1, 2008; 73 FR 79628, Dec. 30, 2008]

§ 284.9 Interruptible transportation service.

(a) Interruptible transportation availability. (1) An interstate pipeline that provides firm transportation service under subpart B or G of this part must also offer transportation service on an interruptible basis under that subpart or subparts and separately from any sales service.

(2) An intrastate pipeline that provides transportation service under Subpart C may offer such transportation service on an interruptible basis.

(3) Service on an interruptible basis means that the capacity used to provide the service is subject to a prior claim by another customer or another class of service and receives a lower priority than such other classes of service.

(b) The provisions regarding non-discriminatory access, reasonable operational conditions, and limitations contained in § 284.7 (b), (c), and (f) apply to pipelines providing interruptible service under this section.

(c) Reservation fee. No reservation fee may be imposed for interruptible service. A pipeline's rate for any transportation service provided under this section may not include any minimum bill provision, minimum take provision, or any other provision that has the effect of guaranteeing revenue.

[Order 436, 50 FR 42494, Oct. 18, 1985]

Editorial Note:For Federal Register citations affecting § 284.9, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 284.10 Rates.

(a) Applicability. Any rate charged for transportation service under subparts B and G of this part must be established under a rate schedule that is filed with the Commission prior to commencement of such service and that conforms to the requirements of this section.

(b) Rate objectives. Maximum rates for both peak and offpeak periods must be designed to achieve the following three objectives:

(1) Rates for service during peak periods should ration capacity;

(2) Rates for firm service during off-peak periods and for interruptible service during all periods should maximize throughput; and

(3) The pipeline's revenue requirement allocated to firm and interruptible services should be attained by providing the projected units of service in peak and off-peak periods at the maximum rate for each service.

(c) Rate design—(1) Volumetric rates. Except as provided in § 284.7(e), any rate filed for service subject to this section must be a one-part rate that recovers the costs allocated to the service to the extent that the projected units of that service are actually purchased and may not include a demand charge, a minimum bill or minimum take provision or any other provision that has the effect of guaranteeing revenue. Such rate must separately identify cost components attributable to transportation, storage, and gathering costs.

(2) Based on projected units of service. Any rate filed for service subject to this section must be designed to recover costs on the basis of projected units of service. The fixed costs allocated to capacity reservations, as determined in accordance with § 284.7(e), should be used along with the projected nominations accepted by the pipeline to compute the unit reservation fee. The remaining fixed costs and all variable costs should be used to determine the volumetric rate computed on the basis of projected volumes to be transported. The units projected for the service in rates filed under this section may be changed only in a subsequent rate filing under section 4 of the Natural Gas Act.

(3) Differentiation due to time and distance. Any rate filed for service subject to this section must reasonably reflect any material variation in the cost of providing the service due to:

(i) Whether the service is provided during a peak or an off-peak period; and

(ii) The distance over which the transportation is provided.

(4) Cost basis for rates. (i) Any maximum rate filed under this section must be designed to recover on a unit basis, solely those costs which are properly allocated to the service to which the rate applies.

(ii) Any minimum rate filed under this section must be based on the average variable costs which are properly allocated to the service to which the rate applies.

(5) Rate flexibility. (i) Any rate schedule filed under this section must state a maximum rate and a minimum rate.

(ii)(A) Except as provided in paragraph (d)(5)(ii)(B) of this section the pipeline may charge an individual customer any rate that is neither greater than the maximum rate nor less than the minimum rate on file for that service.

(B) If a pipeline does not hold a blanket certificate under Subpart G of this part, it may not charge, in a transaction involving its marketing affiliate, a rate that is lower than the highest rate it charges in any transaction not involving its marketing affiliate.

(iii) The pipeline may not file a revised or new rate designed to recover costs not recovered under rates previously in effect.

[Order 436, 50 FR 42493, Oct. 18, 1985, as amended at 50 FR 52274, Dec. 23, 1985; 53 FR 22163, June 14, 1988; Order 522, 55 FR 12169, Apr. 2, 1990; Order 581, 60 FR 53072, Oct. 11, 1995. Redesignated and amended by Order 637, 65 FR 10220, Feb. 25, 2000]

§ 284.11 Environmental compliance.

(a) Any activity involving the construction of, or the abandonment with removal of, facilities that is authorized pursuant to § 284.3(c) and subpart B or C of this part is subject to the terms and conditions of § 157.206(b) of this chapter.

(b) Advance notification—(1) General rule. Except as provided in paragraph (b)(2) of this section, at least 30 days prior to commencing construction a company must file notification with the Commission of any activity described in paragraph (a) of this section.

(2) Exception. The advance notification described in paragraph (b)(1) of this section is not required if the cost of the project does not exceed the cost limit specified in Column 1 of Table I of § 157.208(d) of this chapter.

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

(1) A brief description of the facilities to be constructed or abandoned with removal of facilities (including pipeline size and length, compression horsepower, design capacity, and cost of construction);

(2) Evidence of having complied with each provision of § 157.206(b) of this chapter;

(3) Current U.S. Geological Survey 7.5-minute series topographical maps showing the location of the facilities; and

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

(d) Reporting requirements. On or before May 1 of each year, a company must file (on electronic media pursuant to § 385.2011 of this chapter, accompanied by 7 paper copies) an annual report that lists for the previous calendar year each activity that is described in paragraph (a) of this section, and which was completed during the previous calendar year and exempt from the advance notification requirement pursuant to paragraph (b)(2) of this section. For each such activity, the company must include all of the information described in paragraph (c) of this section.

[Order 544, 57 FR 46495, Oct. 9, 1992, as amended by Order 581, 60 FR 53072, Oct. 11, 1995; Order 603-A, 64 FR 54537, Oct. 7, 1999]

§ 284.12 Standards for pipeline business operations and communications.

(a) Incorporation by reference of NAESB standards. (1) An interstate pipeline that transports gas under subparts B or G of this part must comply with the business practices and electronic communications standards as promulgated by the North American Energy Standards Board, as incorporated herein by reference in paragraphs (a)(1)(i) through (vii) of this section.

(i) WGQ Additional Standards, Version 4.0, September 29, 2023, (including Addition of WGQ Standard No. 0.3.30, November 25, 2024).

(ii) WGQ Nominations Related Standards, Version 4.0, September 29, 2023.

(iii) WGQ Flowing Gas Related Standards, Version 4.0, September 29, 2023.

(iv) WGQ Invoicing Related Standards, Version 4.0, September 29, 2023, (including Minor Correction MC24002 applied May 17, 2024).

(v) WGQ Quadrant Electronic Delivery Mechanism Related Standards, Version 4.0, September 29, 2023, (including Revision to Standard No. 4.3.23, November 25, 2024).

(vi) WGQ Capacity Release Related Standards, Version 4.0, September 29, 2023, (including Addition of WGQ Standard No. 5.3.74, November 25, 2024); and

(vii) WGQ Cybersecurity Related Standards, Version 4.0, September 29, 2023.

(2) The material listed in paragraph (a)(1) is incorporated by reference into this section with the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. All approved material is available for inspection at the Federal Energy Regulatory Commission and at the National Archives and Records Administration (NARA). For assistance in viewing the material, contact the Federal Energy Regulatory Commission at: 888 First Street NE, Washington, DC 20426 phone: 202-502-8371; email: public.referenceroom@ferc.gov; website: https://www.ferc.gov. For information on the availability of this material at NARA, visit www.archives.gov/federal-register/cfr/ibr-locations or email fr.inspection@nara.gov. The material also may be obtained from the North American Energy Standards Board, 801 Travis Street, Suite 1675, Houston, TX 77002; phone: (713) 356-0060; website: https://www.naesb.org/.

(b) Business practices and electronic communication requirements. An interstate pipeline that transports gas under subparts B or G of this part must comply with the following requirements. The regulations in this paragraph adopt the abbreviations and definitions contained in the North American Energy Standards Board Wholesale Gas Quadrant standards incorporated by reference in paragraph (a)(1) of this section.

(1) Nominations.

(i) Intra-day nominations.

(A) A pipeline must give scheduling priority to an intra-day nomination submitted by a firm shipper over nominated and scheduled volumes for interruptible shippers. When an interruptible shipper's scheduled volumes are to be reduced as a result of an intra-day nomination by a firm shipper, the interruptible shipper must be provided with advance notice of such reduction and must be notified whether penalties will apply on the day its volumes are reduced.

(B) An intra-day nomination submitted on the day prior to gas flow will take effect at the start of the gas day at 9 a.m. CCT.

(ii) Capacity release scheduling. (A) Pipelines must permit shippers acquiring released capacity to submit a nomination at the earliest available nomination opportunity after the acquisition of capacity. If the pipeline requires the replacement shipper to enter into a contract, the contract must be issued within one hour after the pipeline has been notified of the release, but the requirement for contracting must not inhibit the ability of the replacement shipper to submit a nomination at the earliest available nomination opportunity.

(B) A pipeline must permit releasing shippers, as a condition of a capacity release, to recall released capacity and renominate such recalled capacity at each nomination opportunity. Each replacement shipper must be provided with advance notice of such recall and must be notified whether penalties will apply on the day its volumes are reduced.

(iii) Within 60 days after a shipper request, a pipeline must file to make appropriate tariff changes at the Commission to allow multiple shippers associated with a designated agent or asset manager to be jointly and severally liable under a single firm transportation service agreement, subject to reasonable terms and conditions.

(2) Flowing gas. (i) Operational balancing agreements. A pipeline must enter into Operational Balancing Agreements at all points of interconnection between its system and the system of another interstate or intrastate pipeline.

(ii) Netting and trading of imbalances. A pipeline must establish provisions permitting shippers and their agents to offset imbalances accruing on different contracts held by the shipper with the pipeline and to trade imbalances with other shippers where such imbalances have similar operational impact on the pipeline's system.

(iii) Imbalance management. A pipeline with imbalance penalty provisions in its tariff must provide, to the extent operationally practicable, parking and lending or other services that facilitate the ability of its shippers to manage transportation imbalances. A pipeline also must provide its shippers the opportunity to obtain similar imbalance management services from other providers and shall provide those shippers using other providers access to transportation and other pipeline services without undue discrimination or preference.

(iv) Operational flow orders. A pipeline must take all reasonable actions to minimize the issuance and adverse impacts of operational flow orders (OFOs) or other measures taken to respond to adverse operational events on its system. A pipeline must set forth in its tariff clear standards for when such measures will begin and end and must provide timely information that will enable shippers to minimize the adverse impacts of these measures.

(v) Penalties. A pipeline may include in its tariff transportation penalties only to the extent necessary to prevent the impairment of reliable service. Pipelines may not retain net penalty revenues, but must credit them to shippers in a manner to be prescribed in the pipeline's tariff. A pipeline with penalty provisions in its tariff must provide to shippers, on a timely basis, as much information as possible about the imbalance and overrun status of each shipper and the imbalance of the pipeline's system.

(3) Communication protocols. (i)(A) All electronic information provided and electronic transactions conducted by a pipeline must be provided on the public Internet. A pipeline must provide, upon request, private network connections using internet tools, internet directory services, and internet communication protocols and must provide these networks with non-discriminatory access to all electronic information. A pipeline may charge a reasonable fee to recover the costs of providing such an interconnection.

(B) A pipeline must implement this requirement no later than June 1, 2000.

(ii) A pipeline must comply with the following requirements for documents constituting public information posted on the pipeline web site:

(A) The documents must be accessible to the public over the public Internet using commercially available web browsers, without imposition of a password or other access requirement;

(B) Users must be able to search an entire document online for selected words, and must be able to copy selected portions of the documents; and

(C) Documents on the web site should be directly downloadable without the need for users to first view the documents on the web site.

(iii) If a pipeline uses a numeric or other designation to represent information, an electronic cross-reference table between the numeric or other designation and the information represented must be available to users, at a cost not to exceed reasonable shipping and handling.

(iv) A pipeline must provide the same content for all information regardless of the electronic format in which it is provided.

(v) A pipeline must maintain, for a period of three years, all information displayed and transactions conducted electronically under this section and be able to recover and regenerate all such electronic information and documents. The pipeline must make this archived information available in electronic form for a reasonable fee.

(vi) A pipeline must post notices of operational flow orders, critical periods, and other critical notices on its Internet web site and must notify affected parties of such notices in either of the following ways to be chosen by the affected party: Internet E-Mail or direct notification to the party's Internet URL address.

(4) Communication and information sharing among pipelines and public utilities. (i) A pipeline is authorized to share non-public, operational information with a public utility, as defined in § 38.2(a) of this chapter or another pipeline covered by this section, for the purpose of promoting reliable service or operational planning.

(ii) Except as permitted in paragraph (b)(4)(i) of this section, a pipeline and its employees, contractors, consultants, and agents are prohibited from disclosing, or using anyone as a conduit for the disclosure of, non-public, operational information received from a public utility pursuant to § 38.2 of this chapter to a third party or to its marketing function employees as that term is defined in § 358.3(d) of this chapter.

[Order 587, 61 FR 39068, July 26, 1996]

Editorial Note:For Federal Register citations affecting § 284.12, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 284.13 Reporting requirements for interstate pipelines.

An interstate pipeline that provides transportation service under subparts B or G of this part must comply with the following reporting requirements.

(a) Cross references. The pipeline must comply with the requirements in Part 358, Part 250, and Part 260 of this chapter, where applicable.

(b) Reports on firm and interruptible services. An interstate pipeline must post the following information on its Internet web site, and provide the information in downloadable file formats, in conformity with § 284.12 of this part, and must maintain access to that information for a period not less than 90 days from the date of posting.

(1) For pipeline firm service and for release transactions under § 284.8, the pipeline must post with respect to each contract, or revision of a contract for service, the following information no later than the first nomination under a transaction:

(i) The full legal name of the shipper, and identification number, of the shipper receiving service under the contract, and the full legal name, and identification number, of the releasing shipper if a capacity release is involved or an indication that the pipeline is the seller of transportation capacity;

(ii) The contract number for the shipper receiving service under the contract, and, in addition, for released transactions, the contract number of the releasing shipper's contract;

(iii) The rate charged under each contract;

(iv) The maximum rate, and for capacity release transactions not subject to a maximum rate, the maximum rate that would be applicable to a comparable sale of pipeline services;

(v) The duration of the contract;

(vi) The receipt and delivery points and the zones or segments covered by the contract, including the location name and code adopted by the pipeline in conformance with paragraph (f) of this section for each point, zone or segment;

(vii) The contract quantity or the volumetric quantity under a volumetric release;

(viii) Special terms and conditions applicable to a capacity release transaction, including all aspects in which the contract deviates from the pipeline's tariff, and special details pertaining to a pipeline transportation contract, including whether the contract is a negotiated rate contract, conditions applicable to a discounted transportation contract, and all aspects in which the contract deviates from the pipeline's tariff.

(ix) Whether there is an affiliate relationship between the pipeline and the shipper or between the releasing and replacement shipper.

(x) Whether a capacity release is a release to an asset manager as defined in § 284.8(h)(3) and the asset manager's obligation to deliver gas to, or purchase gas from, the releasing shipper.

(xi) Whether a capacity release is a release to a marketer participating in a state-regulated retail access program as defined in § 284.8(h)(4).

(2) For pipeline interruptible service, the pipeline must post on a daily basis no later than the first nomination for service under an interruptible agreement, the following information:

(i) The full legal name, and identification number, of the shipper receiving service;

(ii) The rate charged;

(iii) The maximum rate;

(iv) The receipt and delivery points between which the shipper is entitled to transport gas at the rate charged, including the location name and code adopted by the pipeline in conformance with paragraph (f) of this section for each point, zone, or segment;

(v) The quantity of gas the shipper is entitled to transport;

(vi) Special details pertaining to the agreement, including conditions applicable to a discounted transportation contract and all aspects in which the agreement deviates from the pipeline's tariff.

(vii) Whether the shipper is affiliated with the pipeline.

(c) Index of customers. (1) On the first business day of each calendar quarter, an interstate pipeline must file with the Commission an index of all its firm transportation and storage customers under contract as of the first day of the calendar quarter that complies with the requirements set forth by the Commission. The Commission will establish the requirements and format for such filing. The index of customers must also posted on the pipeline's Internet web, in accordance with standards adopted in § 284.12 of this part, and made available from the Internet web site in a downloadable format complying with the specifications established by the Commission. The information posted on the pipeline's Internet web site must be made available until the next quarterly index is posted.

(2) For each shipper receiving firm transportation or storage service, the index must include the following information:

(i) The full legal name, and identification number, of the shipper;

(ii) The applicable rate schedule number under which the service is being provided;

(iii) The contract number;

(iv) The effective and expiration dates of the contract;

(v) For transportation service, the maximum daily contract quantity (specify unit of measurement), and for storage service, the maximum storage quantity (specify unit of measurement);

(vi) The receipt and delivery points and the zones or segments covered by the contract, including the location name and code adopted by the pipeline in conformance with paragraph (f) of this section for each point, zone or segment;

(vii) An indication as to whether the contract includes negotiated rates;

(viii) The name of any agent or asset manager managing a shipper's transportation service; and

(ix) Any affiliate relationship between the pipeline and a shipper or between the pipeline and a shipper's asset manager or agent.

(3) The requirements of this section do not apply to contracts which relate solely to the release of capacity under § 284.8, unless the release is permanent.

(4) Pipelines that are not required to comply with the index of customers posting and filing requirements of this section must comply with the index of customer requirements applicable to transportation and sales under Part 157 as set forth under § 154.111(b) and (c) of this chapter.

(5) The requirements for the electronic index are available through the Commission's website, https://www.ferc.gov.

(d) Capacity and flow information. (1) An interstate pipeline must provide on its Internet web site and in downloadable file formats, in conformity with § 284.12 of this part, equal and timely access to information relevant to the availability of all transportation services whenever capacity is scheduled, including, but not limited to, the availability of capacity at receipt points, on the mainline, at delivery points, and in storage fields, whether the capacity is available directly from the pipeline or through capacity release, the total design capacity of each point or segment on the system, the amount scheduled at each point or segment whenever capacity is scheduled, and all planned and actual service outages or reductions in service capacity. An interstate pipeline must also provide information about the volumes of no-notice transportation provided pursuant to § 284.7(a)(4). This information must be posted at each receipt and delivery point before 11:30 a.m. central clock time three days after the day of gas flow and must reflect the pipeline's best estimate. Updated information must be posted at each receipt and delivery point as necessary within ten business days after the month of gas flow.

(2) An interstate pipeline must make an annual filing by March 1 of each year showing the estimated peak day capacity of the pipeline's system, and the estimated storage capacity and maximum daily delivery capability of storage facilities under reasonably representative operating assumptions and the respective assignments of that capacity to the various firm services provided by the pipeline.

(e) Notice of bypass. An interstate pipeline that provides transportation (except storage) to a customer that is located in the service area of a local distribution company and will not be delivering the customer's gas to that local distribution company, must file with the Commission, within thirty days after commencing such transportation, a statement that the interstate pipeline has notified the local distribution company and the local distribution company's appropriate regulatory agency in writing of the proposed transportation prior to commencement.

(f) Location codes. An interstate pipeline must maintain a posting on its publicly available Internet Web site of the pipeline's location names and codes for all current and inactive receipt and delivery points on its system, including, for each point: Direction of flow, the location of the point, the location zone if such exists, the Commission company identification code (CID), if any, of the upstream and/or downstream entity, the location type, the current status as active and inactive, and the date(s) the point becomes active or inactive. The pipeline must provide the information in downloadable file formats, in conformity with the requirements of 18 CFR 284.12 of this chapter.

[Order 637, 65 FR 10221, Feb. 25, 2000, as amended by Order 637-A, 65 FR 35765, June 5, 2000; Order 2004, 68 FR 69157, Dec. 11, 2003; Order 712, 73 FR 37092, June 30, 2008; Order 720, 73 FR 73517, Dec. 2, 2008; Order 720-B, 75 FR 44900, July 30, 2010; Order 757, 77 FR 4224, Jan. 27, 2012; Order 587-W, 80 FR 67312, Nov. 2, 2015; Order 587-X, 81 FR 15432, Mar. 23, 2016; Order 899, 88 FR 74031, Oct. 30, 2023]

§ 284.14 Posting requirements of major non-interstate pipelines.

(a) Daily posting requirement. A major non-interstate pipeline must post on a daily basis on a publicly-accessible Internet Web site and in downloadable file format equal and timely access to information regarding receipt or delivery points, including non-physical scheduling points.

(1) A major non-interstate pipeline must post data for each receipt or delivery point, or for any point that operates as both a delivery and receipt point for the major non-interstate pipeline, to which natural gas transportation is scheduled:

(i) With a physically metered design capacity equal to or greater than 15,000 MMBtu (million British thermal units)/day; or

(ii) If a physically metered design capacity is not known or does not exist for such a point, with a maximum volume scheduled to such a point equal to or greater than 15,000 MMBtu on any day within the prior three calendar years.

(2) Notwithstanding the requirements of subsection 284.14(a)(1), a receipt point is not subject to the posting requirements of this section if the maximum scheduled volume at the receipt point was less than 5,000 MMBtu on every day within the prior three calendar years. If a point has operated as both a receipt and delivery point any time within the prior three calendar years, subsection 284.14(a)(2) shall not apply to that point.

(3) A major non-interstate pipeline that must post data for a receipt or delivery point shall do so within 45 days of the date that the point becomes eligible for posting.

(4) For each delivery or receipt point that must be posted, a major non-interstate pipeline must provide the following information by 10:00 p.m. central clock time the day prior to scheduled natural gas flow: Transportation Service Provider Name, Posting Date, Posting Time, Nomination Cycle, Location Name, Additional Location Information if Needed to Distinguish Between Points, Location Purpose Description (Receipt, Delivery, Bilateral, or Non-physical Scheduling Point), Posted Capacity (physically metered design capacity or maximum flow within the last three years), Method of Determining Posted Capacity (Capacity or Maximum Volume), Scheduled Volume, Available Capacity (Calculated as Posted Capacity minus Scheduled Capacity), and Measurement Unit (Dth, MMBtu, or MCf). For receipt or delivery points with bi-directional scheduled flows, the Scheduled Volume for scheduled flow in each direction must be posted. The information in this subsection must remain posted for at least a period of one year.

(5) Newly constructed major non-interstate pipelines, which commence service after the effective date of this section, must comply with the requirements of this section upon their in-service date. Except for newly constructed major non-interstate pipelines, a major non-interstate pipeline that becomes subject to the requirements of this section in any year after the effective date of this section has until June 1 of that year to comply with the requirements of this section.

(b) Exemptions to daily posting requirement. The following categories of major non-interstate pipelines are exempt from the posting requirement of § 284.14(a):

(1) Those that are located upstream of a processing, treatment or dehydration plant;

(2) Those that deliver more than ninety-five percent (95%) of the natural gas volumes they flow directly to end-users or on-system storage as measured in average deliveries for the previous three calendar years;

(3) Storage providers;

(4) Those that deliver the entirety of their transported natural gas directly to an end-user that owns or operates the major non-interstate pipeline.

[Order 720-A, 75 FR 5201, Feb. 1, 2010, as amended by Order 720-B, 75 FR 44900, July 30, 2010]

§ 284.15 Bidding by affiliates in open seasons for pipeline capacity.

(a) Multiple affiliates of the same entity may not participate in an open season for pipeline capacity conducted by any interstate pipeline providing service under subparts B and G of this part, in which the pipeline may allocate capacity on a pro rata basis, unless each affiliate has an independent business reason for submitting a bid.

(b) For purposes of this section, an affiliate is any person that satisfies the definition of affiliate in § 358.3(a)(1) and (3) of this chapter with respect to another entity participating in an open season subject to paragraph (a) of this section.

[Order 894, 76 FR 72306, Nov. 23, 2011]

§ 284.101 Applicability.

This subpart implements section 311(a)(1) of the NGPA and applies to the transportation of natural gas by any interstate pipeline on behalf of:

(a) Any intrastate pipeline; or

(b) Any local distribution company.

§ 284.102 Transportation by interstate pipelines.

(a) Subject to paragraphs (d) and (e) of this section, other provisions of this subpart, and the conditions of subpart A of this part, any interstate pipeline is authorized without prior Commission approval, to transport natural gas on behalf of:

(1) Any intrastate pipeline; or

(2) Any local distribution company.

(b) Any rates charged for transportation under this subpart may not exceed the just and reasonable rates established under subpart A of this part.

(c) An interstate pipeline that engages in transportation arrangements under this subpart must file reports in accordance with § 284.13 of this chapter.

(d) Transportation of natural gas is not on behalf of an intrastate pipeline or local distribution company or authorized under this section unless:

(1) The intrastate pipeline or local distribution company has physical custody of and transports the natural gas at some point; or

(2) The intrastate pipeline or local distribution company holds title to the natural gas at some point, which may occur prior to, during, or after the time that the gas is being transported by the interstate pipeline, for a purpose related to its status and functions as an intrastate pipeline or its status and functions as a local distribution company; or

(3) The gas is delivered at some point to a customer that either is located in a local distribution company's service area or is physically able to receive direct deliveries of gas from an intrastate pipeline, and that local distribution company or intrastate pipeline certifies that it is on its behalf that the interstate pipeline is providing transportation service.

(e) An interstate pipeline must obtain from its shippers certifications including sufficient information to verify that their services qualify under this section. Prior to commencing transportation service described in paragraph (d)(3) of this section, an interstate pipeline must receive the certification required from a local distribution company or an intrastate pipeline pursuant to paragraph (d)(3) of this section.

[Order 436, 50 FR 42495, Oct. 18, 1985, as amended by Order 526, 55 FR 33011, Aug. 13, 1990; Order 537, 56 FR 50245, Oct. 4, 1991; Order 581, 60 FR 53072, Oct. 11, 1995; Order 637, 65 FR 10222, Feb. 25, 2000; Order 756, 77 FR 4894, Feb. 1, 2012]

§§ 284.103-284.106 [Reserved]

§ 284.121 Applicability.

This subpart implements section 311(a)(2) of the NGPA and applies to the transportation of natural gas by any intrastate pipeline on behalf of:

(a) Any interstate pipeline, or

(b) Any local distribution company served by any interstate pipeline.

§ 284.122 Transportation by intrastate pipelines.

(a) Subject to paragraph (d) of this section, other provisions of this subpart, and the applicable conditions of Subpart A of this part, any intrastate pipeline may, without prior Commission approval, transport natural gas on behalf of:

(1) Any interstate pipeline; or

(2) Any local distribution company served by an interstate pipeline.

(b) No rate charged for transportation authorized under this subpart may exceed a fair and equitable rate under § 284.123.

(c) Any intrastate pipeline engaged in transportation arrangements authorized under this section must file reports as required by § 284.126.

(d) Transportation of natural gas is not on behalf of an interstate pipeline or local distribution company served by an interstate pipeline or authorized under this section unless:

(1) The interstate pipeline or local distribution company has physical custody of and transports the natural gas at some point; or

(2) The interstate pipeline or local distribution company holds title to the natural gas at some point, which may occur prior to, during, or after the time that the gas is being transported by the intrastate pipeline, for a purpose related to its status and functions as an interstate pipeline or its status and functions as a local distribution company.

[Order 436, 50 FR 42495, Oct. 18, 1985, as amended by Order 537, 56 FR 50245, Oct. 4, 1991; Order 537-A, 57 FR 46501, Oct. 9, 1992; Order 581, 60 FR 53073, Oct. 11, 1995; Order 756, 77 FR 4894, Feb. 1, 2012]

§ 284.123 Rates and charges.

(a) General rule. Rates and charges for transportation of natural gas authorized under § 284.122(a) shall be fair and equitable as determined in accordance with paragraph (b) of this section.

(b) Election of rates. (1) Subject to the conditions in §§ 284.7 and 284.9 of this chapter, an intrastate pipeline may elect to:

(i) Base its rates upon the methodology used:

(A) In designing rates to recover the cost of gathering, treatment, processing, transportation, delivery or similar service (including storage service) included in one of its then effective firm sales rate schedules for city-gate service on file with the appropriate state regulatory agency; or

(B) In determining the allowance permitted by the appropriate state regulatory agency to be included in a natural gas distributor's rates for city-gate natural gas service; or

(ii) To use the rates contained in one of its then effective transportation rate schedules for intrastate service on file with the appropriate state regulatory agency which the intrastate pipeline determines covers service comparable to service under this subpart.

(2)(i) If an intrastate pipeline does not choose to make any election under paragraph (b)(1) of this section, it shall apply for Commission approval, by order, of the proposed rates and charges by filing with the Commission the proposed rates and charges, and information showing the proposed rates and charges are fair and equitable. Each petition for approval filed under this paragraph must be accompanied by the fee set forth in § 381.403 or by a petition for waiver pursuant to § 384.106 of this chapter. Upon filing the petition for approval, the intrastate pipeline may commence the transportation service and charge and collect the proposed rate, subject to refund.

(ii) 150 days after the date on which the Commission received an application filed pursuant to paragraph (b)(2)(i) of this section, the rate proposed in the application will be deemed to be fair and equitable and not in excess of an amount which interstate pipelines would be permitted to charge for providing similar transportation service, unless within the 150 day period, the Commission either extends the time for action, or institutes a proceeding in which all interested parties will be afforded an opportunity for written comments and for the oral presentation of views, data and arguments. In such proceeding, the Commission either will approve the rate or disapprove the rate and order refund, with interest, of any amount which has been determined to be in excess of those shown to be fair and equitable or in excess of the rates and charges which interstate pipelines would be permitted to charge for providing similar transportation service.

(iii) A Commission order approving or disapproving a transportation rate under this paragraph supersedes a rate determined in accordance with paragraph (b)(1) of this section.

(c) Treatment of revenues. The Commission presumes that all revenues received by an intrastate pipeline in connection with transportation authorized under § 284.122(a) and computed in accordance with paragraph (b)(1) of this section have been or will be taken into account by the appropriate state regulatory agency for purposes of establishing transportation charges by the intrastate pipeline for service to intrastate customers.

(d) Presumptions. If the intrastate pipeline is charging a rate computed pursuant to § 284.123(b)(1), the rate charged is presumed to be:

(1) Fair and equitable; and

(2) Not in excess of the rates and charges which interstate pipelines would be permitted to charge for providing similar transportation service.

(e) Filing requirements. Within 30 days of commencement of new service, any intrastate pipeline that engages in transportation arrangements under this subpart must file with the Commission a statement that includes the pipeline's interstate rates, the rate election made pursuant to paragraph (b) of this section, and a description of how the pipeline will engage in these transportation arrangements, including operating conditions, such as quality standards and financial viability of the shipper. If the pipeline changes its operations, rates, or rate election under this subpart, it must amend the statement and file such amendments not later than 30 days after commencement of the change in operations or the change in rate election.

(f) Electronic filing of statements, and related materials—(1) General rule. All filings made in proceedings initiated under this part must be made electronically, including rates and charges, or parts thereof, and material related thereto, statements, and all workpapers.

(2) Requirements for signature. All filings must be signed in compliance with the following:

(i) The signature on a filing constitutes a certification that the contents are true to the best knowledge and belief of the signer, and that the signer possesses full power and authority to sign the filing.

(ii) A filing must be signed by one of the following:

(A) The person on behalf of whom the filing is made;

(B) An officer, agent, or employee of the company, governmental authority, agency, or instrumentality on behalf of which the filing is made; or,

(C) A representative qualified to practice before the Commission under § 385.2101 of this chapter who possesses authority to sign.

(iii) All signatures on the filing or any document included in the filing must comply, where applicable, with the requirements in § 385.2005 of this chapter with respect to sworn declarations or statements and electronic signatures.

(3) Format requirements for electronic filing. The requirements and formats for electronic filing are listed in instructions for electronic filing and for each form. These formats are available through the Commission's website, https://www.ferc.gov.

(g) Election of Notice Procedures—(1) Applicability. An intrastate pipeline filing for approval of rates, a statement of operating conditions, and any amendments or modifications thereto pursuant to this section may use the notice procedures in this paragraph. Any intrastate pipeline electing to use these notice procedures for a filing must clearly state its election to use these procedures in the filing. Such filing is approved and the rates deemed fair and equitable and not in excess of the amount that an interstate pipeline would be permitted to charge for similar transportation service if the requirements in paragraph (g)(8) of this section have been fulfilled.

(2) Rejection of filing. The Director of the Office of Energy Market Regulation or his designee shall reject within 7 days of the date of filing a request which patently fails to comply with the provisions of paragraph (e) or (f) of this section, without prejudice to the intrastate pipeline refiling a complete application. If such filing was required by this section, that filing must be refiled within 14 days of the date of the rejection.

(3) Publication of notice of filing. The Secretary of the Commission shall issue a notice of the filing within 10 days of the date of the filing, which will then be published in the Federal Register. The notice shall designate a deadline for filing interventions, initial comments, final comments, and protests to the filing. The deadline for interventions and initial comments shall be 21 days after the date of the filing or such other date established by the Secretary of the Commission. The deadline for final comments and protests shall be 60 days after the date of the filing or such other date established by the Secretary of the Commission.

(4) Protests. (i) Any person or the Commission's staff may file a protest prior to the deadline for protests.

(ii) Protests shall be filed with the Commission in the form required by Part 385 of this chapter including a detailed statement of the protestor's interest in the filing and the specific reasons and rationale for the objection and whether the protestor seeks to be an intervenor.

(5) Effect of protest. If a protest is filed in accordance with paragraph (g)(4) of this section, then the intrastate pipeline, the person who filed the protest, any intervenors and Commission staff shall have 30 days from the deadline for filing protests established by the Secretary of the Commission in accordance with paragraph (g)(3) of this section, to resolve the protest, and to file a withdrawal of the protest pursuant to paragraph (g)(6) of this section. Informal settlement conferences may be convened by the Director of the Office of Energy Market Regulation or his designee during this 30 day period. If a protest is not withdrawn or dismissed by end of that 30 day period, the filing shall not be deemed approved pursuant to this paragraph. Within 60 days from the deadline for filing protests established by the Secretary of the Commission in accordance with paragraph (g)(3) of this section the Commission will establish procedures to resolve the proceeding.

(6) Withdrawal of protests. The protestor may withdraw a protest by submitting written notice of withdrawal to the Secretary of the Commission pursuant to § 385.216 of this chapter and serving a copy on the intrastate pipeline, any intervenors, and any person who has filed a motion to intervene in the proceeding.

(7) Amendments or modifications to tariff records prior to approval. An intrastate pipeline may file to amend or modify a tariff record contained in the initial filing pursuant to the procedures under this paragraph (g) which has not yet been approved pursuant to paragraph (g)(8) of this section. Such filing will toll the notice period established in paragraph (g)(3) of this section and the Secretary of the Commission will issue a notice establishing new deadlines for comments and protests for the entire filing pursuant to paragraph (g)(3).

(8) Final approval. (i) If no protest is filed within the time allowed by the Secretary of the Commission under paragraph (g)(3) of this section, the filing by the intrastate pipeline is approved, effective on the date proposed in the filing requesting approval unless the intrastate pipeline withdraws, amends, or modifies its filing or the filing is rejected pursuant to paragraph (g)(2) of this section.

(ii) If any protest is filed within the time allowed by the Secretary of the Commission under paragraph (g)(3) of this section and is subsequently withdrawn before the end of the 30-day reconciliation period provided by paragraph (g)(5) of this section, the filing by the intrastate pipeline is approved effective on the date proposed in the filing requesting approval unless the intrastate pipeline withdraws, amends, or modifies its filing or the filing is rejected pursuant to paragraph (g)(2) of this section.

(9) Periodic rate review. Rates of pipelines approved by the Commission pursuant to this paragraph are required to be periodically reviewed.

(i) Any intrastate pipeline with rates so approved must file an application for rate approval under this section on or before the date five years following the date it filed the application for authorization of rates pursuant to this paragraph. Any Hinshaw pipeline that has been a granted a blanket certificate under § 284.224 of this chapter and with rates approved pursuant to this paragraph must on or before the date five years following the date it filed the application for authorization of the rates pursuant to this paragraph either file under this section cost, throughput, revenue and other data, in the form specified in § 154.313 of this chapter, to allow the Commission to determine whether any change in rates is required pursuant to section 5 of the Natural Gas Act or an application for rate authorization pursuant to this section.

(ii) An intrastate pipeline with rates approved pursuant to the rate election in paragraph (b)(1) of this section that remain unchanged during the five-year review period which were approved based on then effective state rates may file a certification with the Commission pursuant to this paragraph (g) that the rates continue to comply on the same basis with the requirements set forth in paragraph (b)(1) of this section. Such certification of rates will meet the periodic rate review requirement set forth in this paragraph (g)(9) unless the Commission determines that further proceedings concerning the rates are appropriate.

(iii) If the state rate used pursuant to paragraph (b)(1) of this section for approval of a rate pursuant to this paragraph (g) is changed, not later than 30 days after that changed rate becomes effective, the intrastate pipeline must file a new rate election pursuant to paragraph (b) of this section.

(10) Withdrawal of filing prior to approval. A pipeline may, pursuant to paragraph (h) of this section, withdraw in its entirety a filing made pursuant to paragraph (g) that has not been approved by filing a withdrawal motion with the Commission. A filing that is withdrawn will not fulfill the requirements under paragraph (g)(8) of this section.

(h) Withdrawal of filing. A pipeline may withdraw in its entirety a filing pursuant to this section that has not been approved by filing a withdrawal motion with the Commission.

(1) The withdrawal motion must state that any amounts collected subject to refund in excess of the rates authorized the Commission will be refunded with interest calculated and a refund report filed with the Commission in accordance with § 154.501 of this chapter. The refunds must be made within 60 days of the date the withdrawal motion becomes effective.

(2) The withdrawal motion will become effective, and the filing will be deemed withdrawn at the end of 15 days from the date of filing of the withdrawal motion, if no order disallowing the motion is issued within that period. If an answer in opposition is filed within the 15-day period, the withdrawal is not effective until an order accepting the withdrawal is issued.

[44 FR 52184, Sept. 7, 1979, as amended at 44 FR 66791, Nov. 21, 1979; Order 394, 49 FR 35364, Sept. 7, 1984; Order 436, 50 FR 42496, Oct. 18, 1985; 50 FR 52276, Dec. 23, 1985; Order 581, 60 FR 53073, Oct. 11, 1995; Order 714, 73 FR 57535, Oct. 3, 2008; Order 781, 78 FR 45862, July 30, 2013; Order 849, 83 FR 36715, July 30, 2018; Order 849-B, 86 FR 29506, June 2, 2021; Order 899, 88 FR 74031, Oct. 30, 2023]

§ 284.124 Terms and conditions.

Contracts for the transportation of natural gas authorized under this subpart shall provide that the transportation arrangement is subject to the provisions of this subpart.

§ 284.125 [Reserved]

§ 284.126 Reporting requirements.

(a) Notice of bypass. An intrastate pipeline that provides transportation (except storage) under § 284.122 to a customer that is located in the service area of a local distribution company and will not be delivering the customer's gas to that local distribution company, must file with the Commission within thirty days after commencing such transportation, a statement that the interstate pipeline has notified the local distribution and the local distribution company's appropriate state regulatory agency in writing of the proposed transportation prior to commencement.

(b) Form No. 549D, Quarterly Transportation and Storage Report of Intrastate Natural Gas and Hinshaw Pipelines.

(1) Each intrastate pipeline must use Form No. 549D to file a quarterly report with the Commission and the appropriate state regulatory agency that contains, for each transportation and storage service provided during the preceding calendar quarter under § 284.122, the following information on each transaction, aggregated by contract:

(i) The full legal name, and identification number, of the shipper receiving the service, including whether there is an affiliate relationship between the pipeline and the shipper;

(ii) The type of service performed (i.e., firm or interruptible transportation, storage, or other service);

(iii) The rate charged under each contract, specifying the rate schedule/name of service and docket where the rates were approved. The report should separately state each rate component set forth in the contract (i.e., reservation, usage, and any other charges);

(iv) The primary receipt and delivery points covered by the contract, identified by the list of points that the pipeline has published with the Commission;

(v) The quantity of natural gas the shipper is entitled to transport, store, or deliver under each contract;

(vi) The duration of the contract, specifying the beginning and (for firm contracts only) ending month and year of the current agreement;

(vii) Total volumes transported, stored, injected or withdrawn for the shipper; and

(viii) Annual revenues received for each shipper, excluding revenues from storage services. The report should separately state revenues received under each component, and need only be reported every fourth quarter.

(2) The quarterly Form No. 549D report for the period January 1 through March 31 must be filed on or before June 1. The quarterly report for the period April 1 through June 30 must be filed on or before September 1. The quarterly report for the period July 1 through September 30 must be filed on or before December 1. The quarterly report for the period October 1 through December 31 must be filed on or before March 1.

(3) Each Form No. 549D report must be filed as prescribed in § 385.2011 of this chapter as indicated in the General Instructions and Data Dictionary set out in the quarterly reporting form. Each report must be prepared and filed in conformance with the Commission's software or XML Schema, eTariff filing structure, and reporting guidance, so as to be posted and available for downloading from the FERC Web site (http://www.ferc.gov). One copy of the report must be retained by the respondent in its files.

(4) Intrastate pipelines filing Form No. 549D are no longer required to file Form No. 549—Intrastate Pipeline Annual Transportation Report after their March 31, 2011 filing.

[Order 436, 50 FR 42496, Oct. 18, 1985, as amended at 50 FR 52276, Dec. 23, 1985; Order 636, 57 FR 13317, Apr. 16, 1992; Order 581, 60 FR 53073, Oct. 11, 1995; 71 FR 38066, July 5, 2006; 75 FR 29419, May 26, 2010; 75 FR 80697, Dec. 23, 2010; Order 757, 77 FR 4224, Jan. 27, 2012; Order 587-W, 80 FR 67312, Nov. 2, 2015]

§ 284.141 Applicability.

This subpart implements section 311(b) of the NGPA and applies to certain sales of natural gas by intrastate pipelines to:

(a) Interstate pipelines; and

(b) Local distribution companies served by interstate pipelines.

§ 284.142 Sales by intrastate pipelines.

Any intrastate pipeline may, without prior Commission approval, sell natural gas to any interstate pipeline or any local distribution company served by an interstate pipeline. The rates charged by an intrastate pipeline pursuant to this subpart may not exceed the price for gas as negotiated in the contract, plus a fair and equitable transportation rate as determined in accordance with § 284.123.

[Order 581, 60 FR 53073, Oct. 11, 1995]

§§ 284.143-284.148 [Reserved]

§ 284.221 General rule; transportation by interstate pipelines on behalf of others.

(a) Blanket certificate. Any interstate pipeline may apply under this section for a single blanket certificate authorizing the transportation of natural gas on behalf of others in accordance with this subpart. A certificate of public convenience and necessity under this section is granted pursuant to section 7 of the Natural Gas Act.

(b) Application procedure. (1) An application for a blanket certificate under this section must be filed electronically. The format for the electronic application filing available through the Commission's website, https://www.ferc.gov, and must include:

(i) The name of the interstate pipeline; and

(ii) A statement by the interstate pipeline that it will comply with the conditions in paragraph (c) of this section.

(2) Upon receipt of an application under this section, the Commission will conduct a hearing pursuant to section 7(c) of the Natural Gas Act and § 157.11 of this chapter and, if required by the public convenience and necessity, will issue to the interstate pipeline a blanket certificate authorizing such pipeline company to transport natural gas, as provided under this subpart.

(c) General conditions. Any blanket certificate under this subpart is subject to the conditions of subpart A of this part.

(d) Pre-grant of abandonment. (1) Except as provided in paragraph (d)(2) of this section, abandonment of transportation services is authorized pursuant to section 7(b) of the Natural Gas Act upon the expiration of the contractual term or upon termination of each individual transportation arrangement authorized under a certificate granted under this section.

(2) Paragraph (d)(1) of this section does not apply if the individual transportation arrangement is for firm transportation under a contract with a term of one year or more, and the firm shipper:

(i) Exercises any contractual right to continue such service; or

(ii) Gives notice that it wants to continue its transportation arrangement and will match the longest term and highest rate for its firm service, up to the applicable maximum rate under § 284.10, offered to the pipeline during the period established in the pipeline's tariff for receiving such offers by any other person desiring firm capacity, and executes a contract matching the terms of any such offer. To be eligible to exercise this right of first refusal, the firm shipper's contract must be for service for twelve consecutive months or more at the applicable maximum rate for that service, except that a contract for more than one year, for a service which is not available for 12 consecutive months, would be subject to the right of first refusal.

(e) Availability of regular certificates. This subpart does not preclude an interstate pipeline from applying for an individual certificate of public convenience and necessity for any particular transportation service.

(f) Cross references. (1) Any local distribution company served by an interstate pipeline may apply for a blanket certificate to perform certain services under § 284.224 of this chapter.

(2) Any interstate pipeline may apply under subpart F of part 157 of this chapter for a blanket certificate to construct or acquire and operate certain natural gas facilities that are necessary to provide transportation under § 284.223.

(3) Section 157.208 of this chapter provides automatic authorization for the construction, acquisition, operation, replacement, and miscellaneous rearrangement of certain eligible facilities, as defined in § 157.202 of this chapter, subject to limits specified in § 157.208(d) of this chapter and § 284.11.

(4) Authorization for delivery points is subject to the automatic authorization under § 157.211(a)(1) and the prior notice procedures under § 157.211(a)(2) and § 157.205.

(g) Flexible receipt point authority. (1) An interstate pipeline authorized to transport gas under a certificate granted under this section may, at the request of the shipper and without prior notice:

(i) Reduce or discontinue receipts of natural gas at a particular receipt point from a supplier; and

(ii) Commence or increase receipts at a particular receipt point from that supplier or any other supplier.

(2) The total natural gas volumes received by the interstate pipeline following any such reassignment under this paragraph must not exceed the total volume of natural gas that the interstate pipeline may transport on behalf of the shipper under a certificate granted under this section.

(3) The receipt points to which natural gas volumes may be reassigned under this paragraph include eligible facilities under § 157.208 which are authorized to be constructed and operated pursuant to a certificate issued under subpart F of part 157 of this chapter.

(h) Flexible delivery point authority. (1) An interstate pipeline authorized to transport gas under a certificate issued pursuant to this section may at the request of the shipper and without prior notice:

(i) Reduce or discontinue deliveries of natural gas to a particular delivery point; and

(ii) Commence or increase deliveries at a particular delivery point.

(2) The total natural gas volumes delivered by the interstate pipeline following any such reassignment must not exceed the total amount of natural gas that the interstate pipeline is authorized under a certificate issued pursuant to this section to transport on behalf of the shipper.

(3) The delivery points to which natural gas volumes may be reassigned under this paragraph include facilities authorized to be constructed and operated only under § 157.211 and the prior notice conditions of § 157.205 of this chapter.

[Order 436, 50 FR 42496, Oct. 18, 1985, as amended by Order 433-A, 51 FR 43607, Dec. 3, 1986; Order 636, 57 FR 13317, Apr. 16, 1992; Order 636-A, 57 FR 36217, Aug. 12, 1992; Order 581, 60 FR 53073, Oct. 11, 1995; Order 603, 64 FR 26610, May 14, 1999; Order 637, 65 FR 10222, Feb. 25, 2000; Order 637-A, 65 FR 35765, June 5, 2000; Order 899, 88 FR 74031, Oct. 30, 2023]

§ 284.222 [Reserved]

§ 284.223 Transportation by interstate pipelines on behalf of shippers.

Subject to the provisions of this subpart and the conditions of Subpart A of this part, any interstate pipeline issued a certificate under § 284.221 is authorized, without prior notice to or approval by the Commission, to transport natural gas for any duration for any shipper for any end-use by that shipper or any other person.

[Order 436, 50 FR 42497, Oct. 18, 1985; 50 FR 45908, Nov. 5, 1985, as amended at 50 FR 52276, Dec. 23, 1985; Order 537, 56 FR 50245, Oct. 4, 1991; Order 581, 60 FR 53074, Oct. 11, 1995; Order 637, 65 FR 10222, Feb. 25, 2000]

§ 284.224 Certain transportation and sales by local distribution companies.

(a) Applicability. This section applies to local distribution companies served by interstate pipelines, including persons who are not subject to the jurisdiction of the Commission, by reason of section 1(c) of the Natural Gas Act.

(b) Blanket certificate—(1) Any local distribution company served by an interstate pipeline or any Hinshaw pipeline may apply for a blanket certificate under this section.

(2) Upon application for a certificate under this section, a hearing will be conducted under section 7(c) of the Natural Gas Act, § 157.11 of this chapter, and subpart H of part 385 of this chapter.

(3) The Commission will grant a blanket certificate to such local distribution company or Hinshaw pipeline under this section, if required by the present or future public convenience and necessity. Such certificate will authorize the local distribution company to engage in the sale or transportation of natural gas that is subject to the Commission's jurisdiction under the Natural Gas Act, to the same extent that and in the same manner that intrastate pipelines are authorized to engage in such activities by subparts C and D of this part, except as otherwise provided in paragraph (e)(2) of this section.

(c) Application procedure. Applications for blanket certificates must be accompanied by the fee prescribed in § 381.207 of this chapter or a petition for waiver pursuant to § 381.106 of this chapter, and shall state:

(1) The exact legal name of applicant; its principal place of business; whether an individual, partnership, corporation or otherwise; the state under the laws of which it is organized or authorized; the agency having jurisdiction over rates and tariffs; and the name, title, and mailing address of the person or persons to whom communications concerning the application are to be addressed;

(2) The volumes of natural gas which:

(i) Were received during the most recent 12-month period by the applicant within or at the boundary of a state, and

(ii) Were exempt from the Natural Gas Act jurisdiction of the Commission by reason of section 1(c) of the Natural Gas Act, if any;

(3) The total volume of natural gas received by the applicant from all sources during the same time period;

(4) Citation to all currently valid declarations of exemption issued by the Commission under section 1(c) of the Natural Gas Act if any;

(5) A statement that the applicant will comply with the conditions in paragraph (e) of this section;

(6) A form of notice suitable for publication in the Federal Register, as contemplated by § 157.9 of this chapter, which will briefly summarize the facts contained in the application in such way as to acquaint the public with its scope and purpose; and

(7) A statement of the methodology to be used in calculating rates for services to be rendered, setting forth any elections under § 284.123 or paragraph (e)(2) of this section and a sample calculation employing the methodology using current data. If a rate election is made under paragraph (e)(2) of this section, this statement shall contain the following items (reflecting the 12-month period used to justify costs in the most recently approved rate case conducted by an appropriate state regulatory agency):

(i) Total operating revenues,

(ii) Purchase gas costs,

(iii) Distribution costs (which include that portion of the common costs allocated to the distribution function),

(iv) The volume throughput of the system categorized by sales, transportation and exchange service, and

(v) A study which determines transportation costs on a unit revenue basis in accordance with paragraph (e)(2) of this section, including any supporting work papers.

(d) Effect of certificate. (1) Any certificate granted under this section will authorize the certificate holder to engage in transactions of the type authorized by subparts C and D of this part.

(2) Acceptance of a certificate or conduct of an activity authorized thereunder will:

(i) Not impair the continued validity of any exclusion under section 1(c) of the Natural Gas Act which may be applicable to the certificate holder, and

(ii) Not subject the certificate holder to the Natural Gas Act jurisdiction to the Commission except to the extent necessary to enforce the terms and conditions of the certificate.

(e) General conditions. (1) Except as provided in paragraph (e)(2) of this section, any transaction authorized under a blanket certificate is subject to the same rates and charges, terms and conditions, and reporting requirements that apply to a transaction authorized for an intrastate pipeline under subparts C and D of this part.

(2) Rate election. If the certificate holder does not have any existing rates on file with the appropriate state regulatory agency for city-gate service, the certificate holder may make the rate election specified in § 284.123(b)(1) only if:

(i) The certificate holder's existing rates are approved by an appropriate state regulatory agency,

(ii) The rates and charges for any transportation are computed by using the portion of the certificate holder weighted average annual unit revenue (per MMBtu) generated by existing rates which is attributable to the cost of gathering, treatment, processing, transportation, delivery or similar service (including storage service), and

(iii) The Commission has approved the method for computing rates and charges specified in paragraph (e)(2)(ii) of this section.

(3) Volumetric test. The volumes of natural gas sold or assigned under the blanket certificate may not exceed the volumes obtained from sources other than interstate supplies.

(4) Filings. Any filings made with the Commission that report individual transactions shall reference the docket number of the proceeding in which the blanket certificate was granted.

(5) Filing Requirements. Filings under this section must comply with the requirements of § 284.123 (f) of this part. The tariff filing requirements of Part 154 of this chapter shall not apply to transactions authorized by the blanket certificate.

(f) Pregrant of abandonment. Abandonment of transportation services or sales, pursuant to section 7(b) of the Natural Gas Act, is authorized upon the expiration of the contractual term of each individual arrangement authorized by a blanket certificate under this section.

(g) Hinshaw pipeline without blanket certificate. A Hinshaw pipeline that does not obtain a blanket certificate under this section is not authorized to sell or transport natural gas as an intrastate pipeline under subparts C and D of this part.

(h) Definitions. For the purposes of this section:

(1) A Hinshaw pipeline means any person engaged in the transportation of natural gas which is not subject to the jurisdiction of the Commission under the Natural Gas Act solely by reason of section 1(c) of the Natural Gas Act.

(2) Interstate supplies means any natural gas obtained, either directly or indirectly, from:

(i) The system supplies of an interstate pipeline, or

(ii) Natural gas reserves which were committed or dedicated to interstate commerce on November 8, 1978.

[45 FR 1875, Jan. 9, 1980, as amended by Order 319, 48 FR 34891, Aug. 1, 1983; 48 FR 35635, Aug. 5, 1983; Order 433, 50 FR 40346, Oct. 3, 1985. Redesignated and amended by Order 436, 50 FR 42497, 42498, Oct. 18, 1985; Order 478, 52 FR 28467, July 30, 1987; Order 581, 60 FR 53074, Oct. 11, 1995; Order 714, 73 FR 57535, Oct. 3, 2008]

§§ 284.225-284.226 [Reserved]

§ 284.227 Certain transportation by intrastate pipelines.

(a) Blanket certificate. A blanket certificate shall issue under this section to any intrastate pipeline that receives natural gas produced in adjacent Federal waters or onshore or offshore in an adjacent state, provided that:

(1) The gas must be received by the intrastate pipeline from a gatherer or other intrastate pipeline;

(2) The intrastate pipeline delivers the gas in the intrastate pipeline's state of operation to an end user or another intrastate pipeline; and

(3) The gas ultimately used by an end user in the same state.

(b) Effective date. If an intrastate pipeline is providing a transportation service described in paragraph (a) of this section as of February 1, 1992, and the service is not a qualifying service under § 284.122 of subpart C of this part, a blanket certificate shall issue under paragraph (a) of this section and become effective as of February 1, 1992. If an intrastate pipeline is not providing a transportation service described in paragraph (a) of this section as of February 1, 1992 the blanket certificate shall issue and become effective on the date that the intrastate pipeline commences such a service that is not a qualifying service under § 284.122 of subpart C of this part.

(c) Acceptance of certificate. An intrastate pipeline shall be deemed to have accepted a blanket certificate under this section if it continues after February 1, 1992, a service described in paragraph (a) of this section that is not a qualifying service under § 284.122 of subpart C or commences such a service after November 4, 1991.

(d) Terms and conditions. An intrastate pipeline's blanket certificate transportation authority under this section is subject to its compliance with all terms and conditions of subpart C of this part, except that service under this section does not have to be on behalf of an interstate pipeline or local distribution company served by an interstate pipeline.

(e) Pregrant of abandonment. Abandonment of transportation services, pursuant to section 7(b) of the Natural Gas Act, is authorized upon the expiration of the contractual term of each individual arrangement authorized by a blanket certificate under this section.

(f) Effect of certificate. Acceptance of a certificate issued under this section or conduct of activity authorized under this section will not subject the certificate holder to the Natural Gas Act jurisdiction of the Commission except to the extent necessary to enforce the terms and conditions of the certificate.

[Order 537, 56 FR 50246, Oct. 4, 1991, as amended by Order 544, 57 FR 46501, Oct. 9, 1992; Order 581, 60 FR 53074, Oct. 11, 1995]

§ 284.261 Purpose.

This subpart exempts a person who engages in an emergency natural gas transaction, as defined for purposes of this subpart, in interstate commerce from the certificate requirements of section 7 of the Natural Gas Act and from the conditions of § 284.10, except as provided in § 284.266, and §§ 284.7-284.9 and §§ 284.11-284.13 of subpart A of this chapter.

§ 284.262 Definitions.

For purposes of this subpart:

Emergency means:

(1) Any situation in which an actual or expected shortage of gas supply or capacity would require an interstate pipeline company, intrastate pipeline, local distribution company, or Hinshaw pipeline to curtail deliveries of gas or provide less than the projected level of service to any pipeline customer, including any situation in which additional supplies or capacity are necessary to ensure a pipeline's contracted level of service to any customer, but not including any situation in which additional supplies or capacity are needed to increase the contracted level of service to an existing customer or to provide service to a new customer; or

(2) A sudden unanticipated loss of natural gas supply or capacity; or

(3) An anticipated loss of natural gas supply or capacity due to a foreseeable facility outage resulting from a landslide or riverbed erosion or other natural forces beyond the participant's control. Participants may seek a temporary certificate under §§ 157.17 of this chapter if the facilities to remedy the emergency cannot be constructed automatically under § 2.55(b) or § 157.208(a) of this chapter.

(4) A situation in which the participant, in good faith, determines that immediate action is required or is reasonably anticipated to be required for protection of life or health or for maintenance of physical property.

Emergency does not mean any situation resulting from a failure by any person to transport natural gas under subpart B, C, or G of this part.

Projected level of service means the level of gas volumes to be delivered by the company for each customer and additional gas volumes needed by a customer due solely to a weather-induced increase in requirements.

Emergency natural gas means natural gas sold, transported, or exchanged in an emergency natural gas transaction.

Emergency natural gas transaction means the sale, transportation, or exchange of natural gas (including the construction and operation of necessary facilities) conducted pursuant to this subpart, that is:

(1) Necessary to alleviate an emergency; and

(2) Not anticipated to extend for more than 60 days in duration.

Emergency facilities means any facilities necessary to alleviate the emergency within the time frame established in § 284.264(b). Participants can seek permanent authority to operate the emergency facilities either under the temporary certificate provisions of § 157.17 of this chapter or the prior notice provisions of § 157.208(b) of this chapter.

Participant means any first seller, interstate pipeline, intrastate pipeline, local distribution company or Hinshaw pipeline that participates in an emergency natural gas transaction under this subpart.

Recipient means:

(1) In the case of a sale of emergency natural gas, the purchaser of such gas; or

(2) In the case of a transportation or exchange of natural gas when there is no sale of emergency natural gas under this subpart, the participant who receives the gas.

Hinshaw pipeline means a pipeline that is exempt from the Natural Gas Act jurisdiction of the Commission by reason of section 1(c) of the Natural Gas Act.

[Order 603, 64 FR 26610, May 14, 1999]

§ 284.263 Exemption from section 7 of Natural Gas Act and certain regulatory conditions.

Any participant that engages in an emergency natural gas transaction conducted in accordance with this subpart is exempt from the requirements of section 7 of the Natural Gas Act and the conditions of § 284.10, except as provided in § 284.266, and from the requirements of §§ 284.7-284.9 and §§ 284.11-284.13 of subpart A of this part. Participation in any emergency natural gas transaction will not subject any participant to the jurisdiction of the Commission under section 7 of the Natural Gas Act except to the extent such transaction is provided for in this subpart.

§ 284.264 Terms and conditions.

(a) General conditions. (1) A participant must make every reasonable attempt to minimize use of emergency natural gas transactions.

(2) Before deliveries of emergency natural gas commence, a responsible official of the recipient must provide any participants in the emergency natural gas transaction sufficient information to enable the participants to form a good faith belief that an emergency exists or is imminent.

(3) No participant may engage in an emergency natural gas transaction if its participation will adversely affect service to its existing customers.

(4) A participant may not sell emergency natural gas if, during the term of the sale, it is also purchasing emergency natural gas under this subpart, except when natural gas is being sold to relieve an emergency on another, separate segment of the participant's system.

(5) An interstate pipeline, acting in an emergency gas transaction as a broker or agent on behalf of another participant or any other person, may not receive compensation for such brokerage or agency service.

(6) A recipient of emergency natural gas that directly benefits from the service must:

(i) Provide line loss and the fuel volumes required to transport the emergency natural gas; and

(ii) Pay for the facilities required to be constructed to conduct the emergency natural gas transaction.

(b) Duration—(1) Emergency sale or transportation. An emergency natural gas transaction is limited to 60 consecutive calendar days, except that such transaction may be continued for an additional 60 consecutive days if:

(i) Fifteen days prior to the end of the initial 60-day period, the recipient of emergency natural gas files a petition that:

(A) Describes fully the continued emergency,

(B) Requests a waiver of the initial 60-day limitation and permission for an extension of the transaction for an additional 60 days; and

(ii) Within the 15-day period, the Commission does not, by order, prohibit continuation of the emergency natural gas transaction for the additional 60-day period.

(2) Redelivery in emergency exchange. The redelivery of emergency natural gas received under an exchange arrangement must occur within 180 consecutive days following the termination of deliveries of the emergency natural gas.

§ 284.265 Cost recovery by interstate pipeline.

(a) Except as provided in paragraph (b), an interstate pipeline that provides emergency natural gas, whether from its system supply or by special purchase, must directly assign the emergency gas costs to the recipient.

(b) If an interstate pipeline cannot identify individual recipients, the interstate pipeline must roll the emergency gas costs into its general system supply costs.

§ 284.266 Rates and charges for interstate pipelines.

(a) Transportation rates—(1) Rate on file. If an interstate pipeline has on file with the Commission an effective transportation rate schedule that conforms to § 284.10, it must use volumetric rates based upon fully-allocated costs and adjusted only for time and distance.

(2) Rate not on file. If an interstate pipeline does not have on file with the Commission a transportation rate schedule that conforms to § 284.10, it may:

(i) Base its rates upon the methodology used in designing rates to recover the transmission and related storage costs included in one of its then-effective sales rates schedules; or

(ii) Use the rates contained in one of its transportation rate schedules on file with the Commission which the interstate pipeline determines covers service comparable to transportation service authorized under this subpart.

(b) Interstate pipeline costs excluded from rate base. An interstate pipeline may not include in its jurisdictional rate base any cost associated with facilities installed and operated in connection with an emergency natural gas transaction unless a certificate of public convenience and necessity has been issued authorizing the costs. Absent a certificate, such facilities may only be used to conduct emergency natural gas transactions or transactions authorized under section 311 of the NGPA.

[Order 449, 51 FR 9187, Mar. 18, 1986, as amended by Order 581, 60 FR 53074, Oct. 11, 1995]

§ 284.267 Intrastate pipeline emergency transportation rates.

General rule. Rates and charges for transportation of emergency gas by intrastate pipelines authorized under this subpart must be determined in accordance with § 284.123 of this chapter.

§ 284.268 Local distribution company emergency transportation rates.

(a) Rate on file. A local distribution company that has a rate on file with an appropriate state regulatory agency for city-gate transportation services must determine its rates and charges for transportation of emergency natural gas in accordance with § 284.123 of this chapter.

(b) Rate not on file. A local distribution company that does not have a rate on file with an appropriate state regulatory agency for city-gate transportation services must determine its rates and charges for transportation of emergency natural gas (per unit volume of emergency natural gas transported) in accordance with § 284.224(e)(2)(ii) of this chapter.

§ 284.269 Intrastate pipeline and local distribution company emergency sales rates.

An intrastate pipeline or local distribution company must determine its rates for sales of emergency natural gas under this subpart in accordance with § 284.142.

[Order 449, 51 FR 9187, Mar. 18, 1986, as amended by Order 581, 60 FR 53074, Oct. 11, 1995]

§ 284.270 Reporting requirements.

(a) Forty-eight hour report for sales transactions. Within 48 hours after deliveries of emergency natural gas commence, the purchasing participant must notify the Commission by email, facsimile or other written report of the sale, stating, in the following sequences:

(1) That the report is submitted pursuant to § 284.270 for an emergency natural gas transaction;

(2) The date deliveries commenced;

(3) The specific nature of the situation, explained in sufficient detail to demonstrate how the situation qualifies as an emergency under § 284.262 and under the conditions of § 284.264, and anticipated duration of the emergency;

(4) The estimated total amount and average daily amount of emergency natural gas to be purchased during the term of the transaction;

(5) The purchase price of the emergency natural gas;

(6) The transportation rate; and

(7) The identity of all participants involved in the transaction, including any customers to whom the emergency natural gas is to be assigned.

(b) Forty-eight hour report for transportation (excluding exchanges). Within 48 hours after deliveries commence in an emergency natural gas transaction which does not involve the sale of emergency natural gas, the recipient of emergency natural gas shall notify the Commission by email, facsimile or other written report of the transportation, stating, in the following sequence:

(1) That the report is submitted pursuant to § 284.270 for an emergency transaction;

(2) The date deliveries commenced;

(3) The specific nature of the situation, explained in sufficient detail to demonstrate how the situation qualifies as an emergency under § 284.262 and under the conditions of § 284.264, and anticipated duration of the emergency;

(4) The estimated total amount and average daily amount of emergency natural gas to be transported during the term of the transaction;

(5) The transportation rate; and

(6) The identity of all the participants involved in the transaction.

(c) Forty-eight hour report for exchanges. Within 48 hours after an exchange transaction for emergency natural gas commences, the initial recipient of the exchange volumes must notify the Commission by email, facsimile or other written report of the exchange, stating, in the following sequence:

(1) That the report is for and submitted pursuant to § 284.270 for an emergency transaction;

(2) The date the exchange commenced;

(3) The specific nature of the situation, explained in sufficient detail to clearly demonstrate how the situation qualifies as an emergency under § 284.262 and under the conditions of § 284.264, and anticipated duration of the emergency;

(4) The estimated total amount and average daily amount of emergency natural gas to be exchanged during the term of the transaction;

(5) The identity of all participants involved in the transaction;

(6) Whether the exchange is simultaneous or deferred, or any imbalances in the volumes;

(7) Whether the exchange is on a thermal or volumetric basis; and

(8) The rates or charges, if any, for the exchange service.

(d) Termination report. Within thirty days after the emergency natural gas transaction ends, the participant that received the emergency natural gas shall file with the Commission a sworn statement and two conformed copies thereof, which must include the following information in the following sequence:

(1) A description of the emergency natural gas transaction, including sufficient information to clearly demonstrate how the situation qualifies as an emergency under § 284.262 and under the conditions of § 284.264; the commencement and termination dates; the date of the 48-hour report, and the method of resolving the emergency;

(2) Any corrections to the 48-hour report information supplied to the Commission under paragraphs (a) through (c) of this section or a statement that the information was correct;

(3) The volumes of the emergency natural gas delivered during the transaction;

(4) The total compensation received by the seller for the emergency sale;

(5) The total compensation paid for the emergency natural gas transportation or exchange service, if any;

(6) The methods by which such compensation was derived;

(7) The total volumes of natural gas whose cost was assigned to specific customers, and the total volumes whose cost was included in system supply;

(8) The information supplied to any other participant pursuant to § 284.264(a)(2); and

(9) A statement that the emergency natural gas transaction was carried out in accordance with this subpart, and that identifies the circumstances demonstrating an emergency existed or was imminent so as to require an emergency natural gas transaction.

[Order 46, 44 FR 52184, Sept. 7, 1979, as amended by Order 756, 77 FR 4894, Feb. 1, 2012]

§ 284.271 Waiver.

The Commission may, by order, waive the requirements of this subpart in connection with any emergency natural gas transaction to the extent required by the public interest.

§ 284.281 Applicability.

This subpart applies to any interstate pipeline that offers transportation service under subpart B or G of this part.

§ 284.282 Definitions.

(a) Bundled sales service is gas sales service that is not sold separately from transportation service.

(b) Sales service includes firm or interruptible gas sales.

(c) Unbundled sales service is gas sales service that is sold separately from transportation service.

(d) Small customer is a customer that purchases gas from a pipeline under the pipeline's one-part imputed load factor rate schedule on the effective date of the blanket certificate.

[Order 636, 57 FR 13318, Apr. 16, 1992, as amended by Order 636-A, 57 FR 36218, Aug. 12, 1992]

§ 284.283 Point of unbundling.

A sales service is unbundled when gas is sold at a point before it enters a mainline system, at an entry point to a mainline system from a production area, or at an intersection with another pipeline system.

§ 284.284 Blanket certificates for unbundled sales services.

(a) Authorization. An interstate pipeline that offers transportation service under subpart B or G of this part is granted a blanket certificate of public convenience and necessity pursuant to section 7 of the Natural Gas Act authorizing it to provide unbundled firm or interruptible sales in accordance with the provisions of this section.

(b) Conversion to unbundled firm sales service and firm transportation service. On the effective date of the pipeline's blanket certificate for unbundled sales services under paragraph (a) of this section, firm sales entitlements under any firm sales service agreement for a bundled sales service are converted to an equivalent amount of unbundled firm sales service and an equivalent amount of unbundled firm transportation service.

(c) Conversion to unbundled interruptible sales service and interruptible transportation service. On the effective date of the pipeline's blanket certificate for unbundled sales services under paragraph (a) of this section, interruptible sales volumes under any interruptible sales service agreement for a bundled sales service are converted to an equivalent amount of unbundled sales service and an equivalent amount of unbundled interruptible transportation service.

(d) A pipeline that provides unbundled sales service under this section may serve as an agent of the sales customer to arrange for any pipeline-provided service necessary to deliver gas to the customer.

(e) Small customer cost-based rate. A pipeline that provided bundled sales service to a small customer before the effective date of the blanket certificate granted in paragraph (a) of this section is required to offer a sales service to that customer at a cost-based rate for one year from the effective date of the certificate. The obligation to sell at the cost-based rate expires one year after the effective date of the certificate.

[Order 636, 57 FR 13318, Apr. 16, 1992, as amended by Order 636-A, 57 FR 36218, Aug. 12, 1992; Order 581, 60 FR 53074, Oct. 11, 1995]

§ 284.285 Pregrant of abandonment of unbundled sales services.

Abandonment of unbundled sales services is authorized pursuant to section 7(b) of the Natural Gas Act upon the expiration of the contractual term or upon termination of each individual sales arrangement authorized under § 284.284.

§ 284.286 Standards of conduct for unbundled sales service.

(a) To the maximum extent practicable, the pipeline must organize its unbundled sales and transportation operating employees so that they function independently of each other.

(b) The pipeline must conduct its business to conform to the requirements set forth in § 284.7(b)(2) and § 284.9(b)(2) with respect to the equality of service by not giving shippers of gas sold by the pipeline any preference over shippers of gas sold by any other merchant in matters relating to part 284 transportation.

(c) The pipeline must comply with part 358 by considering its unbundled sales operating employees as an operational unit which is the functional equivalent of a marketing affiliate.

(d) The pipeline must comply with § 250.16 of this chapter by considering its unbundled sales operating employees as an operational unit which is the functional equivalent of a marketing affiliate.

(e) A pipeline that provides unbundled sales service under § 284.284 must have tariff provisions on file with the Commission indicating how the pipeline is complying with the standards of this section.

[Order 636, 57 FR 13318, Apr. 16, 1992, as amended by Order 566, 59 FR 32899, June 27, 1994; Order 581, 60 FR 53074, Oct. 11, 1995; Order 2004, 68 FR 69157, Dec. 11, 2003]

§ 284.287 Implementation and effective date.

(a) Prior to offering any sales service under this subpart J, a pipeline must file revised tariff sheets incorporating the provisions of this subpart J.

(b) A blanket certificate issued under § 284.284 will be effective on the effective date (as approved by the Commission) of the tariff sheets implementing service under that certificate.

[Order 581, 60 FR 53074, Oct. 11, 1995]

§ 284.288 Code of conduct for unbundled sales service.

(a) To the extent Seller engages in reporting of transactions to publishers of electricity or natural gas indices, Seller must provide accurate and factual information, and not knowingly submit false or misleading information or omit material information to any such publisher, by reporting its transactions in a manner consistent with the procedures set forth in the Policy Statement on Natural Gas and Electric Price Indices, issued by the Commission in Docket No. PL03-3-000 and any clarifications thereto. Seller must notify the Commission as part of its FERC Form No. 552 annual reporting requirement in § 260.401 of this chapter whether it reports its transactions to publishers of electricity and natural gas indices. In addition, Seller must adhere to any other standards and requirements for price reporting as the Commission may order.

(b) A pipeline that provides unbundled natural gas sales service under § 284.284 shall retain, for a period of five years, all data and information upon which it billed the prices it charged for natural gas it sold pursuant to its market based sales certificate or the prices it reported for use in price indices.

[Order 644, 68 FR 66336, Nov. 26, 2003, as amended by Order 673, 71 FR 9716, Feb. 27, 2006; Order 677, 71 FR 30287, May 26, 2006; 73 FR 1032, Jan. 4, 2008]

§ 284.301 Applicability.

This subpart implements section 5 of the Outer Continental Shelf Land Act (OCSLA) and applies to any jurisdictional interstate natural gas pipeline that holds a certificate under section 7 of the Natural Gas Act (NGA) authorizing the construction and operation of facilities on the Outer Continental Shelf (OCS).

§ 284.302 Definitions.

For the purposes of this subpart, the term:

(a) Outer Continental Shelf (OCS) has the same meaning as found in section 2(a) of the OCSLA (43 U.S.C. 1331(a)); and

(b) OCS pipeline means an interstate natural gas pipeline that holds a certificate under section 7 of the NGA authorizing the construction and operation of facilities on the OCS, and includes all of the OCS pipeline's facilities that fall within the scope of the Commission's jurisdiction under section 7 of the NGA to the full extent that such facilities are used or necessary to transport natural gas on or across the OCS between:

(1) Any locations on the OCS (if the pipeline does not have an interconnection off the OCS), or

(2) The OCS and the first point of interconnection on the shoreward side of the OCS where the pipeline delivers or receives natural gas to or from either:

(i) A natural gas conditioning or processing facility, or

(ii) Another pipeline, or

(iii) A distributor or end user of natural gas.

[Order 509, 53 FR 50938, Dec. 19, 1988, as amended by Order 509-A, 54 FR 8313, Feb. 28, 1989]

§ 284.303 OCS blanket certificates.

Every OCS pipeline [as that term is defined in § 284.302(b)] is required to provide open-access, nondiscriminatory transportation service pursuant to a blanket transportation certificate issued under subpart G of this part.

[Order 559, 58 FR 52663, Oct. 12, 1993]

§ 284.401 Definitions.

Affiliated marketer. For purposes of this subpart, an “affiliated marketer” is a person engaged in the “marketing” of natural gas that is an “affiliate” of an interstate pipeline as those terms are defined in § 161.2 of this chapter.

[Order 547, 57 FR 57959, Dec. 8, 1992]

§ 284.402 Blanket marketing certificates.

(a) Authorization. Any person who is not an interstate pipeline is granted a blanket certificate of public convenience and necessity pursuant to section 7 of the Natural Gas Act authorizing the certificate holder to make sales for resale at negotiated rates in interstate commerce of any category of gas that is subject to the Commission's Natural Gas Act jurisdiction. A blanket certificate issued under Subpart L is a certificate of limited jurisdiction which will not subject the certificate holder to any other regulation under the Natural Gas Act jurisdiction of the Commission, other than that set forth in this Subpart L, by virtue of the transactions under this certificate.

(b) The authorization granted in paragraph (a) of this section will become effective on January 7, 1993 except as otherwise provided in paragraph (c) of this section.

(c)(1) The authorization granted in paragraph (a) of this section will become effective for an affiliated marketer with respect to transactions involving affiliated pipelines when an affiliated pipeline receives its blanket certificate pursuant to § 284.284.

(2) Should a marketer be affiliated with more than one pipeline, the authorization granted in paragraph (a) of this section will not be effective for transactions involving other affiliated interstate pipelines until such other pipelines' meet the criterion set forth in paragraph (c)(1) of this section. The authorization granted in paragraph (a) of this section is not extended to affiliates of persons who transport gas in interstate commerce and who do not have a tariff on file with the Commission under part 284 of this subchapter with respect to transactions involving that person.

(d) Abandonment of the sales service authorized in paragraph (a) of this section is authorized pursuant to section 7(b) of the Natural Gas Act upon the expiration of the contractual term or upon termination of each individual sales arrangement.

[Order 547, 57 FR 57959, Dec. 8, 1992, as amended by Order 581, 60 FR 53074, Oct. 11, 1995; Order 644, 68 FR 66337, Nov. 26, 2003]

§ 284.403 Code of conduct for persons holding blanket marketing certificates.

(a) To the extent Seller engages in reporting of transactions to publishers of electricity or natural gas indices, Seller must provide accurate and factual information, and not knowingly submit false or misleading information or omit material information to any such publisher, by reporting its transactions in a manner consistent with the procedures set forth in the Policy Statement on Natural Gas and Electric Price Indices, issued by the Commission in Docket No. PL03-3-000 and any clarifications thereto. Seller must notify the Commission as part of its FERC Form No. 552 annual reporting requirement in § 260.401 of this chapter whether it reports its transactions to publishers of electricity and natural gas indices. In addition, Seller shall adhere to any other standards and requirements for price reporting as the Commission may order.

(b) A blanket marketing certificate holder shall retain, for a period of five years, all data and information upon which it billed the prices it charged for the natural gas sold pursuant to its market based sales certificate or the prices it reported for use in price indices.

[Order 644, 68 FR 66337, Nov. 26, 2003, as amended by Order 673, 71 FR 9716, Feb. 27, 2006; Order 677, 71 FR 30287, May 26, 2006; 73 FR 1032, Jan. 4, 2008; 73 FR 55739, Sept. 26, 2008]

§ 284.501 Applicability.

Any pipeline or storage service provider that provides or will provide service under subparts B, C, or G of this part, and that wishes to provide storage and storage-related services at market-based rates must conform to the requirements in subpart M.

§ 284.502 Procedures for applying for market-based rates.

(a) Applications for market-based rates may be filed with certificate applications. Service, notice, intervention, and protest procedures for such filings will conform with those applicable to the certificate application.

(b) With respect to applications not filed as part of certificate applications,

(1) Applicants providing service under subpart B or subpart G of this part must file a request for declaratory order and comply with the service and filing requirements of part 154 of this chapter. Interventions and protests to applications for market-based rates must be filed within 30 days of the application unless the notice issued by the Commission provides otherwise. An applicant providing service under subpart B or subpart G of this part cannot charge market-based rates under this subpart of this part until its application has been accepted by the Commission. Once accepted, the applicant can make the appropriate filing necessary to set its market-based rates into effect.

(2) Applicants providing service under subpart C of this part must file in accordance with the requirements of that subpart.

§ 284.503 Market-power determination.

An applicant may apply for market-based rates by filing a request for a market-power determination that complies with the following:

(a) The applicant must set forth its specific request and adequately demonstrate that it lacks market power in the market to be served, and must include an executive summary of its statement of position and a statement of material facts in addition to its complete statement of position. The statement of material facts must include citation to the supporting statements, exhibits, affidavits, and prepared testimony.

(b) The applicant must include with its application the following information:

(1) Statement A—geographic market. This statement must describe the geographic markets for storage services in which the applicant seeks to establish that it lacks significant market power. It must include the market related to the service for which it proposes to charge market-based rates. The statement must explain why the applicant's method for selecting the geographic markets is appropriate.

(2) Statement B—product market. This statement must identify the product market or markets for which the applicant seeks to establish that it lacks significant market power. The statement must explain why the particular product definition is appropriate.

(3) Statement C—the applicant's facilities and services. This statement must describe the applicant's own facilities and services, and those of all parent, subsidiary, or affiliated companies, in the relevant markets identified in Statements A and B in paragraphs (b)(1) and (2) of this section. The statement must include all pertinent data about the storage facilities and services.

(4) Statement D—competitive alternatives. This statement must describe available alternatives in competition with the applicant in the relevant markets and other competition constraining the applicant's rates in those markets. Such proposed alternatives may include an appropriate combination of other storage, local gas supply, LNG, financial instruments and pipeline capacity. These alternatives must be shown to be reasonably available as a substitute in the area to be served soon enough, at a price low enough, and with a quality high enough to be a reasonable alternative to the applicant's services. Capacity (transportation, storage, LNG, or production) owned or controlled by the applicant and affiliates of the applicant in the relevant market shall be clearly and fully identified and may not be considered as alternatives competing with the applicant. Rather, the capacity of an applicant's affiliates is to be included in the market share calculated for the applicant. To the extent available, the statement must include all pertinent data about storage or other alternatives and other constraining competition.

(5) Statement E—potential competition. This statement must describe potential competition in the relevant markets. To the extent available, the statement must include data about the potential competitors, including their costs, and their distance in miles from the applicant's facilities and major consuming markets. This statement must also describe any relevant barriers to entry and the applicant's assessment of whether ease of entry is an effective counter to attempts to exercise market power in the relevant markets.

(6) Statement F—maps. This statement must consist of maps showing the applicant's principal facilities, pipelines to which the applicant intends to interconnect and other pipelines within the area to be served, the direction of flow of each line, the location of the alternatives to the applicant's service offerings, including their distance in miles from the applicant's facility. The statement must include a general system map and maps by geographic markets. The information required by this statement may be on separate pages.

(7) Statement G—market-power measures. This statement must set forth the calculation of the market concentration of the relevant markets using the Herfindahl-Hirschman Index. The statement must also set forth the applicant's market share, inclusive of affiliated service offerings, in the markets to be served. The statement must also set forth the calculation of other market-power measures relied on by the applicant. The statement must include complete particulars about the applicant's calculations.

(8) Statement H—other factors. This statement must describe any other factors that bear on the issue of whether the applicant lacks significant market power in the relevant markets. The description must explain why those other factors are pertinent.

(9) Statement I—prepared testimony. This statement must include the proposed testimony in support of the application and will serve as the applicant's case-in-chief, if the Commission sets the application for hearing. The proposed witness must subscribe to the testimony and swear that all statements of fact contained in the proposed testimony are true and correct to the best of his or her knowledge, information, and belief.

§ 284.504 Standard requirements for market-power authorizations.

(a) Applicants granted the authority to charge market-based rates under § 284.503 that provide cost-based service(s) must separately account for all costs and revenues associated with facilities used to provide the market-based services. When it files to change its cost-based rates, applicant must provide a summary of the costs and revenues associated with market-based rates with applicable cross references to §§ 154.312 and 154.313 of this chapter. The summary statement must provide the formulae and explain the bases used in the allocation of common costs between the applicant's cost-based services and its market-based services.

(b) A storage service provider granted the authority to charge market-based rates under § 284.503 is required to notify the Commission within 10 days of acquiring knowledge of significant changes occurring in its market power status. Such notification should include a detailed description of the new facilities/services and their relationship to the storage service provider. Significant changes include, but are not limited to:

(1) The storage provider expanding its storage capacity beyond the amount authorized in this proceeding;

(2) The storage provider acquiring transportation facilities or additional storage capacity;

(3) An affiliate providing storage or transportation services in the same market area; and

(4) The storage provider or an affiliate acquiring an interest in or is acquired by an interstate pipeline.

§ 284.505 Market-based rates for storage providers without a market-power determination.

(a) Any storage service provider seeking market-based rates for storage capacity, pursuant to the authority of section 4(f) of the Natural Gas Act, related to a specific facility put into service after August 8, 2005, may apply for market-based rates by complying with the following requirements:

(1) The storage service provider must demonstrate that market-based rates are in the public interest and necessary to encourage the construction of the storage capacity in the area needing storage services; and

(2) The storage service provider must provide a means of protecting customers from the potential exercise of market power.

(b) Any storage service provider seeking market-based rates for storage capacity pursuant to this section will be presumed by the Commission to have market power.

§ 286.101 Application for stay.

(a) General rule. Any person who believes that any provision of a final or interim regulation issued under the Natural Gas Policy Act of 1978 is unlawful as applied to such person may file an application for stay.

(b) Content of application. The application shall state, clearly and concisely:

(1) The provision of the regulation, by section, paragraph, subparagraph and clause, as appropriate, which applicant seeks to have stayed;

(2) The conditions which the applicant believes require the stay, including the irreparable injury which the applicant believes will result if the stay is not granted; and

(3) The factual and legal basis for applicant's contention that the final or interim regulation is unlawful.

(c) Filing requirements. The application shall be under oath. An original and three conformed copies shall be filed with the Secretary of the Commission.

(d) Commission action. The Commission may grant the application, in whole or in part, by issuing an order specifying the scope of the stay granted and the effective dates of the stay.

[43 FR 57599, Dec. 8, 1978, as amended at 44 FR 13473, Mar. 12, 1979]

§ 286.102 Application for rehearing.

(a) General rule. Any person aggrieved by any order or regulation or any amendment to a regulation issued under the NGPA and subject to judicial review under section 506(a) or (b) thereof shall file a petition for rehearing within 30 days after the order or regulation is issued by the Commission or February 3, 1979, whichever is later. There has not been an exhaustion of administrative remedies until a petition for rehearing has been filed under this section and the proceeding is complete by the denial of the request, or if rehearing is granted, an order affirming, modifying or revoking the challenged order or regulation is issued.

(b) Specifications of error. The application for rehearing shall state clearly and concisely with respect to the challenged order or regulation:

(1) The provision of the order or the regulation, by section, and where appropriate, by paragraph;

(2) Applicant's interest in the particular provision; and

(3) The facts and legal analysis upon which the request for rehearing is based.

(c) Procedural requirements. Except as otherwise provided in this section, the procedures for rehearing in § 385.713 of this chapter shall apply.

(d) Commission action upon the application. (1) The Commission may grant the request for rehearing, in whole or in part, by issuing an order specifying the scope of rehearing. If, and to the extent that rehearing is granted, the Commission may request Staff, applicant or any other party to file briefs. In every case where rehearing is granted, the Commission will issue an order affirming, modifying or revoking the challenged order or regulation.

(2) The Commission may modify the original order or regulation without further hearing.

(3) Unless the Commission acts upon the application within 30 days after it is filed, such application shall be considered to have been denied. If the Commission grants rehearing in part, any part of the application outside the scope of the order granting rehearing shall be considered to have been denied.

[44 FR 2383, Jan. 11, 1979, as amended by Order 225, 47 FR 19058, May 3, 1982]

§ 286.103 Notice to audited person.

An audit conducted by the Commission's staff under authority of the Natural Gas Policy Act may result in a notice of deficiency or audit report or similar document containing a finding or findings that the audited person has not complied with a requirement of the Commission with respect to, but not limited to, the following: A filed tariff or tariffs, contracts, data, records, accounts, books, communications or papers relevant to the audit of the audited person; matters under the Standards of Conduct or the Code of Conduct; and the activities or operations of the audited person. The notice of deficiency, audit report or similar document may also contain one or more proposed remedies that address findings of noncompliance. Where such findings, with or without proposed remedies, appear in a notice of deficiency, audit report or similar document, such document shall be provided to the audited person, and the finding or findings, and any proposed remedies, shall be noted and explained. The audited person shall timely indicate in a written response any and all findings or proposed remedies, or both, in any combination, with which the audited person disagrees. The audited person shall have 15 days from the date it is sent the notice of deficiency, audit report or similar document to provide a written response to the audit staff indicating any and all findings or proposed remedies, or both, in any combination, with which the audited person disagrees, and such further time as the audit staff may provide in writing to the audited person at the time the document is sent to the audited person. The audited person may move the Commission for additional time to provide a written response to the audit staff and such motion shall be granted for good cause shown. Any initial order that the Commission subsequently may issue with respect to the notice of deficiency, audit report or similar document shall note, but not address on the merits, the finding or findings, or the proposed remedy or remedies, or both, in any combination, with which the audited person disagreed. The Commission shall provide the audited person 30 days to respond to the initial Commission order concerning a notice of deficiency, audit report or similar document with respect to the finding or findings or any proposed remedy or remedies, or both, in any combination, with which it disagreed.

[Order 675-A, 71 FR 29785, May 24, 2006]

§ 286.104 Response to notification.

Upon issuance of a Commission order that notes a finding or findings, with or without proposed remedies, with which the audited person has disagreed, the audited person may: Acquiesce in the findings and proposed remedies by not timely responding to the Commission order, in which case the Commission may issue an order approving them or taking other action; or challenge the finding or findings and any proposed remedies with which it disagreed by timely notifying the Commission in writing that it requests Commission review by means of a shortened procedure, or, if there are material facts in dispute which require cross-examination, a trial-type hearing.

§ 286.105 Shortened procedure.

If the audited person subject to a Commission order described in § 286.103 notifies the Commission that it seeks to challenge one or more audit findings, or proposed remedies, or both, in any combination, by the shortened procedure, the Commission shall thereupon issue a notice setting a schedule for the filing of memoranda. The person electing the use of the shortened procedure, and any other interested entities, including the Commission staff, shall file, within 45 days of the notice, an initial memorandum that addresses the relevant facts and applicable law that support the position or positions taken regarding the matters at issue. Reply memoranda shall be filed within 20 days of the date by which the initial memoranda are due to be filed. Only participants who filed initial memoranda may file reply memoranda. Subpart T of part 385 of this chapter shall apply to all filings. Within 20 days after the last date that reply memoranda under the shortened procedure may be timely filed, the audited person who elected the shortened procedure may file a motion with the Commission requesting a trial-type hearing if new issues are raised by a party. To prevail in such a motion, the audited person must show that a party to the shortened procedure raised one or more new issues of material fact relevant to resolution of a matter in the shortened procedure such that fundamental fairness requires a trial-type hearing to resolve the new issue or issues so raised. Parties to the shortened procedure and the Commission staff may file responses to the motion. In ruling upon the motion, the Commission may determine that some or all of the issues be litigated in a trial-type hearing.

§ 286.106 Form and style.

Each copy of such memorandum must be complete in itself. All pertinent data should be set forth fully, and each memorandum should set out the facts and argument as prescribed for briefs in § 385.706 of this chapter.

§ 286.107 Verification.

The facts stated in the memorandum must be sworn to by persons having knowledge thereof, which latter fact must affirmatively appear in the affidavit. Except under unusual circumstances, such persons should be those who would appear as witnesses if hearing were had to testify as to the facts stated in the memorandum.

§ 286.108 Determination.

If no formal hearing is had the matter in issue will be determined by the Commission on the basis of the facts and arguments submitted.

§ 286.109 Assignment for oral hearing.

Except when there are no material facts in dispute, when a person does not consent to the shortened procedure, the Commission will assign the proceeding for hearing as provided by subpart E of part 385 of this chapter. Notwithstanding a person's not giving consent to the shortened procedure, and instead seeking assignment for hearing as provided for by subpart E of part 385 of this chapter, the Commission will not assign the proceeding for a hearing when no material facts are in dispute. The Commission may also, in its discretion, at any stage in the proceeding, set the proceeding for hearing.

§ 287.101 Determination of powerplant design capacity.

For the purpose of section 103 of the Powerplant and Industrial Fuel Use Act of 1978, a powerplant's design capacity shall be determined as follows:

(a) Steam-electric generating unit. The design capacity of a steam-electric generating unit shall be maximum generator nameplate rating measured in kilowatts or, if the nameplate does not have a rating measured in kilowatts, the product of the generator's kilovolt-amperes nameplate rating and power factor nameplate rating.

(b) Combustion turbine. The design capacity of a combustion turbine shall be its nameplate rating measured in kilowatts, adjusted for peaking service at an ambient temperature of 59 degrees Fahrenheit (15 degrees Celsius) and at the unit's site elevation.

(c) Combined cycle unit. The design capacity of a combined cycle shall be the sum of its combustion turbine nameplate rating measured in kilowatts, based on baseload operation adjusted for site elevation, and the maximum generator nameplate rating measured in kilowatts of the steam turbine portion of the unit.

(d) Internal combustion engine. The design capacity of an internal combustion engine shall be the generator's nameplate rating measured in kilowatts.

(e) Sunsetting provisions. This section shall cease to have effect on December 5, 2026, unless the Commission determines that the cessation deadline should be extended to a date not more than 5 years in the future after offering the public an opportunity to provide input on the costs and benefits of this section and considering that input. The Commission will publish a document in the Federal Register announcing its determination and revising or removing this section accordingly.

[44 FR 38839, July 3, 1979, as amended by Order 914, 90 FR 48404, Oct. 21, 2025]

§ 290.101 Applicability and exemptions.

(a) Except as provided in paragraph (b), this part shall apply to each electric utility, in any calendar year, if the total sales of electric energy by such utility for purposes other than resale exceed 500 million kilowatt-hours during any calendar year beginning after December 31, 1975, and before the immediately preceding calendar year.

(b) The Commission exempts from compliance with this part any utility:

(1) Listed by name in Appendix A to this part; or

(2) That has total sales of electric energy for purposes other than resale of less than 2 billion kilowatt-hours per year.

[Order 353, 48 FR 55449, Dec. 13, 1983, as amended at 49 FR 4939, Feb. 9, 1984]

§ 290.102 Information gathering and filing.

All nonexempt electric utilities must file the data required by section 133(a) of the Public Utility Regulatory Policies Act of 1978, 16 U.S.C. § 2643, with their state regulatory authorities. All nonexempt, nonregulated electric utilities shall, to the extent the data are collected and compiled, make these data publicly available. All nonexempt electric utilities shall file an affidavit with the Commission certifying that the requisite state filing was made. All nonexempt, nonregulated electric utilities shall file an affidavit with the Commission certifying that the data were made publicly available.

[Order 545, 57 FR 53991, Nov. 16, 1992]

§ 290.103 Time of filing and reporting period.

All nonexempt electric utilities must file with any state regulatory authority having ratemaking authority for such utilities the information gathered pursuant to § 290.102, and all nonexempt, nonregulated electric utilities must make such information available to the public as follows:

(a) Biennial filing. Information required to be filed under § 290.102 must be filed biennially in even-numbered years on or before June 30 of that year.

(b) Reporting period. The reporting period is the calendar year immediately preceding the filing year. Information for previous years and projected information for future years must be reported on a calendar year basis.

(c) Alternate reporting period. Use of an alternate reporting period is permitted as follows:

(1) Except as provided in paragraph (c)(2) of this section, if a nonexempt electric utility has gathered all of the information specified in § 290.102 and has filed such information, based on a recent 12-month reporting period, either with its state regulatory authority or governing authority in connection with a retail rate proceeding, the nonexempt electric utility may substitute such information for the equivalent information required by this part in fulfillment of the biennial filing requirements.

(2) If a nonexempt electric utility not subject to the jurisdiction of a state regulatory authority maintains accounting records other than on a calendar year basis, such utility may use such other basis as the reporting period for purposes of compliance with this part, provided such reporting period is a 12-month period.

(Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 2601-2645; Energy Supply and Environmental Coordination Act, 15 U.S.C. 791-798; Federal Power Act, as amended, 16 U.S.C. 792-828C; Department of Energy Organization Act, 42 U.S.C. 7101-7352, E.O. 12009, 42 FR 46267)

[Order 48, 44 FR 58697, Oct. 11, 1979, as amended by Order 353, 48 FR 55449, Dec. 13, 1983; Order 545, 57 FR 53991, Nov. 16, 1992]

§ 292.101 Definitions.

(a) General rule. Terms defined in the Public Utility Regulatory Policies Act of 1978 (PURPA) shall have the same meaning for purposes of this part as they have under PURPA, unless further defined in this part.

(b) Definitions. The following definitions apply for purposes of this part.

(1) Qualifying facility means a cogeneration facility or a small power production facility that is a qualifying facility under Subpart B of this part.

(i) A qualifying facility may include transmission lines and other equipment used for interconnection purposes (including transformers and switchyard equipment), if:

(A) Such lines and equipment are used to supply power output to directly and indirectly interconnected electric utilities, and to end users, including thermal hosts, in accordance with state law; or

(B) Such lines and equipment are used to transmit supplementary, standby, maintenance and backup power to the qualifying facility, including its thermal host meeting the criteria set forth in Union Carbide Corporation, 48 FERC ¶ 61,130, reh'g denied, 49 FERC ¶ 61,209 (1989), aff'd sub nom., Gulf States Utilities Company v. FERC, 922 F.2d 873 (D.C. Cir. 1991); or

(C) If such lines and equipment are used to transmit power from other qualifying facilities or to transmit standby, maintenance, supplementary and backup power to other qualifying facilities.

(ii) The construction and ownership of such lines and equipment shall be subject to any applicable Federal, state, and local siting and environmental requirements.

(2) Purchase means the purchase of electric energy or capacity or both from a qualifying facility by an electric utility.

(3) Sale means the sale of electric energy or capacity or both by an electric utility to a qualifying facility.

(4) System emergency means a condition on a utility's system which is likely to result in imminent significant disruption of service to customers or is imminently likely to endanger life or property.

(5) Rate means any price, rate, charge, or classification made, demanded, observed or received with respect to the sale or purchase of electric energy or capacity, or any rule, regulation, or practice respecting any such rate, charge, or classification, and any contract pertaining to the sale or purchase of electric energy or capacity.

(6) Avoided costs means the incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source.

(7) Interconnection costs means the reasonable costs of connection, switching, metering, transmission, distribution, safety provisions and administrative costs incurred by the electric utility directly related to the installation and maintenance of the physical facilities necessary to permit interconnected operations with a qualifying facility, to the extent such costs are in excess of the corresponding costs which the electric utility would have incurred if it had not engaged in interconnected operations, but instead generated an equivalent amount of electric energy itself or purchased an equivalent amount of electric energy or capacity from other sources. Interconnection costs do not include any costs included in the calculation of avoided costs.

(8) Supplementary power means electric energy or capacity supplied by an electric utility, regularly used by a qualifying facility in addition to that which the facility generates itself.

(9) Back-up power means electric energy or capacity supplied by an electric utility to replace energy ordinarily generated by a facility's own generation equipment during an unscheduled outage of the facility.

(10) Interruptible power means electric energy or capacity supplied by an electric utility subject to interruption by the electric utility under specified conditions.

(11) Maintenance power means electric energy or capacity supplied by an electric utility during scheduled outages of the qualifying facility.

(12) Locational marginal price means the price for energy at a particular location as determined in a market defined in § 292.309(e), (f), or (g).

(13) Competitive Price means a Market Hub Price or a Combined Cycle Price.

(14) Market Hub Price means a price for as-delivered energy determined pursuant to § 292.304(b)(7)(i).

(15) Combined Cycle Price means a price for as-delivered energy determined pursuant to § 292.304(b)(7)(ii).

(16) Competitive Solicitation Price means a price for energy and/or capacity determined pursuant to § 292.304(b)(8).

(Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 2601 et seq., Energy Supply and Environmental Coordination Act, 15 U.S.C. 791 et seq. Federal Power Act, 16 U.S.C. 792 et seq., Department of Energy Organization Act, 42 U.S.C. 7101 et seq., E.O. 12009, 42 FR 46267)

[45 FR 12233, Feb. 25, 1980, as amended by Order 575, 60 FR 4856, Jan. 25, 1995; Order 872, 85 FR 54732, Sept. 2, 2020]

§ 292.201 Scope.

This subpart applies to the criteria for and manner of becoming a qualifying small power production facility and a qualifying cogeneration facility under sections 3(17)(C) and 3(18)(B), respectively, of the Federal Power Act, as amended by section 201 of the Public Utility Regulatory Policies Act of 1978 (PURPA).

[45 FR 17972, Mar. 20, 1980]

§ 292.202 Definitions.

For purposes of this subpart:

(a) Biomass means any organic material not derived from fossil fuels;

(b) Waste means an energy input that is listed below in this subsection, or any energy input that has little or no current commercial value and exists in the absence of the qualifying facility industry. Should a waste energy input acquire commercial value after a facility is qualified by way of Commission certification pursuant to § 292.207(b), or self-certification pursuant to § 292.207(a), the facility will not lose its qualifying status for that reason. Waste includes, but is not limited to, the following materials that the Commission previously has approved as waste:

(1) Anthracite culm produced prior to July 23, 1985;

(2) Anthracite refuse that has an average heat content of 6,000 Btu or less per pound and has an average ash content of 45 percent or more;

(3) Bituminous coal refuse that has an average heat content of 9,500 Btu per pound or less and has an average ash content of 25 percent or more;

(4) Top or bottom subbituminous coal produced on Federal lands or on Indian lands that has been determined to be waste by the United States Department of the Interior's Bureau of Land Management (BLM) or that is located on non-Federal or non-Indian lands outside of BLM's jurisdiction, provided that the applicant shows that the latter coal is an extension of that determined by BLM to be waste.

(5) Coal refuse produced on Federal lands or on Indian lands that has been determined to be waste by the BLM or that is located on non-Federal or non-Indian lands outside of BLM's jurisdiction, provided that applicant shows that the latter is an extension of that determined by BLM to be waste.

(6) Lignite produced in association with the production of montan wax and lignite that becomes exposed as a result of such a mining operation;

(7) Gaseous fuels, except:

(i) Synthetic gas from coal; and

(ii) Natural gas from gas and oil wells unless the natural gas meets the requirements of § 2.400 of this chapter;

(8) Petroleum coke;

(9) Materials that a government agency has certified for disposal by combustion;

(10) Residual heat;

(11) Heat from exothermic reactions;

(12) Used rubber tires;

(13) Plastic materials; and

(14) Refinery off-gas.

(c) Cogeneration facility means equipment used to produce electric energy and forms of useful thermal energy (such as heat or steam), used for industrial, commercial, heating, or cooling purposes, through the sequential use of energy;

(d) Topping-cycle cogeneration facility means a cogeneration facility in which the energy input to the facility is first used to produce useful power output, and at least some of the reject heat from the power production process is then used to provide useful thermal energy;

(e) Bottoming-cycle cogeneration facility means a cogeneration facility in which the energy input to the system is first applied to a useful thermal energy application or process, and at least some of the reject heat emerging from the application or process is then used for power production;

(f) Supplementary firing means an energy input to the cogeneration facility used only in the thermal process of a topping-cycle cogeneration facility, or only in the electric generating process of a bottoming-cycle cogeneration facility;

(g) Useful power output of a cogeneration facility means the electric or mechanical energy made available for use, exclusive of any such energy used in the power production process;

(h) Useful thermal energy output of a topping-cycle cogeneration facility means the thermal energy:

(1) That is made available to an industrial or commercial process (net of any heat contained in condensate return and/or makeup water);

(2) That is used in a heating application (e.g., space heating, domestic hot water heating);

(3) That is used in a space cooling application (i.e., thermal energy used by an absorption chiller); or

(4) That is used by a fuel cell system with an integrated steam hydrocarbon reformation process for production of fuel for electricity generation.

(i) Total energy output of a topping-cycle cogeneration facility is the sum of the useful power output and useful thermal energy output;

(j) Total energy input means the total energy of all forms supplied from external sources;

(k) Natural gas means either natural gas unmixed, or any mixture of natural gas and artificial gas;

(l) Oil means crude oil, residual fuel oil, natural gas liquids, or any refined petroleum products; and

(m) Energy input in the case of energy in the form of natural gas or oil is to be measured by the lower heating value of the natural gas or oil.

(n) Electric utility holding company means a holding company, as defined in section 2(a)(7) of the Public Utility Holding Company Act of 1935, 15 U.S.C. 79b(a)(7) which owns one or more electric utilities, as defined in section 2(a)(3) of that Act, 15 U.S.C. 79b(a)(3), but does not include any holding company which is exempt by rule or order adopted or issued pursuant to sections 3(a)(3) or 3(a)(5) of the Public Utility Holding Company Act of 1935, 15 U.S.C. 79c(a)(3) or 79c(a)(5).

(o) Utility geothermal small power production facility means a small power production facility which uses geothermal energy as the primary energy resource and of which more than 50 percent is owned either:

(1) By an electric utility or utilities, electric utility holding company or companies, or any combination thereof.

(2) By any company 50 percent or more of the outstanding voting securities of which of which are directly or indirectly owned, controlled, or held with power to vote by an electric utility, electric utility holding company, or any combination thereof.

(p) New dam or diversion means a dam or diversion which requires, for the purposes of installing any hydroelectric power project, any construction, or enlargement of any impoundment or diversion structure (other than repairs or reconstruction or the addition of flashboards of similar adjustable devices);

(q) Substantial adverse effect on the environment means a substantial alteration in the existing or potential use of, or a loss of, natural features, existing habitat, recreational uses, water quality, or other environmental resources. Substantial alteration of particular resource includes a change in the environment that substantially reduces the quality of the affected resources; and

(r) Commitment of substantial monetary resources means the expenditure of, or commitment to expend, at least 50 percent of the total cost of preparing an application for license or exemption for a hydroelectric project that is accepted for filing by the Commission pursuant to § 4.32(e) of this chapter. The total cost includes (but is not limited to) the cost of agency consultation, environmental studies, and engineering studies conducted pursuant to § 4.38 of this chapter, and the Commission's requirements for filing an application for license exemption.

(s) Sequential use of energy means:

(1) For a topping-cycle cogeneration facility, the use of reject heat from a power production process in sufficient amounts in a thermal application or process to conform to the requirements of the operating standard; or

(2) For a bottoming-cycle cogeneration facility, the use of reject heat from a thermal application or process, at least some of which is then used for power production.

(t) Electrical generating equipment means all boilers, heat recovery steam generators, prime movers (any mechanical equipment driving an electric generator), electrical generators, photovoltaic solar panels, inverters, fuel cell equipment and/or other primary power generation equipment used in the facility, excluding equipment for gathering energy to be used in the facility.

(Energy Security Act, Pub. L. 96-294, 94 Stat. 611 (1980) Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 2601, et seq., Energy Supply and Environmental Coordination Act, 15 U.S.C. 791 et seq., Federal Power Act, as amended, 16 U.S.C. 792 et seq., Department of Energy Organization Act, 42 U.S.C. 7101 et seq., E.O. 12009, 42 FR 46267)

[45 FR 17972, Mar. 20, 1980, as amended at 45 FR 33958, May 21, 1980; 45 FR 66789, Oct. 8, 1980; Order 135, 46 FR 19231, Mar. 30, 1981; 46 FR 32239, June 22, 1981; Order 499, 53 FR 27002, July 18, 1988; Order 575, 60 FR 4857, Jan. 25, 1995; Order 872, 85 FR 54732, Sept. 2, 2020; Order 874, 86 FR 8140, Feb. 4, 2021]

§ 292.203 General requirements for qualification.

(a) Small power production facilities. Except as provided in paragraph (c) of this section, a small power production facility is a qualifying facility if it:

(1) Meets the maximum size criteria specified in § 292.204(a);

(2) Meets the fuel use criteria specified in § 292.204(b); and

(3) Unless exempted by paragraph (d), has filed with the Commission a notice of self-certification, pursuant to § 292.207(a); or has filed with the Commission an application for Commission certification, pursuant to § 292.207(b)(1), that has been granted.

(b) Cogeneration facilities. A cogeneration facility, including any diesel and dual-fuel cogeneration facility, is a qualifying facility if it:

(1) Meets any applicable standards and criteria specified in §§ 292.205(a), (b) and (d); and

(2) Unless exempted by paragraph (d), has filed with the Commission a notice of self-certification, pursuant to § 292.207(a); or has filed with the Commission an application for Commission certification, pursuant to § 292.207(b)(1), that has been granted.

(c) Hydroelectric small power production facilities located at a new dam or diversion. (1) A hydroelectric small power production facility that impounds or diverts the water of a natural watercourse by means of a new dam or diversion (as that term is defined in § 292.202(p)) is a qualifying facility if it meets the requirements of:

(i) Paragraph (a) of this section; and

(ii) Section 292.208.

(2) [Reserved]

(d) Exemptions and waivers from filing requirement. (1) Any facility with a net power production capacity of 1 MW or less is exempt from the filing requirements of paragraphs (a)(3) and (b)(2) of this section.

(2) The Commission may waive the requirement of paragraphs (a)(3) and (b)(2) of this section for good cause. Any applicant seeking waiver of paragraphs (a)(3) and (b)(2) of this section must file a petition for declaratory order describing in detail the reasons waiver is being sought.

[Order 732, 75 FR 15965, Mar. 30, 2010]

§ 292.204 Criteria for qualifying small power production facilities.

(a) Size of the facility—(1) Maximum size. Except as provided in paragraph (a)(4) of this section, the power production capacity of a facility for which qualification is sought, together with the power production capacity of any other small power production qualifying facilities that use the same energy resource, are owned by the same person(s) or its affiliates, and are located at the same site, may not exceed 80 megawatts.

(2) Method of calculation. (i)(A) For purposes of this paragraph (a)(2), there is an irrebuttable presumption that affiliated small power production qualifying facilities that use the same energy resource and are located one mile or less from the facility for which qualification or recertification is sought are located at the same site as the facility for which qualification or recertification is sought.

(B) For purposes of this paragraph (a)(2), for facilities for which qualification or recertification is filed on or after December 31, 2020 there is an irrebuttable presumption that affiliated small power production qualifying facilities that use the same energy resource and are located 10 miles or more from the facility for which qualification or recertification is sought are located at separate sites from the facility for which qualification or recertification is sought.

(C) For purposes of this paragraph (a)(2), for facilities for which qualification or recertification is filed on or after December 31, 2020, there is a rebuttable presumption that affiliated small power production qualifying facilities that use the same energy resource and are located more than one mile and less than 10 miles from the facility for which qualification or recertification is sought are located at separate sites from the facility for which qualification or recertification is sought.

(D) For hydroelectric facilities, facilities are considered to be located at the same site as the facility for which qualification or recertification is sought if they are located within one mile of the facility for which qualification or recertification is sought and use water from the same impoundment for power generation.

(ii) For purposes of making the determinations in paragraph (a)(2)(i), the distance between two facilities shall be measured from the edge of the closest electrical generating equipment for which qualification or recertification is sought to the edge of the nearest electrical generating equipment of the other affiliated small power production qualifying facility using the same energy resource.

(3) Waiver. The Commission may modify the application of paragraph (a)(2) of this section, for good cause.

(4) Exception. Facilities meeting the criteria in section 3(17)(E) of the Federal Power Act (16 U.S.C. 796(17)(E)) have no maximum size, and the power production capacity of such facilities shall be excluded from consideration when determining the size of other small power production facilities less than 10 miles from such facilities.

(b) Fuel use. (1)(i) The primary energy source of the facility must be biomass, waste, renewable resources, geothermal resources, or any combination thereof, and 75 percent or more of the total energy input must be from these sources.

(ii) Any primary energy source which, on the basis of its energy content, is 50 percent or more biomass shall be considered biomass.

(2) Use of oil, natural gas and coal by a facility, under section 3(17)(B) of the Federal Power Act, is limited to the minimum amounts of fuel required for ignition, startup, testing, flame stabilization, and control uses, and the minimum amounts of fuel required to alleviate or prevent unanticipated equipment outages, and emergencies, directly affecting the public health, safety, or welfare, which would result from electric power outages. Such fuel use may not, in the aggregate, exceed 25 percent of the total energy input of the facility during the 12-month period beginning with the date the facility first produces electric energy and any calendar year subsequent to the year in which the facility first produces electric energy.

(Energy Security Act, Pub. L. 96-294, 94 Stat. 611 (1980) Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 2601, et seq., Energy Supply and Environmental Coordination Act, 15, U.S.C. 791, et seq., Federal Power Act, as amended, 16 U.S.C. 792 et seq., Department of Energy Organization Act, 42 U.S.C. 7101, et seq.; E.O. 12009, 42 FR 46267)

[45 FR 17972, Mar. 20, 1980, as amended by Order 135, 46 FR 19231, Mar. 30, 1981; Order 575, 60 FR 4857, Jan. 25, 1995; Order 732, 75 FR 15966, Mar. 30, 2010; Order 872, 85 FR 54732, Sept. 2, 2020]

§ 292.205 Criteria for qualifying cogeneration facilities.

(a) Operating and efficiency standards for topping-cycle facilities—(1) Operating standard. For any topping-cycle cogeneration facility, the useful thermal energy output of the facility must be no less than 5 percent of the total energy output during the 12-month period beginning with the date the facility first produces electric energy, and any calendar year subsequent to the year in which the facility first produces electric energy.

(2) Efficiency standard. (i) For any topping-cycle cogeneration facility for which any of the energy input is natural gas or oil, and the installation of which began on or after March 13, 1980, the useful power output of the facility plus one-half the useful thermal energy output, during the 12-month period beginning with the date the facility first produces electric energy, and any calendar year subsequent to the year in which the facility first produces electric energy, must:

(A) Subject to paragraph (a)(2)(i)(B) of this section be no less than 42.5 percent of the total energy input of natural gas and oil to the facility; or

(B) If the useful thermal energy output is less than 15 percent of the total energy output of the facility, be no less than 45 percent of the total energy input of natural gas and oil to the facility.

(ii) For any topping-cycle cogeneration facility not subject to paragraph (a)(2)(i) of this section there is no efficiency standard.

(b) Efficiency standards for bottoming-cycle facilities. (1) For any bottoming-cycle cogeneration facility for which any of the energy input as supplementary firing is natural gas or oil, and the installation of which began on or after March 13, 1980, the useful power output of the facility during the 12-month period beginning with the date the facility first produces electric energy, and any calendar year subsequent to the year in which the facility first produces electric energy must be no less than 45 percent of the energy input of natural gas and oil for supplementary firing.

(2) For any bottoming-cycle cogeneration facility not covered by paragraph (b)(1) of this section, there is no efficiency standard.

(c) Waiver. The Commission may waive any of the requirements of paragraphs (a) and (b) of this section upon a showing that the facility will produce significant energy savings.

(d) Criteria for new cogeneration facilities. Notwithstanding paragraphs (a) and (b) of this section, any cogeneration facility that was either not a qualifying cogeneration facility on or before August 8, 2005, or that had not filed a notice of self-certification or an application for Commission certification as a qualifying cogeneration facility under § 292.207 of this chapter prior to February 2, 2006, and which is seeking to sell electric energy pursuant to section 210 of the Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 824a-1, must also show:

(1) The thermal energy output of the cogeneration facility is used in a productive and beneficial manner; and

(2) The electrical, thermal, chemical and mechanical output of the cogeneration facility is used fundamentally for industrial, commercial, residential or institutional purposes and is not intended fundamentality for sale to an electric utility, taking into account technological, efficiency, economic, and variable thermal energy requirements, as well as state laws applicable to sales of electric energy from a qualifying facility to its host facility.

(3) Fundamental use test. For the purpose of satisfying paragraph (d)(2) of this section, the electrical, thermal, chemical and mechanical output of the cogeneration facility will be considered used fundamentally for industrial, commercial, or institutional purposes, and not intended fundamentally for sale to an electric utility if at least 50 percent of the aggregate of such output, on an annual basis, is used for industrial, commercial, residential or institutional purposes. In addition, applicants for facilities that do not meet this safe harbor standard may present evidence to the Commission that the facilities should nevertheless be certified given state laws applicable to sales of electric energy or unique technological, efficiency, economic, and variable thermal energy requirements.

(4) For purposes of paragraphs (d)(1) and (2) of this section, a new cogeneration facility of 5 MW or smaller will be presumed to satisfy the requirements of those paragraphs.

(5) For purposes of paragraph (d)(1) of this section, where a thermal host existed prior to the development of a new cogeneration facility whose thermal output will supplant the thermal source previously in use by the thermal host, the thermal output of such new cogeneration facility will be presumed to satisfy the requirements of paragraph (d)(1).

[45 FR 17972, Mar. 20, 1980, as amended by Order 478, 52 FR 28467, July 30, 1987; Order 575, 60 FR 4857, Jan. 25, 1995; Order 671, 71 FR 7868, Feb. 15, 2006; Order 732, 75 FR 15966, Mar. 30, 2010; 76 FR 50663, Aug. 16, 2011]

§ 292.207 Procedures for obtaining qualifying status.

(a) Self-certification—(1) FERC Form No. 556. The qualifying facility status of an existing or a proposed facility that meets the requirements of § 292.203 may be self-certified by the owner or operator of the facility or its representative by properly completing a FERC Form No. 556 and filing that form with the Commission, pursuant to § 131.80 of this chapter, and complying with paragraph (e) of this section.

(2) Factors. For small power production facilities pursuant to § 292.204, the owner or operator of the facility or its representative may, when completing the FERC Form No. 556, provide information asserting factors showing that the facility for which qualification or recertification is sought is at a separate site from other facilities using the same energy resource and owned by the same person(s) or its affiliates.

(3) Commission action. Self-certification and self-recertification are effective upon filing. If no protests to a self-certification or self-recertification are timely filed pursuant to paragraph (c) of this section, no further action by the Commission is required for a self-certification or self-recertification to be effective. If protests to a self-certification or self-recertification are timely filed pursuant to paragraph (c) of this section, a self-certification or self-recertification will remain effective until the Commission issues an order revoking QF certification. The Commission will act on the protest within 90 days from the date the protest is filed; provided that, if the Commission requests more information from the protester, the entity seeking qualification or recertification, or both, the time for the Commission to act will be extended to 60 days from the filing of a complete answer to the information request. In addition to any extension resulting from a request for information, the Commission also may toll the 90-day period for one additional 60-day period if so required to rule on a protest. Authority to toll the 90-day period for this purpose is delegated to the Secretary or the Secretary's designee. Absent Commission action before the expiration of the tolling period, a protest will be deemed denied, and the self-certification or self-recertification will remain effective.

(b) Optional procedure—Commission certification—(1) Application for Commission certification. In lieu of the self-certification procedures in paragraph (a) of this section, an owner or operator of an existing or a proposed facility, or its representative, may file with the Commission an application for Commission certification that the facility is a qualifying facility. The application must be accompanied by the fee prescribed by part 381 of this chapter, and the applicant for Commission certification must comply with paragraph (c) of this section.

(2) General contents of application. The application must include a properly completed FERC Form No. 556 pursuant to § 131.80 of this chapter. For small power production facilities pursuant to § 292.204, the owner or operator of the facility or its representative may, when completing the FERC Form No. 556, provide information asserting factors showing that the facility for which qualification is sought is at a separate site from other facilities using the same energy resource and owned by the same person(s) or its affiliates.

(3) Commission action. (i) Within 90 days of the later of the filing of an application or the filing of a supplement, amendment or other change to the application, the Commission will either: Inform the applicant that the application is deficient; or issue an order granting or denying the application; or toll the time for issuance of an order. Any order denying certification shall identify the specific requirements which were not met. If the Commission does not act within 90 days of the date of the latest filing, the application shall be deemed to have been granted.

(ii) For purposes of paragraph (b) of this section, the date an application is filed is the date by which the Office of the Secretary has received all of the information and the appropriate filing fee necessary to comply with the requirements of this Part.

(c) Protests and Interventions—(1) Filing a Protest. Any person, as defined in § 385.102(d) of this chapter, who opposes either a self-certification or self-recertification making substantive changes to the existing certification filed pursuant to paragraph (a) of this section or an application for Commission certification or Commission recertification making substantive changes to the existing certification filed pursuant to paragraph (b) of this section for which qualification or recertification is filed on or after December 31, 2020, may file a protest with the Commission. Any protest to and any intervention in a self-certification or self-recertification must be filed in accordance with §§ 385.211 and 385.214 of this chapter, on or before 30 days from the date the self-certification or self-recertification is filed. Any protestor must concurrently serve a copy of such filing pursuant to § 385.211 of this chapter. Any protest must be adequately supported, and provide any supporting documents, contracts, or affidavits to substantiate the claims in the protest.

(2) Limitations on protest. Protests may be filed to any initial self-certification or application for Commission certification filed on or after the effective date of this final rule, and to any self-recertification or application for Commission recertification that are filed on or after December 31, 2020 that makes substantive changes to the existing certification. Once the Commission has certified an applicant's qualifying facility status either in response to a protest opposing a self-certification or self-recertification, or in response to an application for Commission certification or Commission recertification, any later protest to a self-recertification or application for Commission recertification making substantive changes to a qualifying facility's certification must demonstrate changed circumstances that call into question the continued validity of the certification.

(d) Response to protests. Any response to a protest must be filed on or before 30 days from the date of filing of that protest and will be allowed under § 385.213(a)(2) of this chapter.

(e) Notice requirements—(1) General. An applicant filing a self-certification, self-recertification, application for Commission certification or application for Commission recertification of the qualifying status of its facility must concurrently serve a copy of such filing on each electric utility with which it expects to interconnect, transmit or sell electric energy to, or purchase supplementary, standby, back-up or maintenance power from, and the State regulatory authority of each state where the facility and each affected electric utility is located. The Commission will publish a notice in the Federal Register for each application for Commission certification and for each self-certification of a cogeneration facility that is subject to the requirements of § 292.205(d).

(2) Facilities of 500 kW or more. An electric utility is not required to purchase electric energy from a facility with a net power production capacity of 500 kW or more until 90 days after the facility notifies the facility that it is a qualifying facility or 90 days after the utility meets the notice requirements in paragraph (c)(1) of this section.

(f) Revocation of qualifying status. (1)(i) If a qualifying facility fails to conform with any material facts or representations presented by the cogenerator or small power producer in its submittals to the Commission, the notice of self-certification or Commission order certifying the qualifying status of the facility may no longer be relied upon. At that point, if the facility continues to conform to the Commission's qualifying criteria under this part, the cogenerator or small power producer may file either a notice of self-recertification of qualifying status pursuant to the requirements of paragraph (a) of this section, or an application for Commission recertification pursuant to the requirements of paragraph (b) of this section, as appropriate.

(ii) The Commission may, on its own motion or on the motion of any person, revoke the qualifying status of a facility that has been certified under paragraph (b) of this section, if the facility fails to conform to any of the Commission's qualifying facility criteria under this part.

(iii) The Commission may, on its own motion or on the motion of any person, revoke the qualifying status of a self-certified or self-recertified qualifying facility if it finds that the self-certified or self-recertified qualifying facility does not meet the applicable requirements for qualifying facilities.

(2) Prior to undertaking any substantial alteration or modification of a qualifying facility which has been certified under paragraph (b) of this section, a small power producer or cogenerator may apply to the Commission for a determination that the proposed alteration or modification will not result in a revocation of qualifying status. This application for Commission recertification of qualifying status should be submitted in accordance with paragraph (b) of this section.

[45 FR 17972, Mar. 20, 1980]

Editorial Note:For Federal Register citations affecting § 292.207, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 292.208 Special requirements for hydroelectric small power production facilities located at a new dam or diversion.

(a) A hydroelectric small power production facility that impounds or diverts the water of a natural watercourse by means of a new dam or diversion (as that term is defined in § 292.202(p)) is a qualifying facility only if it meets the requirements of:

(1) Paragraph (b) of this section;

(2) Section 292.203(c); and

(3) Part 4 of this chapter.

(b) A hydroelectric small power production described in paragraph (a) is a qualifying facility only if:

(1) The Commission finds, at the time it issues the license or exemption, that the project will not have a substantial adverse effect on the environment (as that term is defined in § 292.202(q)), including recreation and water quality;

(2) The Commission finds, at the time the application for the license or exemption is accepted for filing under § 4.32 of this chapter, that the project is not located on any segment of a natural watercourse which:

(i) Is included, or designated for potential inclusion in, a State or National wild and scenic river system; or

(ii) The State has determined, in accordance with applicable State law, to possess unique natural, recreational, cultural or scenic attributes which would be adversely affected by hydroelectric development; and

(3) The project meets the terms and conditions set by the appropriate fish and wildlife agencies under the same procedures as provided for under section 30(c) of the Federal Power Act.

(c) For the Commission to make the findings in paragraph (b) of this section an applicant must:

(1) Comply with the applicable hydroelectric licensing requirements in Part 4 of this chapter, including:

(i) Completing the pre-filing consultation process under § 4.38 of this chapter, including performing any environmental studies which may be required under §§ 4.38(b)(2)(i)(D) through (F) of this chapter; and

(ii) Submitting with its application an environmental report that meets the requirements of § 4.41(f) of this chapter, regardless of project size;

(2) State whether the project is located on any segment of a natural watercourse which:

(i) Is included in or designated for potential inclusion in:

(A) The National Wild and Scenic River System (28 U.S.C. 1271-1278 (1982)); or

(B) A State wild and scenic river system;

(ii) Crosses an area designated or recommended for designation under the Wilderness Act (16 U.S.C. 1132) as:

(A) A wilderness area; or

(B) Wilderness study area; or

(iii) The State, either by or pursuant to an act of the State legislature, has determined to possess unique, natural, recreational, cultural, or scenic attributes that would be adversely affected by hydroelectric development.

(d) If the project is located on any segment of a natural watercourse that meets any of the conditions in paragraph (c)(2) of this section, the applicant must provide the following information in its application:

(1) The date on which the natural watercourse was protected;

(2) The statutory authority under which the natural watercourse was protected; and

(3) The Federal or state agency, or political subdivision of the state, that is in charge of administering the natural watercourse.

[Order 499, 53 FR 27003, July 18, 1988]

§ 292.209 Exceptions from requirements for hydroelectric small power production facilities located at a new dam or diversion.

(a) The requirements in §§ 292.208(b)(1) through (3) do not apply if:

(1) An application for license or exemption is filed for a project located at a Government dam, as defined in section 3(10) of the Federal Power Act, at which non-Federal hydroelectric development is permissible; or

(2) An application for license or exemption was filed and accepted before October 16, 1986.

(b) The requirements in §§ 292.208(b) (1) and (3) do not apply if an application for license or exemption was filed before October 16, 1986, and is accepted for filing by the Commission before October 16, 1989.

(c) The requirements in § 292.208(b)(3) do not apply to an applicant for license or exemption if:

(1) The applicant files a petition pursuant to § 292.210; and

(2) The Commission grants the petition.

(d) Any application covered by paragraph (a), (b), or (c) of this section is excepted from the moratorium imposed by section 8(e) of the Electric Consumers Protection Act of 1986, Pub. L. No. 99-495.

[Order 499, 53 FR 27003, July 18, 1988]

§ 292.210 Petition alleging commitment of substantial monetary resources before October 16, 1986.

(a) An applicant covered by § 292.203(c) whose application for license or exemption was filed on or after October 16, 1986, but before April 16, 1988, may file a petition for exception from the requirement in § 292.208(b)(3) and the moratorium described in § 292.203(c)(2). The petition must show that prior to October 16, 1986, the applicant committed substantial monetary resources (as that term is defined in § 292.202(r)) to the development of the project.

(b) Subject to rebuttal under paragraph (d)(7)(ii) of this section, a showing of the commitment of substantial monetary resources will be presumed if the applicant held a preliminary permit for the project and had completed environmental consultations pursuant to § 4.38 of this chapter before October 16, 1986.

(c) Time of filing petition—(1) General rule. Except as provided in paragraph (c)(2) of this section, the applicant must:

(i) File the petition with the application for license or exemption; or

(ii) Submit with the application for license or exemption a request for an extension of time, not to exceed 90 days or April 16, 1988, whichever occurs first, in which to file the petition.

(2) Exception. If the application for license or exemption was filed on or after October 16, 1986, but before March 23, 1987, the petition must have been filed by June 22, 1987.

(d) Filing requirements. A petition filed under this section must include the following information or refer to the pages in the application for license or exemption where it can be found:

(1) A certificate of service, conforming to the requirements set out in § 385.2010(h) of this chapter, certifying that the applicant has served the petition on the Federal and State agencies required to be consulted by the applicant pursuant to § 4.38 of this chapter;

(2) Documentation of any issued preliminary permits for the project;

(3) An itemized statement of the total costs expended on the application;

(4) An itemized schedule of costs the applicant expended, or committed to be expended, before October 16, 1986, on the application, accompanied by supporting documentation including but not limited to:

(i) Dated invoices for maps, surveys, supplies, geophysical and geotechnical services, engineering services, legal services, document reproduction, and other items related to the preparation of the application, and

(ii) Written contracts and other written documentation demonstrating a commitment made before October 16, 1986, to expend monetary resources on the preparation of the application, together with evidence that those monetary resources were actually expended; and

(5) Correspondence or other documentation to support the items listed in paragraphs (d)(3) and (d)(4) of this section to show that the expenses presented were directly related to the preparation of the application.

(6) The applicant must include in its total cost statement and in its schedule of the costs expended or committed to be expended before October 16, 1986, the value of services that were performed by the applicant itself instead of contracted out.

(7)(i) If the applicant held a preliminary permit for the project and had completed pre-filing consultation pursuant to § 4.38 of this chapter prior to October 16, 1986, the applicant may, instead of submitting the information listed in paragraphs (d)(3), (d)(4), and (d)(5) of this section, submit a statement identifying the preliminary permit by project number.

(ii) If any interested person objects (pursuant to § 385.211 of this chapter) to the presumption in paragraph (b) of this section, the applicant must supply the information listed in paragraphs (d)(3), (d)(4), and (d)(5) of this section.

(8) If the application is deficient pursuant to § 4.32(e) of this chapter, the applicant must include with the information correcting those deficiencies a statement of the costs expended to make the corrections.

(e) Processing of petition. (1) The Commission will issue a notice of the petition filed under this section and publish the notice in the Federal Register. The petition will be available to inspect or to download on the Commission's website, https://www.ferc.gov.

(2) Comments on the petition. The Commission will provide the public 45 days from the date the notice of the petition is issued to submit comments. The applicant for license or exemption has 15 days after the expiration of the public comment period to respond to the comments filed with the Commission.

(3) Commission action on petition. The Director of the Office of Energy Projects will determine whether or not the applicant for license or exemption has made the showing required under this section.

[Order 499, 53 FR 27003, July 18, 1988, as amended by Order 699, 72 FR 45325, Aug. 14, 2007; Order 899, 88 FR 74032, Oct. 30, 2023]

§ 292.211 Petition for initial determination on whether a project has a substantial adverse effect on the environment (AEE petition).

(a) An applicant that has filed a petition under § 292.210 may also file an AEE petition with the Commission for an initial determination on whether the project satisfies the requirement that it has no substantial adverse effect on the environment as specified in § 292.208(b)(1).

(b) The filing of the AEE petition does not relieve the applicant of the filing requirements of § 292.208(c).

(c) The Commission will act on the AEE petition only if the Commission has granted the applicant's commitment of resources petition under § 292.210.

(d) Time of filing petition. The applicant may file the AEE petition with the application for license or exemption or at any time before the Commission issues the license or exemption.

(e) Contents of petition. The AEE petition must identify the project and request that the Commission make an initial determination on the adverse environmental effects requirements in § 292.208(b)(1).

(f) The Director of the Office of Energy Projects will make the initial determination on the AEE petition. In making this determination, the Director will consider the following:

(1) Any proposed mitigative measures;

(2) The consistency of the proposal with local, regional, and national resource plans and programs;

(3) The mandatory terms and conditions of fish and wildlife agencies under section 210(j) of PURPA, or section 30(c) of the Federal Power Act; or the recommended terms and conditions of fish a wildlife agencies under Section 10(j) of the Federal Power Act, whichever is appropriate; and

(4) Any other information which the Director believes is relevant to consider.

(g) Initial finding on the petition. The Director of the Office of Energy Projects will make the initial determination on the AEE petition after the close of the public notice period for the accepted application. If the Director's initial determination finds:

(1) No substantial adverse effect on the environment, the Commission must wait at least 45 days before making a final determination that the project satisfies the requirements of § 292.208(b)(1).

(2) A substantial adverse effect on the environment, the applicant may file, within 90 days of the initial finding that the project does not satisfy the requirements in § 292.208(b)(1), proposed measures to mitigate the adverse environmental effects found.

(3)(i) The Commission will provide written notice of the Director's initial finding on the petition to the applicant, to the federal and state agencies that the applicant must consult under § 4.38 of this chapter and to any intervenors in the proceeding.

(ii) The Commission will publish notice of the Director's initial finding in the Federal Register.

(h) Notice and comment on the mitigative measures. (1) The Commission will issue notice of the mitigative measures filed by an applicant under paragraph (g)(2) of this section and will publish the notice in the Federal Register. The mitigative measures will be on file and available to inspect or to download on the Commission's website, https://www.ferc.gov.

(2) The Commission will provide the State and interested persons within 90 days from the date the notice is issued to review and submit comments on the mitigative measures. The applicant for license or exemption has 15 days after the expiration of the public comment period to respond to the comments filed with the Commission.

(i) Material amendments to application. The proposed mitigative measures filed under paragraph (g)(2) of this section will not be considered a material amendment to the application unless the Commission finds that the proposed measures are unnecessary to, or exceed the scope of, mitigating substantial adverse effects. If the Commission finds the proposed mitigative measures constitute a material amendment, the application will be considered filed with the Commission on the date on which the applicant filed the proposed mitigative measures, and all other provisions of § 4.35(a) of this chapter will apply.

(j) Final determination on the petition. The Commission will make a final determination on the petition at the time the Commission issues a license or exemption for the project.

(k) Presumption. (1) If, between the Commission's initial and final findings on the AEE petition, the State does not take any action under § 292.208(b)(2), the failure to take action can be the basis for a presumption that there is not substantial adverse effect on the environment (as that term is defined in § 292.202(q)).

(2) If the presumption in paragraph (k)(1) of this section comes into effect, it:

(i) Is only available for those adverse effects related to the natural, recreational, cultural, or scenic attributes of the environment;

(ii) Can only operate during the time between the Commission's initial and final findings on the AEE petition; and

(iii) Has no affect on the Commission's independent obligation to find that the project will not have a substantial adverse effect on the environment under § 292.208(b)(1).

(3) The presumption in paragraph (k)(1) of this section does not take effect if the State, the Commission or an interested person demonstrates that the State has acted to protect the natural watercourse under § 292.208(b)(2).

(4) The presumption in paragraph (k)(1) of this section can be rebutted if:

(i) The Commission determines that the project will have a substantial adverse effect on the environment related to the environmental attributes listed in paragraph (k)(2)(i) of this section; or

(ii) Any interested person, including a State, demonstrates that the project will have a substantial adverse effect on the environment related to the environmental attributes listed in paragraph (k)(2)(i) of this section.

[Order 499, 53 FR 27004, July 18, 1988, as amended by Order 499-A, 53 FR 40724, Oct. 18, 1988; Order 699, 72 FR 45325, Aug. 14, 2007; Order 899, 88 FR 74032, Oct. 30, 2023]

§ 292.301 Scope.

(a) Applicability. This subpart applies to the regulation of sales and purchases between qualifying facilities and electric utilities.

(b) Negotiated rates or terms. Nothing in this subpart:

(1) Limits the authority of any electric utility or any qualifying facility to agree to a rate for any purchase, or terms or conditions relating to any purchase, which differ from the rate or terms or conditions which would otherwise be required by this subpart; or

(2) Affects the validity of any contract entered into between a qualifying facility and an electric utility for any purchase.

§ 292.302 Availability of electric utility system cost data.

(a) Applicability. (1) Except as provided in paragraph (a)(2) of this section, paragraph (b) applies to each electric utility, in any calendar year, if the total sales of electric energy by such utility for purposes other than resale exceeded 500 million kilowatt-hours during any calendar year beginning after December 31, 1975, and before the immediately preceding calendar year.

(2) Each utility having total sales of electric energy for purposes other than resale of less than one billion kilowatt-hours during any calendar year beginning after December 31, 1975, and before the immediately preceding year, shall not be subject to the provisions of this section until June 30, 1982.

(b) General rule. To make available data from which avoided costs may be derived, not later than November 1, 1980, June 30, 1982, and not less often than every two years thereafter, each regulated electric utility described in paragraph (a) of this section shall provide to its State regulatory authority, and shall maintain for public inspection, and each nonregulated electric utility described in paragraph (a) of this section shall maintain for public inspection, the following data:

(1) The estimated avoided cost on the electric utility's system, solely with respect to the energy component, for various levels of purchases from qualifying facilities. Such levels of purchases shall be stated in blocks of not more than 100 megawatts for systems with peak demand of 1000 megawatts or more, and in blocks equivalent to not more than 10 percent of the system peak demand for systems of less than 1000 megawatts. The avoided costs shall be stated on a cents per kilowatt-hour basis, during daily and seasonal peak and off-peak periods, by year, for the current calendar year and each of the next 5 years;

(2) The electric utility's plan for the addition of capacity by amount and type, for purchases of firm energy and capacity, and for capacity retirements for each year during the succeeding 10 years; and

(3) The estimated capacity costs at completion of the planned capacity additions and planned capacity firm purchases, on the basis of dollars per kilowatt, and the associated energy costs of each unit, expressed in cents per kilowatt hour. These costs shall be expressed in terms of individual generating units and of individual planned firm purchases.

(c) Special rule for small electric utilities. (1) Each electric utility (other than any electric utility to which paragraph (b) of this section applies) shall, upon request:

(i) Provide comparable data to that required under paragraph (b) of this section to enable qualifying facilities to estimate the electric utility's avoided costs for periods described in paragraph (b) of this section; or

(ii) With regard to an electric utility which is legally obligated to obtain all its requirements for electric energy and capacity from another electric utility, provide the data of its supplying utility and the rates at which it currently purchases such energy and capacity.

(2) If any such electric utility fails to provide such information on request, the qualifying facility may apply to the State regulatory authority (which has ratemaking authority over the electric utility) or the Commission for an order requiring that the information be provided.

(d) Substitution of alternative method. (1) After public notice in the area served by the electric utility, and after opportunity for public comment, any State regulatory authority may require (with respect to any electric utility over which it has ratemaking authority), or any non-regulated electric utility may provide, data different than those which are otherwise required by this section if it determines that avoided costs can be derived from such data.

(2) Any State regulatory authority (with respect to any electric utility over which it has ratemaking authority) or nonregulated utility which requires such different data shall notify the Commission within 30 days of making such determination.

(e) State Review. (1) Any data submitted by an electric utility under this section shall be subject to review by the State regulatory authority which has ratemaking authority over such electric utility.

(2) In any such review, the electric utility has the burden of coming forward with justification for its data.

[45 FR 12234, Feb. 25, 1980; 45 FR 24126, Apr. 9, 1980]

§ 292.303 Electric utility obligations under this subpart.

(a) Obligation to purchase from qualifying facilities. Each electric utility shall purchase, in accordance with § 292.304, unless exempted by § 292.309 and § 292.310, any energy and capacity which is made available from a qualifying facility:

(1) Directly to the electric utility; or

(2) Indirectly to the electric utility in accordance with paragraph (d) of this section.

(b) Obligation to sell to qualifying facilities. Each electric utility shall sell to any qualifying facility, in accordance with § 292.305, unless exempted by § 292.312, energy and capacity requested by the qualifying facility.

(c) Obligation to interconnect. (1) Subject to paragraph (c)(2) of this section, any electric utility shall make such interconnection with any qualifying facility as may be necessary to accomplish purchases or sales under this subpart. The obligation to pay for any interconnection costs shall be determined in accordance with § 292.306.

(2) No electric utility is required to interconnect with any qualifying facility if, solely by reason of purchases or sales over the interconnection, the electric utility would become subject to regulation as a public utility under part II of the Federal Power Act.

(d) Transmission to other electric utilities. If a qualifying facility agrees, an electric utility which would otherwise be obligated to purchase energy or capacity from such qualifying facility may transmit the energy or capacity to any other electric utility. Any electric utility to which such energy or capacity is transmitted shall purchase such energy or capacity under this subpart as if the qualifying facility were supplying energy or capacity directly to such electric utility. The rate for purchase by the electric utility to which such energy is transmitted shall be adjusted up or down to reflect line losses pursuant to § 292.304(e)(4) and shall not include any charges for transmission.

(e) Parallel operation. Each electric utility shall offer to operate in parallel with a qualifying facility, provided that the qualifying facility complies with any applicable standards established in accordance with § 292.308.

[Order 688, 71 FR 64372, Nov. 1, 2006; 71 FR 75662, Dec. 18, 2006]

§ 292.304 Rates for purchases.

(a) Rates for purchases. (1) Rates for purchases shall:

(i) Be just and reasonable to the electric consumer of the electric utility and in the public interest; and

(ii) Not discriminate against qualifying cogeneration and small power production facilities.

(2) Nothing in this subpart requires any electric utility to pay more than the avoided costs for purchases.

(b) Relationship to avoided costs. (1) For purposes of this paragraph, “new capacity” means any purchase from capacity of a qualifying facility, construction of which was commenced on or after November 9, 1978.

(2) Subject to paragraph (b)(3) of this section, a rate for purchases satisfies the requirements of paragraph (a) of this section if the rate equals the avoided costs determined after consideration of the factors set forth in paragraph (e) of this section

(3) A rate for purchases (other than from new capacity) may be less than the avoided cost if the State regulatory authority (with respect to any electric utility over which it has ratemaking authority) or the nonregulated electric utility determines that a lower rate is consistent with paragraph (a) of this section, and is sufficient to encourage cogeneration and small power production.

(4) Rates for purchases from new capacity shall be in accordance with paragraph (b)(2) of this section, regardless of whether the electric utility making such purchases is simultaneously making sales to the qualifying facility.

(5) In the case in which the rates for purchases are based upon estimates of avoided costs over the specific term of the contract or other legally enforceable obligation, the rates for such purchases do not violate this subpart if the rates for such purchases differ from avoided costs at the time of delivery.

(6) Locational Marginal Price. There is a rebuttable presumption that a state regulatory authority or nonregulated electric utility may use a Locational Marginal Price as a rate for as-available qualifying facility energy sales to electric utilities located in a market defined in § 292.309(e), (f), or (g).

(7) Competitive Price. A state regulatory authority or nonregulated electric utility may use a Competitive Price as a rate for as-available qualifying facility energy sales to electric utilities located outside a market defined in § 292.309(e), (f), or (g). A Competitive Price may be either a Market Hub Price or a Combined Cycle Price, determined as follows:

(i) A Market Hub Price is a price established at a liquid market hub which a state regulatory authority or nonregulated electric utility determines represents an appropriate measure of the electric utility's avoided cost for as-available energy, and is a hub to which the electric utility has reasonable access, based on an evaluation by the state regulatory authority or nonregulated electric utility of the relevant factors, including but not limited to the following:

(A) Whether the hub is sufficiently liquid that prices at the hub represent a competitive price;

(B) Whether prices developed at the hub are sufficiently transparent;

(C) Whether the electric utility has the ability to deliver power from such hub to its load, even if its load is not directly connected to the hub; and

(D) Whether the hub represents an appropriate market to derive an energy price for the electric utility's purchases from the relevant qualifying facility given the electric utility's physical proximity to the hub or other factors.

(ii) A Combined Cycle Price is a price determined pursuant to a formula established by a state regulatory authority or nonregulated electric utility using published natural gas price indices, a proxy heat rate, and variable operations and maintenance costs for an efficient natural gas combined-cycle generating facility. Before establishing such a formula rate, a state regulatory authority or nonregulated electric utility must determine that the resulting Combined Cycle Price represents an appropriate measure of the purchasing electric utility's avoided cost for energy, based on its evaluation of the relevant factors, including but not limited to the following:

(A) Whether the cost of energy from an efficient natural gas combined cycle generating facility represents a reasonable measure of a competitive price in the purchasing electric utility's region;

(B) Whether natural gas priced pursuant to particular proposed natural gas price indices would be available in the relevant market;

(C) Whether there should be an adjustment to the natural gas price to appropriately reflect the cost of transporting natural gas to the relevant market; and

(D) Whether the proxy heat rate used in the formula should be updated regularly to reflect improvements in generation technology.

(8) Competitive Solicitation Price. (i) A state regulatory authority or nonregulated electric utility may use a price determined pursuant to a competitive solicitation process to establish qualifying facility energy and/or capacity rates for sales to electric utilities, provided that such competitive solicitation process is conducted pursuant to procedures ensuring the solicitation is conducted in a transparent and non-discriminatory manner including, but not limited to, the following:

(A) The solicitation process is an open and transparent process that includes, but is not limited to, providing equally to all potential bidders substantial and meaningful information regarding transmission constraints, levels of congestion, and interconnections, subject to appropriate confidentiality safeguards;

(B) Solicitations are open to all sources, to satisfy that electric utility's capacity needs, taking into account the required operating characteristics of the needed capacity;

(C) Solicitations are conducted at regular intervals;

(D) Solicitations are subject to oversight by an independent administrator; and

(E) Solicitations are certified as fulfilling the above criteria by the relevant state regulatory authority or nonregulated electric utility through a post-solicitation report.

(ii) To the extent that the electric utility procures all of its capacity, including capacity resources constructed or otherwise acquired by the electric utility, through a competitive solicitation process conducted pursuant to paragraph (b)(8)(i) of this section, the electric utility shall be presumed to have no avoided capacity costs unless and until it determines to acquire capacity outside of such competitive solicitation process. However, the electric utility shall nevertheless be required to purchase energy from qualifying small power producers and qualifying cogeneration facilities.

(iii) To the extent that the electric utility does not procure all of its capacity through a competitive solicitation process conducted pursuant to paragraph (b)(8)(i) of this section, then there shall be no presumption that the electric utility has no avoided capacity costs.

(c) Standard rates for purchases. (1) There shall be put into effect (with respect to each electric utility) standard rates for purchases from qualifying facilities with a design capacity of 100 kilowatts or less.

(2) There may be put into effect standard rates for purchases from qualifying facilities with a design capacity of more than 100 kilowatts.

(3) The standard rates for purchases under this paragraph:

(i) Shall be consistent with paragraphs (a) and (e) of this section; and

(ii) May differentiate among qualifying facilities using various technologies on the basis of the supply characteristics of the different technologies.

(d) Purchases “as available” or pursuant to a legally enforceable obligation. (1) Each qualifying facility shall have the option either:

(i) To provide energy as the qualifying facility determines such energy to be available for such purchases, in which case the rates for such purchases shall be based on the electric utility's avoided cost for energy calculated at the time of delivery; or

(ii) To provide energy or capacity pursuant to a legally enforceable obligation for the delivery of energy or capacity over a specified term, in which case the rates for such purchases shall, except as provided in paragraph (d)(2) of this section, be based on either:

(A) The avoided costs calculated at the time of delivery; or

(B) The avoided costs calculated at the time the obligation is incurred.

(iii) The rate for delivery of energy calculated at the time the obligation is incurred may be based on estimates of the present value of the stream of revenue flows of future locational marginal prices, or Competitive Prices during the anticipated period of delivery.

(2) Notwithstanding paragraph (d)(1)(ii)(B) of this section, a state regulatory authority or nonregulated electric utility may require that rates for purchases of energy from a qualifying facility pursuant to a legally enforceable obligation vary through the life of the obligation, and be set at the electric utility's avoided cost for energy calculated at the time of delivery.

(3) Obtaining a legally enforceable obligation. A qualifying facility must demonstrate commercial viability and financial commitment to construct its facility pursuant to criteria determined by the state regulatory authority or nonregulated electric utility as a prerequisite to a qualifying facility obtaining a legally enforceable obligation. Such criteria must be objective and reasonable.

(e) Factors affecting rates for purchases. (1) A state regulatory authority or nonregulated electric utility may establish rates for purchases of energy from a qualifying facility based on a purchasing electric utility's locational marginal price calculated by the applicable market defined in § 292.309(e), (f), or (g), or the purchasing electric utility's applicable Competitive Price. Alternatively, a state regulatory authority or nonregulated electric utility may establish rates for purchases of energy and/or capacity from a qualifying facility based on a Competitive Solicitation Price. To the extent that capacity rates are not set pursuant to this section, capacity rates shall be set pursuant to subsection (2).

(2) To the extent that a state regulatory authority or nonregulated electric utility does not set energy and/or capacity rates pursuant to paragraph (e)(1) of this section, the following factors shall, to the extent practicable, be taken into account in determining rates for purchases from a qualifying facility:

(i) The data provided pursuant to § 292.302(b), (c), or (d), including State review of any such data;

(ii) The availability of capacity or energy from a qualifying facility during the system daily and seasonal peak periods, including:

(A) The ability of the electric utility to dispatch the qualifying facility;

(B) The expected or demonstrated reliability of the qualifying facility;

(C) The terms of any contract or other legally enforceable obligation, including the duration of the obligation, termination notice requirement and sanctions for non-compliance;

(D) The extent to which scheduled outages of the qualifying facility can be usefully coordinated with scheduled outages of the electric utility's facilities;

(E) The usefulness of energy and capacity supplied from a qualifying facility during system emergencies, including its ability to separate its load from its generation;

(F) The individual and aggregate value of energy and capacity from qualifying facilities on the electric utility's system; and

(G) The smaller capacity increments and the shorter lead times available with additions of capacity from qualifying facilities; and

(iii) The relationship of the availability of energy or capacity from the qualifying facility as derived in paragraph (e)(2)(ii) of this section, to the ability of the electric utility to avoid costs, including the deferral of capacity additions and the reduction of fossil fuel use; and

(iv) The costs or savings resulting from variations in line losses from those that would have existed in the absence of purchases from a qualifying facility, if the purchasing electric utility generated an equivalent amount of energy itself or purchased an equivalent amount of electric energy or capacity.

(f) Periods during which purchases not required. (1) Any electric utility which gives notice pursuant to paragraph (f)(2) of this section will not be required to purchase electric energy or capacity during any period during which, due to operational circumstances, purchases from qualifying facilities will result in costs greater than those which the utility would incur if it did not make such purchases, but instead generated an equivalent amount of energy itself.

(2) Any electric utility seeking to invoke paragraph (f)(1) of this section must notify, in accordance with applicable State law or regulation, each affected qualifying facility in time for the qualifying facility to cease the delivery of energy or capacity to the electric utility.

(3) Any electric utility which fails to comply with the provisions of paragraph (f)(2) of this section will be required to pay the same rate for such purchase of energy or capacity as would be required had the period described in paragraph (f)(1) of this section not occurred.

(4) A claim by an electric utility that such a period has occurred or will occur is subject to such verification by its State regulatory authority as the State regulatory authority determines necessary or appropriate, either before or after the occurrence.

[Order 69, 45 FR 12234, Feb. 25, 1980, as amended by Order 872, 85 FR 54733, Sept. 2, 2020]

§ 292.305 Rates for sales.

(a) General rules. (1) Rates for sales:

(i) Shall be just and reasonable and in the public interest; and

(ii) Shall not discriminate against any qualifying facility in comparison to rates for sales to other customers served by the electric utility.

(2) Rates for sales which are based on accurate data and consistent systemwide costing principles shall not be considered to discriminate against any qualifying facility to the extent that such rates apply to the utility's other customers with similar load or other cost-related characteristics.

(b) Additional services to be provided to qualifying facilities. (1) Upon request of a qualifying facility, each electric utility shall provide:

(i) Supplementary power;

(ii) Back-up power;

(iii) Maintenance power; and

(iv) Interruptible power.

(2) The State regulatory authority (with respect to any electric utility over which it has ratemaking authority) and the Commission (with respect to any nonregulated electric utility) may waive any requirement of paragraph (b)(1) of this section if, after notice in the area served by the electric utility and after opportunity for public comment, the electric utility demonstrates and the State regulatory authority or the Commission, as the case may be, finds that compliance with such requirement will:

(i) Impair the electric utility's ability to render adequate service to its customers; or

(ii) Place an undue burden on the electric utility.

(c) Rates for sales of back-up and maintenance power. The rate for sales of back-up power or maintenance power:

(1) Shall not be based upon an assumption (unless supported by factual data) that forced outages or other reductions in electric output by all qualifying facilities on an electric utility's system will occur simultaneously, or during the system peak, or both; and

(2) Shall take into account the extent to which scheduled outages of the qualifying facilities can be usefully coordinated with scheduled outages of the utility's facilities.

§ 292.306 Interconnection costs.

(a) Obligation to pay. Each qualifying facility shall be obligated to pay any interconnection costs which the State regulatory authority (with respect to any electric utility over which it has ratemaking authority) or nonregulated electric utility may assess against the qualifying facility on a nondiscriminatory basis with respect to other customers with similar load characteristics.

(b) Reimbursement of interconnection costs. Each State regulatory authority (with respect to any electric utility over which it has ratemaking authority) and nonregulated utility shall determine the manner for payments of interconnection costs, which may include reimbursement over a reasonable period of time.

§ 292.307 System emergencies.

(a) Qualifying facility obligation to provide power during system emergencies. A qualifying facility shall be required to provide energy or capacity to an electric utility during a system emergency only to the extent:

(1) Provided by agreement between such qualifying facility and electric utility; or

(2) Ordered under section 202(c) of the Federal Power Act.

(b) Discontinuance of purchases and sales during system emergencies. During any system emergency, an electric utility may discontinue:

(1) Purchases from a qualifying facility if such purchases would contribute to such emergency; and

(2) Sales to a qualifying facility, provided that such discontinuance is on a nondiscriminatory basis.

§ 292.308 Standards for operating reliability.

Any State regulatory authority (with respect to any electric utility over which it has ratemaking authority) or nonregulated electric utility may establish reasonable standards to ensure system safety and reliability of interconnected operations. Such standards may be recommended by any electric utility, any qualifying facility, or any other person. If any State regulatory authority (with respect to any electric utility over which it has ratemaking authority) or nonregulated electric utility establishes such standards, it shall specify the need for such standards on the basis of system safety and reliability.

§ 292.309 Termination of obligation to purchase from qualifying facilities.

(a) After August 8, 2005, an electric utility shall not be required, under this part, to enter into a new contract or obligation to purchase electric energy from a qualifying cogeneration facility or a qualifying small power production facility if the Commission finds that the qualifying cogeneration facility or qualifying small power facility production has nondiscriminatory access to:

(1)(i) Independently administered, auction-based day ahead and real time wholesale markets for the sale of electric energy; and

(ii) Wholesale markets for long-term sales of capacity and electric energy; or

(2)(i) Transmission and interconnection services that are provided by a Commission-approved regional transmission entity and administered pursuant to an open access transmission tariff that affords nondiscriminatory treatment to all customers; and

(ii) Competitive wholesale markets that provide a meaningful opportunity to sell capacity, including long-term and short-term sales, and electric energy, including long-term, short-term and real-time sales, to buyers other than the utility to which the qualifying facility is interconnected. In determining whether a meaningful opportunity to sell exists, the Commission shall consider, among other factors, evidence of transactions within the relevant market; or

(3) Wholesale markets for the sale of capacity and electric energy that are, at a minimum, of comparable competitive quality as markets described in paragraphs (a)(1) and (a)(2) of this section.

(b) For purposes of § 292.309(a), a renewal of a contract that expires by its own terms is a “new contract or obligation” without a continuing obligation to purchase under an expired contract.

(c) For purposes of paragraphs (a)(1), (2) and (3) of this section, with the exception of paragraph (d) of this section, there is a rebuttable presumption that a qualifying facility has nondiscriminatory access to the market if it is eligible for service under a Commission-approved open access transmission tariff or Commission-filed reciprocity tariff, and Commission-approved interconnection rules.

(1) If the Commission determines that a market meets the criteria of paragraphs (a)(1), (2) or (3) of this section, and if a qualifying facility in the relevant market is eligible for service under a Commission-approved open access transmission tariff or Commission-filed reciprocity tariff, a qualifying facility may seek to rebut the presumption of access to the market by demonstrating, inter alia, that it does not have access to the market because of operational characteristics or transmission constraints.

(2) For purposes of paragraphs (a)(1), (2), and (3) of this section, a qualifying small power production facility with a capacity between 5 megawatts and 20 megawatts may additionally seek to rebut the presumption of access to the market by demonstrating that it does not have access to the market in light of consideration of other factors, including, but not limited to:

(i) Specific barriers to connecting to the interstate transmission grid, such as excessively high costs and pancaked delivery rates;

(ii) Unique circumstances impacting the time or length of interconnection studies or queues to process the small power production facility's interconnection request;

(iii) A lack of affiliation with entities that participate in the markets in paragraphs (a)(1), (2), and (3) of this section;

(iv) The qualifying small power production facility has a predominant purpose other than selling electricity and should be treated similarly to qualifying cogeneration facilities;

(v) The qualifying small power production facility has certain operational characteristics that effectively prevent the qualifying facility's participation in a market; or

(vi) The qualifying small power production facility lacks access to markets due to transmission constraints. The qualifying small power production facility may show that it is located in an area where persistent transmission constraints in effect cause the qualifying facility not to have access to markets outside a persistently congested area to sell the qualifying facility output or capacity.

(d)(1) For purposes of paragraphs (a)(1), (2), and (3) of this section, there is a rebuttable presumption that a qualifying cogeneration facility with a capacity at or below 20 megawatts does not have nondiscriminatory access to the market.

(2) For purposes of paragraphs (a)(1), (2), and (3) of this section, there is a rebuttable presumption that a qualifying small power production facility with a capacity at or below 5 megawatts does not have nondiscriminatory access to the market.

(3) Nothing in paragraphs (d)(1) through (3) affects the rights the rights or remedies of any party under any contract or obligation, in effect or pending approval before the appropriate State regulatory authority or non-regulated electric utility on or before February 16, 2021, to purchase electric energy or capacity from or to sell electric energy or capacity to a small power production facility between 5 megawatts and 20 megawatts under this Act (including the right to recover costs of purchasing electric energy or capacity).

(4) For purposes of implementing paragraphs (d)(1) and (2) of this section, the Commission will not be bound by the standards set forth in § 292.204(a)(2).

(e) Midcontinent Independent System Operator, Inc. (MISO), PJM Interconnection, L.L.C. (PJM), ISO New England Inc. (ISO-NE), and New York Independent System Operator, Inc. (NYISO) qualify as markets described in paragraphs (a)(1)(i) and (ii) of this section, and there is a rebuttable presumption that small power production facilities with a capacity greater than 5 megawatts and cogeneration facilities with a capacity greater than 20 megawatts have nondiscriminatory access to those markets through Commission-approved open access transmission tariffs and interconnection rules, and that electric utilities that are members of such regional transmission organizations or independent system operators should be relieved of the obligation to purchase electric energy from the qualifying facilities.

(1) A qualifying facility above 20 MW may seek to rebut this presumption by demonstrating, inter alia, that:

(i) The qualifying facility has certain operational characteristics that effectively prevent the qualifying facility's participation in a market; or

(ii) The qualifying facility lacks access to markets due to transmission constraints. The qualifying facility may show that it is located in an area where persistent transmission constraints in effect cause the qualifying facility not to have access to markets outside a persistently congested area to sell the qualifying facility output or capacity.

(2) A small power producer qualifying facility between 5 megawatts and 20 megawatts may show it does not have access to the market in light of consideration of other factors, including, but not limited to:

(i) Specific barriers to connecting to the interstate transmission grid, such as excessively high costs and pancaked delivery rates;

(ii) Unique circumstances impacting the time or length of interconnection studies or queues to process the small power production facility's interconnection request;

(iii) A lack of affiliation with entities that participate in the markets in section § 292.309(a)(1), (2), and (3);

(iv) The qualifying small power production facility has a predominant purpose other than selling electricity and should be treated similarly to qualifying cogeneration facilities;

(v) The qualifying small power production facility has certain operational characteristics that effectively prevent the qualifying facility's participation in a market; or

(vi) The qualifying small power production facility lacks access to markets due to transmission constraints. The qualifying small power production facility may show that it is located in an area where persistent transmission constraints in effect cause the qualifying facility not to have access to markets outside a persistently congested area to sell the qualifying facility output or capacity.

(f) The Electric Reliability Council of Texas (ERCOT) qualifies as a market described in paragraph (a)(3) of this section, and there is a rebuttable presumption that small power production facilities with a capacity greater than five megawatts and cogeneration facilities with a capacity greater than 20 megawatts have nondiscriminatory access to that market through Public Utility Commission of Texas (PUCT) approved open access protocols, and that electric utilities that operate within ERCOT should be relieved of the obligation to purchase electric energy from the qualifying facilities.

(1) A qualifying facility above 20 MW may seek to rebut this presumption by demonstrating, inter alia, that:

(i) The qualifying facility has certain operational characteristics that effectively prevent the qualifying facility's participation in a market; or

(ii) The qualifying facility lacks access to markets due to transmission constraints. The qualifying facility may show that it is located in an area where persistent transmission constraints in effect cause the qualifying facility not to have access to markets outside a persistently congested area to sell the qualifying facility output or capacity.

(2) A small power producer qualifying facility between 5 megawatts and 20 megawatts may show it does not have access to the market in light of consideration of other factors, including, but not limited to:

(i) Specific barriers to connecting to the interstate transmission grid, such as excessively high costs and pancaked delivery rates;

(ii) Unique circumstances impacting the time or length of interconnection studies or queues to process the small power production facility's interconnection request;

(iii) A lack of affiliation with entities that participate in the markets in section § 292.309(a)(1), (2), and (3);

(iv) The qualifying small power production facility has a predominant purpose other than selling electricity and should be treated similarly to qualifying cogeneration facilities;

(v) The qualifying small power production facility has certain operational characteristics that effectively prevent the qualifying facility's participation in a market; or

(vi) The qualifying small power production facility lacks access to markets due to transmission constraints. The qualifying small power production facility may show that it is located in an area where persistent transmission constraints in effect cause the qualifying facility not to have access to markets outside a persistently congested area to sell the qualifying facility output or capacity.

(g) The California Independent System Operator and Southwest Power Pool, Inc. satisfy the criteria of § 292.309(a)(2)(i).

(h) No electric utility shall be required, under this part, to enter into a new contract or obligation to purchase from or sell electric energy to a facility that is not an existing qualifying cogeneration facility unless the facility meets the criteria for new qualifying cogeneration facilities established by the Commission in § 292.205.

(i) For purposes of § 292.309(h), an “existing qualifying cogeneration facility” is a facility that:

(1) Was a qualifying cogeneration facility on or before August 8, 2005; or

(2) Had filed with the Commission a notice of self-certification or self-recertification, or an application for Commission certification, under § 292.207 prior to February 2, 2006.

(j) For purposes of § 292.309(h), a “new qualifying cogeneration facility” is a facility that satisfies the criteria for qualifying cogeneration facilities pursuant to § 292.205.

[Order 688, 71 FR 64372, Nov. 1, 2006; 71 FR 75662, Dec. 18, 2006; Order 872, 85 FR 54735, Sept. 2, 2020; 85 FR 86725, Dec. 30, 2020]

§ 292.310 Procedures for utilities requesting termination of obligation to purchase from qualifying facilities.

(a) An electric utility may file an application with the Commission for relief from the mandatory purchase requirement under § 292.303(a) pursuant to this section on a service territory-wide basis. Such application shall set forth the factual basis upon which relief is requested and describe why the conditions set forth in § 292.309(a)(1), (2) or (3) have been met. After notice, including sufficient notice to potentially affected qualifying cogeneration facilities and qualifying small power production facilities, and an opportunity for comment, the Commission shall make a final determination within 90 days of such application regarding whether the conditions set forth in § 292.309(a)(1), (2) or (3) have been met.

(b) Sufficient notice shall mean that an electric utility must identify with names and addresses all potentially affected qualifying facilities in an application filed pursuant to paragraph (a).

(c) An electric utility must submit with its application for each potentially affected qualifying facility: The docket number assigned if the qualifying facility filed for self-certification or an application for Commission certification of qualifying facility status; the net capacity of the qualifying facility; the location of the qualifying facility depicted by state and county, and the name and location of the substation where the qualifying facility is interconnected; the interconnection status of each potentially affected qualifying facility including whether the qualifying facility is interconnected as an energy or a network resource; and the expiration date of the energy and/or capacity agreement between the applicant utility and each potentially affected qualifying facility. All potentially affected qualifying facilities shall include:

(1) Those qualifying facilities that have existing power purchase contracts with the applicant;

(2) Other qualifying facilities that sell their output to the applicant or that have pending self-certification or Commission certification with the Commission for qualifying facility status whereby the applicant will be the purchaser of the qualifying facility's output;

(3) Any developer of generating facilities with whom the applicant has agreed to enter into power purchase contracts, as of the date of the application filed pursuant to this section, or are in discussion, as of the date of the application filed pursuant to this section, with regard to power purchase contacts;

(4) The developers of facilities that have pending state avoided cost proceedings, as of the date of the application filed pursuant to this section; and

(5) Any other qualifying facilities that the applicant reasonably believes to be affected by its application filed pursuant to paragraph (a) of this section.

(d) The following information must be filed with an application:

(1) Identify whether applicant seeks a finding under the provisions of § 292.309(a)(1), (2), or (3).

(2) A narrative setting forth the factual basis upon which relief is requested and describing why the conditions set forth in § 292.309(a)(1), (2), or (3) have been met. Applicant should also state in its application whether it is relying on the findings or rebuttable presumptions contained in § 292.309(e), (f) or (g). To the extent applicant seeks relief from the purchase obligation with respect to a qualifying facility 20 megawatts or smaller, and thus seeks to rebut the presumption in § 292.309(d), applicant must also set forth, and submit evidence of, the factual basis supporting its contention that the qualifying facility has nondiscriminatory access to the wholesale markets which are the basis for the applicant's filing.

(3) Transmission Studies and related information, including:

(i) The applicant's long-term transmission plan, conducted by applicant, or the RTO, ISO or other relevant entity;

(ii) Transmission constraints by path, element or other level of comparable detail that have occurred and/or are known and expected to occur, and any proposed mitigation including transmission construction plans;

(iii) Levels of congestion, if available;

(iv) Relevant system impact studies for the generation interconnections, already completed;

(v) Other information pertinent to showing whether transfer capability is available; and

(vi) The appropriate link to applicant's OASIS, if any, from which a qualifying facility may obtain applicant's available transfer capability (ATC) information.

(4) Describe the process, procedures and practices that qualifying facilities interconnected to the applicant's system must follow to arrange for the transmission service to transfer power to purchasers other than the applicant. This description must include the process, procedures and practices of all distribution, transmission and regional transmission facilities necessary for qualifying facility access to the market.

(5) If qualifying facilities will be required to execute new interconnection agreements, or renegotiate existing agreements so that they can effectuate wholesale sales to third-party purchasers, explain the requirements, charges and the process to be followed. Also, explain any differences in these requirements as they apply to qualifying facilities compared to other generators, or to applicant-owned generation.

(6) Applicants seeking a Commission finding pursuant to § 292.309(a)(2) or (3), except those applicants located in ERCOT, also must provide evidence of competitive wholesale markets that provide a meaningful opportunity to sell capacity, including long-term and short-term sales, and electric energy, including long-term, short-term and real-time sales, to buyers other than the utility to which the qualifying facility is interconnected. In demonstrating that a meaningful opportunity to sell exists, provide evidence of transactions within the relevant market. Applicants must include a list of known or potential purchasers, e.g., jurisdictional and non-jurisdictional utilities as well as retail energy service providers.

(7) Signature of authorized individual evidencing the accuracy and authenticity of information provided by applicant.

(8) Person(s) to whom communications regarding the filed information may be addressed, including name, title, telephone number, and mailing address.

[Order 688, 71 FR 64372, Nov. 1, 2006, as amended by Order 688-A, 72 FR 35892, June 29, 2007]

§ 292.311 Reinstatement of obligation to purchase.

At any time after the Commission makes a finding under §§ 292.309 and 292.310 relieving an electric utility of its obligation to purchase electric energy, a qualifying cogeneration facility, a qualifying small power production facility, a State agency, or any other affected person may apply to the Commission for an order reinstating the electric utility's obligation to purchase electric energy under this section. Such application shall set forth the factual basis upon which the application is based and describe why the conditions set forth in § 292.309(a), (b) or (c) are no longer met. After notice, including sufficient notice to potentially affected electric utilities, and opportunity for comment, the Commission shall issue an order within 90 days of such application reinstating the electric utility's obligation to purchase electric energy under this section if the Commission finds that the conditions set forth in § 292.309(a), (b), or (c) which relieved the obligation to purchase, are no longer met.

[Order 688, 71 FR 64372, Nov. 1, 2006]

§ 292.312 Termination of obligation to sell to qualifying facilities.

(a) Any electric utility may file an application with the Commission for relief from the mandatory obligation to sell under this section on a service territory-wide basis or a single qualifying facility basis. Such application shall set forth the factual basis upon which relief is requested and describe why the conditions set forth in paragraphs (b)(1) and (b)(2) of this section have been met. After notice, including sufficient notice to potentially affected qualifying facilities, and an opportunity for comment, the Commission shall make a final determination within 90 days of such application regarding whether the conditions set forth in paragraphs (b)(1) and (b)(2) of this section have been met.

(b) After August 8, 2005, an electric utility shall not be required to enter into a new contract or obligation to sell electric energy to a qualifying small power production facility, an existing qualifying cogeneration facility, or a new qualifying cogeneration facility if the Commission has found that;

(1) Competing retail electric suppliers are willing and able to sell and deliver electric energy to the qualifying cogeneration facility or qualifying small power production facility; and

(2) The electric utility is not required by State law to sell electric energy in its service territory.

[Order 688, 71 FR 64372, Nov. 1, 2006; 71 FR 75662, Dec. 18, 2006]

§ 292.313 Reinstatement of obligation to sell.

At any time after the Commission makes a finding under § 292.312 relieving an electric utility of its obligation to sell electric energy, a qualifying cogeneration facility, a qualifying small power production facility, a State agency, or any other affected person may apply to the Commission for an order reinstating the electric utility's obligation to purchase electric energy under this section. Such application shall set forth the factual basis upon which the application is based and describe why the conditions set forth in Paragraph (b)(1) and (b)(2) of this section are no longer met. After notice, including sufficient notice to potentially affected utilities, and opportunity for comment, the Commission shall issue an order within 90 days of such application reinstating the electric utility's obligation to sell electric energy under this section if the Commission finds that the conditions set forth in paragraphs (b)(1) and (b)(2) of this section are no longer met.

[Order 688, 71 FR 64372, Nov. 1, 2006]

§ 292.314 Existing rights and remedies.

Nothing in this section affects the rights or remedies of any party under any contract or obligation, in effect or pending approval before the appropriate State regulatory authority or non-regulated electric utility on or before August 8, 2005, to purchase electric energy or capacity from or to sell electric energy or capacity to a qualifying cogeneration facility or qualifying small power production facility under this Act (including the right to recover costs of purchasing electric energy or capacity).

[Order 688, 71 FR 64372, Nov. 1, 2006]

§ 292.401 Implementation of certain reporting requirements.

Any electric utility which fails to comply with the requirements of § 292.302(b) shall be subject to the same penalties to which it may be subjected for failure to comply with the requirements of the Commission's regulations issued under section 133 of PURPA.

[45 FR 12236, Feb. 25, 1980. Redesignated by Order 541, 57 FR 21734, May 22, 1992]

§ 292.402 Waivers.

(a) State regulatory authority and nonregulated electric utility waivers. Any State regulatory authority (with respect to any electric utility over which it has ratemaking authority) or nonregulated electric utility may, after public notice in the area served by the electric utility, apply for a waiver from the application of any of the requirements of subpart C (other than § 292.302 thereof).

(b) Commission action. The Commission will grant such a wavier only if an applicant under paragraph (a) of this section demonstrates that compliance with any of the requirements of subpart C is not necessary to encourage cogeneration and small power production and is not otherwise required under section 210 of PURPA.

[45 FR 12236, Feb. 25, 1980. Redesignated by Order 541, 57 FR 21734, May 22, 1992]

§ 292.601 Exemption to qualifying facilities from the Federal Power Act.

(a) Applicability. This section applies to qualifying facilities, other than those described in paragraph (b) of this section. This section also applies to qualifying facilities that meet the criteria of section 3(17)(E) of the Federal Power Act (16 U.S.C. 796(17)(E)), notwithstanding paragraph (b).

(b) Exclusion. This section does not apply to a qualifying small power production facility with a power production capacity which exceeds 30 megawatts, if such facility uses any primary energy source other than geothermal resources.

(c) General rule. Any qualifying facility described in paragraph (a) of this section shall be exempt from all sections of the Federal Power Act, except:

(1) Sections 205 and 206; however, sales of energy or capacity made by qualifying facilities 20 MW or smaller, or made pursuant to a contract executed on or before March 17, 2006 or made pursuant to a state regulatory authority's implementation of section 210 the Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 824a-1, shall be exempt from scrutiny under sections 205 and 206;

(2) Section 1-18, and 21-30;

(3) Sections 202(c), 210, 211, 212, 213, 214, 215, 220, 221 and 222;

(4) Sections 305(c); and

(5) Any necessary enforcement provision of part III of the Federal Power Act (including but not limited to sections 306, 307, 308, 309, 314, 315, 316 and 316A) with regard to the sections listed in paragraphs (c)(1), (2), (3) and (4) of this section.

(Energy Security Act, Pub. L. 96-294, 94 Stat. 611 (1980) Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 2601, et seq., Energy Supply and Environmental Coordination Act, 15 U.S.C. 791, et seq., Federal Power Act, as amended, 16 U.S.C. 792 et seq., Department of Energy Organization Act, 42 U.S.C. 7101, et seq.; E.O. 12009, 42 FR 46267)

[Order 135, 46 FR 19232, Mar. 30, 1981, as amended by Order 569, 59 FR 40470, Aug. 9, 1994; Order 671, 71 FR 7868, Feb. 15, 2006; 72 FR 29063, May 24, 2007; Order 732, 75 FR 15966, Mar. 30, 2010]

§ 292.602 Exemption to qualifying facilities from the Public Utility Holding Company Act of 2005 and certain State laws and regulations.

(a) Applicability. This section applies to any qualifying facility described in § 292.601(a), and to any qualifying small power production facility with a power production capacity over 30 megawatts if such facility produces electric energy solely by the use of biomass as a primary energy source.

(b) Exemption from the Public Utility Holding Company Act of 2005. A qualifying facility described in paragraph (a) of this section or a utility geothermal small power production facility shall be exempt from the Public Utility Holding Company Act of 2005, 42 U.S.C. 16,451-63.

(c) Exemption from certain State laws and regulations. (1) Any qualifying facility described in paragraph (a) of this section shall be exempted (except as provided in paragraph (c)(2) of this section) from State laws or regulations respecting:

(i) The rates of electric utilities; and

(ii) The financial and organizational regulation of electric utilities.

(2) A qualifying facility may not be exempted from State laws and regulations implementing subpart C.

(3) Upon request of a state regulatory authority or nonregulated electric utility, the Commission may consider a limitation on the exemptions specified in paragraph (b)(1) of this section.

(4) Upon request of any person, the Commission may determine whether a qualifying facility is exempt from a particular State law or regulation.

(Energy Security Act, Pub. L. 96-294, 94 Stat. 611 (1980) Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 2601, et seq., Energy Supply and Environmental Coordination Act, 15 U.S.C. 791, et seq., Federal Power Act, as amended, 16 U.S.C. 792 et seq., Department of Energy Organization Act, 42 U.S.C. 7101, et seq.; E.O. 12009, 42 FR 46267)

[45 FR 12237, Feb. 25, 1980, as amended by Order 135, 46 FR 19232, Mar. 30, 1981; Order 671, 71 FR 7869, Feb. 15, 2006; Order 671-A, 71 FR 30589, May 30, 2006; Order 732, 75 FR 15966, Mar. 30, 2010; 77 FR 9842, Feb. 21, 2012]

§ 294.101 Shortages of electric energy and capacity.

(a) Definition of shortages of electric energy and capacity. For purposes of this section, the term anticipated shortages of electric or energy means:

(1) Any situation anticipated to occur in which the generating and bulk purchased power capability of a public utility will not be sufficient to meet its anticipated demand plus appropriate reserve margins and this shortage would affect the utility's capability adequately to supply electric services to its firm power wholesale customers; or

(2) Any situation anticipated to occur in which the energy supply capability of a public utility is not sufficient to meet its customers' energy requirements and this shortage would affect the utility's capability adequately to supply electric services to its firm power wholesale customers.

(b) Accommodation of shortages. (1) Each public utility now serving firm power wholesale customers, shall submit a brief statement indicating how it would accommodate any shortages of electric energy or capacity affecting its firm power wholesale customers.

(2) This statement shall:

(i) Describe how the utility would assure that direct and indirect customers are treated without undue prejudice or disadvantage; and

(ii) It shall also identify any agreement, law, or regulation which might impair the utility's ability to accommodate such a shortage.

(3) Each utility shall file a copy of its statement with any appropriate State regulatory agency and all firm power wholesale customers.

(4) If a plan for accommodating any shortages of electric energy or capacity affecting its firm power wholesale customers as described in the brief statement submitted pursuant to paragraph (b)(1) of this section is modified, the utility must submit to the Commission and the persons described in paragraph (b)(3) of this section within 15 days of any such modification, a supplemental statement informing the Commission of those modifications.

(5) Notwithstanding any other provision of this section, a public utility need not file the statement with the Commission if the public utility provides in its rate schedules to firm power wholesale customers that:

(i) During electric energy and capacity shortages it will treat without undue discrimination or preference, prejudice, or disadvantage firm power wholesale customers; and

(ii) It will report any modifications to its contingency plans for accommodating shortages within 15 days to:

(A) The appropriate State regulatory agency and

(B) To the affected wholesale customers.

(c) Reporting requirements. Each public utility shall immediately report to the Commission, to any State regulatory authority and to firm power wholesale customers, any anticipated shortage of electric energy or capacity. The report shall include the following information:

(1) The nature and projected duration of the anticipated capacity or energy supply shortage;

(2) A list showing all firm power wholesale customers affected or likely to be affected by the anticipated shortage;

(3) Procedures for accommodating the shortage, if different from those described in paragraph (b) of this section;

(4) An estimate of the effects (reduced power and energy usage) of use of these procedures upon the utility's wholesale and retail customers; and

(5) The name, title, address and telephone number of an officer or employee of the utility who may be contacted for further information regarding the shortage and planned actions of the utility.

(d) Reports to other government entities. Any report filed with another governmental entity that contains the information that must be reported under this part may be filed to comply with this part.

(e) Reporting Procedure. Any public utility that reports under this part must provide an electronic filing to this Commission at emergency@ferc.gov and one copy to any state regulatory authority and firm power wholesale customers, unless otherwise required by the Commission.

(f) Report of anticipated shortage. Notwithstanding any other provision of this part, if a public utility provides in its rate schedule that it will make such reports to the appropriate state regulatory agency and to its firm power wholesale requirements customers, then it need only report to the Commission the nature and projected duration of the anticipated capacity or energy supply shortage and supply a list of the firm power wholesale customers affected or likely to be affected by the shortage. Upon receiving the public utility's report of anticipated shortage of electric energy or capacity, the Commission will decide what further reports, if any, to require.

[44 FR 37502, June 27, 1979, as amended at 47 FR 20297, May 12, 1982; Order 401, 49 FR 39538, Oct. 9, 1984; Order 401-A, 54 FR 41087, Oct. 5, 1989; Order 575, 60 FR 4859, Jan. 25, 1995; Order 659, 70 FR 35028, June 16, 2005]

§ 300.1 Applicability and definitions.

(a) Applicability. This part sets forth procedures governing the filing, review and disposition of the rate schedules for the sale or transmission of power and energy established by the Alaska, Bonneville, Southeastern, Southwestern and Western Area Power Administrations. Except as otherwise provided by rule or order, the Commission's general rules of practice and procedure (part 385 of this chapter) will apply to any filings, hearings or other procedures under this part, as applicable.

(b) Definitions. For purposes of this part, the following definitions apply:

(1) Administrator means the administrator of a power marketing administration.

(2) Electric service means any transmission or sale of electric power and energy, including capacity sales, energy sales, firm power sales, transmission services, or any combination of these services, and the utilization, by means of ownership, contractual arrangements, leasing, or other arrangements, of any facility to provide such sales or services.

(3) Historic period means the period commencing with the date of first commercial operation of a powerplant or transmission facility and ending on the last day of the latest year for which actual cost data are available, provided that the period does not end more than 18 months before the date on which the Administrator tenders the rate schedule for filing with the Commission, or such longer period requested by the Deputy Secretary of Energy or Administrator and granted by the Commission.

(4) Initial capital investment means the cost of acquisition or construction of a power facility or non-power facility which has been assigned to be repaid from the power revenues, including but not limited to any cost of planning, design, land acquisition, construction, interest during construction, and testing incurred before the date on which the facility becomes operational or revenue-producing.

(5) Power repayment study or PRS means a study of the annual repayment of production and transmission investments and other costs through the application of revenues during the repayment period.

(6) Proposed rate approval period means the period for which confirmation and approval of the rate schedules is requested. This period must not exceed five years.

(7) Rate schedule means a statement describing:

(i) Type of service to which the rate is to be applied;

(ii) Rates and charges for, or in connection with, electric service; and

(iii) Classifications and other provisions which directly affect such rates and charges.

(8) Rate test or cost evaluation period means a period, commencing with the end of the historic period, as defined in paragraph (b)(3) of this section, and continuing through the proposed rate approval period as defined in paragraph (b)(6) of this section, during which future estimates of costs and revenues should be modified by the Administrator to reflect changing conditions.

(9) Replacement means any substitution of a unit of property with another unit of like character.

[Order 382, 49 FR 25235, June 20, 1984, as amended by Order 323-B, 52 FR 20709, June 3, 1987]

§ 300.2 Informal conference.

The Administrator or a designee may confer with Commission staff prior to submitting an application under subpart B, with respect to the appropriate form and content of such application.

§ 300.10 Application for confirmation and approval.

(a) General provisions—(1) Contents of filing. Any application under this subpart for confirmation and approval of rate schedules must include, as described in this section:

(i)(A) A letter of request for rate approval;

(B) A form of notice suitable for publication in the Federal Register in accordance with the specifications in § 385.203(d) of this chapter;

(C) The rate schedule;

(D) A statement of revenue and related costs;

(E) The order, if any, placing the rates into effect on an interim basis;

(F) The Administrator's Record of Decision or explanation of the rate development process;

(G) Supporting documents;

(H) A certification; and

(I) Technical supporting information and analysis.

(ii) The form of notice shall be on electronic media as specified by the Secretary.

(iii) Paragraphs (a)(1)(i)(B) and (a)(1)(ii) of this section shall cease to have effect on December 5, 2026, unless the Commission determines that the cessation deadline should be extended to a date not more than 5 years in the future after offering the public an opportunity to provide input on the costs and benefits of paragraphs (a)(1)(i)(B) and (a)(1)(ii) and considering that input. The Commission will publish a document in the Federal Register announcing its determination and revising or removing paragraphs (a)(1)(i)(B) and (a)(1)(ii) accordingly.

(2) Incorporation of information by reference. Any information required under this subpart that has previously been submitted to the Commission in substantially the same form as specified in this section may be incorporated by reference only.

(3) Time of filing. (i) Rate schedules put into effect on an interim basis by the Secretary of the Department of Energy, or a designee, and filed for final Commission approval must be filed not later than five days after interim approval is granted.

(ii) Rate schedules of the Bonneville Power Administration for which interim approval by the Commission is requested must be filed not later than 60 days in advance of the proposed effective date.

(iii) Rate schedules for which interim approval is not requested must be filed not later than 180 days in advance of the proposed effective date.

(4) Electronic filing. All material must be filed electronically in accordance with the requirements of § 35.7 of this chapter.

(b) Letter of request for rate approval. A letter of request for rate approval must contain the following information:

(1) A description of the period for which Commission approval is requested, delineated by an effective date and an expiration date, and, for the Bonneville Power Administration, a request, if any, for interim approval of the rates;

(2) A brief description of the proposed rates and charges under existing and proposed rate schedules and the expected changes, if any, in annual revenues; and

(3) A description of how the filed rate differs in rate level or rate structure from the rate schedule currently effective.

(c) Notice of filing. The notice of filing, suitable for publication in the Federal Register, must contain the following information:

(1) The identification number or description of the rate schedule or contract;

(2) If the rate schedule includes changes in rates, the dollar amount and percent increase or decrease in rates;

(3) If the rate schedule includes changes other than rates, a brief description of the changes;

(4) A brief explanation of the reasons for any proposed change in the rate schedule;

(5) A statement whether interim approval of Bonneville Power Administration rates is requested;

(6) The proposed effective date of the rate schedule; and

(7) The proposed rate approval period.

(d) Rate schedules. A filed rate schedule, as defined in § 300.1(b)(7), must describe the following, as appropriate:

(1) The class of service to which each rate schedule will apply and service areas or zones which will be affected by the filed rate;

(2) The rate to be applied to capacity and energy services or other services;

(3) Special provisions, such as discounts, penalties, power factor adjustments, service interruptions, unauthorized overruns and other similar provisions which may affect the rate and charges; and

(4) The period during which the rates will be effective.

(e) Statement of revenue and related costs. Each filing shall include a statement which includes cost (if available) and revenue data for each class of service as specified in each rate schedule for the proposed period.

(f) Explanation of rate development process and supporting documents. (1) The Administrator must file the entire record on which the final decision establishing a rate scheduled is based.

(2) The Administrator must file a Record of Decision, if one is made, or an explanation of the rate development process, if a Record of Decision is not made. The Record of Decision or the explanation of the rate development process must include:

(i) A discussion of issues raised by customers or the public and how such issues were resolved;

(ii) A discussion of all statutory, regulatory, or other requirements which governed the Administrator's decision;

(iii) A description of any methodology used for determining revenue requirements and for developing appropriate rate structures;

(iv) A list identifying all documents submitted for Commission consideration; and

(g) Certification. The Administrator must file a statement certifying that the rate is consistent with applicable laws and that it is the lowest possible rate consistent with sound business principles.

(h) Additional filing requirements. (1) The Administrator must file with the Commission any other information relevant to the Commission's ratemaking decision.

(2) The Administrator must file any other information requested by the Office of Energy Market Regulation as needed for Commission analysis of the rate filing.

[Order 382, 49 FR 25235, June 20, 1984, as amended by Order 541, 57 FR 21734, May 22, 1992; Order 593, 62 FR 1284, Jan. 9, 1997; Order 647, 69 FR 32439, June 10, 2004; Order 699, 72 FR 45325, Aug. 14, 2007; Order 701, 72 FR 61054, Oct. 29, 2007; Order 714, 73 FR 57536, Oct. 3, 2008; Order 914, 90 FR 48404, Oct. 21, 2025]

§ 300.11 Technical support for the rate schedule.

(a) Filing requirement. The Administrator must submit, in conjunction with any application under § 300.10, the technical support data described under paragraph (b) of this section and the analysis of data described under § 300.12 of this subpart.

(b) Data—(1) Statement A—Sales and Revenues. Statement A must include:

(i) Sales and revenues for each rate schedule for the last five years of the historic period, as defined in section 300.1(b)(3);

(ii) For the rate test period, the estimated annual sales and revenues for the existing and each proposed rate schedule, including a separate aggregation of any revenues from sources not covered by the rate schedule according to general classifications of such revenues; and

(iii) Brief explanations of how sales and revenue estimates are prepared and explanations of any changes in sales or revenues during the last five years of the historic period.

(2) Statement B—Power Resources. Statement B must contain a list of the capacity and energy resources for the last five years of the historic period and for the rate test period, used to support the sales and revenues figures contained in Statement A. The statement should identify resources according to the powerplant and any purchase or exchange agreement.

(3) Statement C—Capitalized investments or costs. (i) Statement C must account for all capitalized investments to be repaid from power revenues.

(ii) The statement shall include a listing, by year, of the following:

(A) All initial investments and additions to plant, including interest during construction, that produced revenue during the historic period or are expected to produce revenue during the rate test period;

(B) Capitalized deferred expenses; and

(C) Replacements made during the historic period and replacements projected to be made during the balance of the repayment period.

(iii) For each such investment, the statement shall specify:

(A) Whether the investment is an initial investment, an addition, a replacement, or a capitalized deferred annual expense;

(B) The date the investment was made;

(C) The year in which repayment is due to be completed;

(D) Whether the investment was financed through the issuance of revenue bonds, the appropriate interest rate, and the terms and conditions for such bonds; and

(E) The authority or administrative procedure used for the adoption of such interest rate.

(iv) If available, the amount repaid on each investment to date must be stated, except that if repayment on individual investments is not recorded, the amount repaid to date on each group of investments having common interest rates should be stated.

(v) For each year, the sum of unpaid individual investments or the unpaid portion of interest groups shown above must equal the unamortized investment shown in the power repayment study for that year.

(vi) The statement must describe the methods used to forecast replacements and the price level used to estimate replacement costs.

(4) Statement D—Interest Expenses; Repayment of Investments and Debt Capital. (i) For each capitalized investment and cost listed in Statement C, Statement D must describe, by interest group:

(A) The total unpaid balance outstanding at the end of the historic period;

(B) Payments made on principal and interest during each of the last five years of the historic period; and

(C) Annual payments expected to be made through the cost evaluation period.

(ii) The statement must describe how the interest expense was determined for each type of investment and include examples of such computations.

(5) Statement E—Operation, Maintenance and Other Annual Expenses. Statement E must contain, for the last five years of the historic period and for the rate test period, as appropriate, a tabulation of actual and projected operation and maintenance, administrative and general, purchased power, wheeling, and any other expenses, other than interest. Statement E must:

(i) List expenses for each individual source, if purchased power and other similar expenses are derived from more than one source;

(ii) Explain any significant deviations from trends in expenses or any extraordinary expenses; and

(iii) Explain the price level used for estimating expenses.

(6) Statement F—Cost Allocations. (i) Statement F must contain, for each multiple-purpose reservoir project, unit, division, or system, a table or other summary showing total investment costs, the total annual operation and maintenance costs, and the allocation of all such costs among the various authorized purposes.

(ii) The statement must show the amount of power costs suballocated to irrigation functions, any changes from previous allocations, and the procedure used in allocating such costs. Currently valid allocations previously submitted to the Commission need not be furnished, if referenced.

§ 300.12 Analysis of supporting data.

(a) An analysis of the data provided under § 300.11 must be supported by an appropriate methodology developed by the Administrator.

(b) Revenue recovery study. (1) A study must be provided which supports the filed rate and charges, including a narrative statement that explains how the rates and charges meet the objective of recovering the revenue necessary to repay the Federal investment and other costs in a reasonable period of time.

(2) Any Power Repayment Study (PRS) submitted for this purpose must be developed using currently approved rates for estimating future revenues. If the filed rates differ from the current rates, the Administrator must provide a PRS which uses the level of revenues produced by the proposed rates. Unless otherwise required by statute, a PRS must contain only those investments in plant which will be in commercial operation during the proposed rate approval period, except replacements. Forecasts of costs beyond the rate test period must be based on conditions prevailing during the period, unless unusual circumstances warrant otherwise.

(3) A PRS must include, but need not be limited to, those items listed below:

(i) Operating revenues;

(ii) Operating expenses;

(iii) Interest expense;

(iv) Investment placed in service (using totals if the supporting statement annually shows a breakdown into the appropriate subcategories under each major heading), including the initial project, additions, replacements, and the total investment;

(v) Investment amortized;

(vi) Remaining unamortized investment;

(vii) Allowable unamortized investment (using totals if the supporting statement annually shows a breakdown into the appropriate subcategories under each major heading), including initial project, additions, replacements, and total investment;

(viii) Irrigation investment assigned to be repaid from power revenues (using totals if the supporting statement annually shows a breakdown into the appropriate subcategories under each major heading), including irrigation investment assigned to power, investment repaid, remaining unpaid investment, and allowable unpaid investment; and

(ix) Cumulative status of repayment.

(c) Cost of service study. For any project or system which provides more than one class of service for which differing rates are proposed, a cost of service study, if available, must be provided which shows how the costs of providing each service have been determined. If rates and charges have not been formulated on a cost related basis, the basis for each rate or charge should be explained.

§ 300.13 Waiver of filing requirements.

The Administrator must request waiver of any requirement of this subpart if an application that does not fully comply with that requirement is not to be considered deficient. The request must state the Administrator's reasons for such noncompliance and show good cause for any waiver.

§ 300.14 Filings under section 7(k).

Any application for Commission review and approval of a rate or rate schedules established by the Administrator of the Bonneville Power Administration pursuant to section 7(k) of the Pacific Northwest Electric Power Planning and Conservation Act must be filed in compliance with the provisions of § 35.13(a)(2) of part 35 of this chapter and with the provisions of this part, and must include the classifications, practices, rules and regulations affecting the rate and charges and all contracts which in any manner affect or relate to such rate, charges, classifications, services, rules, regulations, or practices. However, such classifications, practices, rules, regulations or contracts which may affect or relate to rates will not be subject to Commission approval unless they are determined to be rates or rate schedules.

[Order 323-B, 52 FR 20709, June 3, 1987]

§ 300.20 Interim acceptance and review of Bonneville Power Administration rates.

(a) Opportunity to comment. The Commission will publish in the Federal Register notice of any filing made under this part, for which interim approval is requested. This notice will give interested persons an opportunity to submit written comments on whether interim approval should be granted.

(b) Action on request for interim rate acceptance—(1) Deficient applications. Upon receipt of an application that does not comply with the requirements of this part, the Commission may:

(i) Accept the application and order the rate schedule into effect on an interim basis, effective on the date requested by the Administrator or at such time as the Commission may otherwise order, on the condition that any deficiencies in the filing are corrected by the Administrator to the satisfaction of and within such time specified by the Director of the Office of Energy Market Regulation; or

(ii) Deny the Administrator's interim rate request and reject the application, if the Commission determines that the Administrator's application:

(A) Is patently deficient with respect to the filing requirements of this part; or

(B) Fails to comply with the applicable provisions of the Northwest Power Act or such other Acts as may be applicable.

(2) Applications that are in compliance. Upon receipt of an application that complies with the requirements of this part, the Commission may:

(i) Order the rate schedule into effect on an interim basis, effective on the date requested by the Administrator or at such time as the Commission may otherwise order; or

(ii) Deny the Administrator's interim rate request and review the application for final confirmation and approval of the rate schedule pursuant to the provisions of this part.

(c) Condition of acceptance. Any rate schedule the Commission allows to become effective on an interim basis under paragraph (b) of this section is subject to refund with interest.

(d) Notice of action on interim approval. The Commission will publish in the Federal Register a notice of any action taken under paragraph (b) of this section and will mail notice to any person on the Commission's service list.

[Order 382, 49 FR 25235, June 20, 1984, as amended by Order 699, 72 FR 45326, Aug. 14, 2007; Order 701, 72 FR 61054, Oct. 29, 2007]

§ 300.21 Final confirmation and approval.

(a) Opportunity to comment and intervene. (1) The Commission will publish notice in the Federal Register giving interested persons an opportunity:

(i) To submit initial and reply comments on any filing made under subpart B; and

(ii) To intervene in any proceeding held on such filing.

(2) With respect to the Bonneville Power Administration:

(i) Such notice will also give interested persons an opportunity to comment on whether it is necessary to hold a hearing on non-regional rates under section 7(k) of the Northwest Power Act and the issues to be resolved at such hearing.

(ii) This notice may be part of any Commission order granting interim approval under § 300.20 of this part.

(b) Proceedings under section 7(k). For the Bonneville Power Administration, the Commission will publish a separate order if it determines that a hearing is necessary under section 7(k) of the Northwest Power Act. This order will, if appropriate, delineate the issues to be resolved at such hearing. Such hearing will be held in accordance with the procedures established for ratemaking by the Commission pursuant to the Federal Power Act.

(c) Standards of review for the Bonneville Power Administration—(1) Rates under section 7(a). The Commission will review any rate established by the Administrator under section 7(a) of the Northwest Power Act for compliance with the following standards:

(i) The rates must be sufficient to ensure repayment of the Federal investment in the Federal Columbia River Power System over a reasonable number of years after first meeting the Administrator's other costs.

(ii) The rates must be based upon the Administrator's total system costs.

(iii) With respect to transmission rates, the rates must equitably allocate the costs of the Federal transmission system between Federal and non-federal power utilizing such system.

(2) Rates under section 7(k). The Commission will review any rate established by the Administrator under section 7(k) of the Pacific Northwest Electric Power Planning and Conservation Act for compliance with the requirements of the Bonneville Project Act, the Flood Control Act of 1944, and the Federal Columbia River Transmission System Act.

(d) Standards of review for other power marketing administrations. The Commission will review the rates of the Alaska, Southeastern, Southwestern, and Western Area Power Marketing Administrations in accordance with the terms of any delegation made by the Secretary of Energy.

(e) Action on request for final confirmation and approval of rates. Filed rates will be considered for final confirmation and approval if the relevant filing complies with the filing requirements of subpart B of these regulations. The Commission may take any of the following actions:

(1) Confirm and approve the rate schedules for the period beginning with the date such rates where placed in effect on an interim basis or the effective date requested in the application to the expiration date requested in the application but not to exceed a five-year period, or for such lesser period, as the Commission deems appropriate;

(2) Remand the filing for further development of the record to support the filed rate schedules;

(3) Order an evidentiary hearing if there are questions of fact which can not be resolved from the record or through staff evaluation;

(4) Disapprove the filed rates; or

(5) Take such other action that the Commission considers appropriate.

(f) Procedures upon disapproval. If the Commission disapproves the rates, the Administrator will be provided a 120-day period, or other period as the Commission may deem appropriate, to prepare substitute rates that resolve the Commission's concerns. If the filed rates have been approved on an interim basis, the rates will continue in effect on an interim basis until the Commission takes final action.

(g) Refund and interest—(1) Refund. If a rate collected by any power marketing administration on an interim basis exceeds the rate which is confirmed and approved by the Commission as a final rate, the Administrator, pursuant to any conditions established by the Commission, must refund with interest any portion of the rate increase collected during the interim period which exceeds the final rate. The Administrator may make refunds by means of a net energy billing which reflects the value of any overcharge or other appropriate methods.

(2) Interest. Except as otherwise provided by the Commission, the Administrator must compute any amount of interest based on the revenues collected subject to refund and required to be refunded under this paragraph by using:

(i) With respect to the rates of the Bonneville Power Administration, the rate of interest or a weighted average of all rates of interest charged to the Bonneville Power Administration by the U.S. Treasury during the period for which the computation is made;

(ii) With respect to the rates of other Power Marketing Administrations, the rates of interest computed in accordance with the formula contained in DOE Order No. RA 6120.2, available from the Department of Energy (Office of Power Marketing Coordination) and the Power Marketing Administrations.

(h) Notice of action on final approval. The Commission's Secretary will publish in the Federal Register a notice of any action taken under paragraph (e) of this section and will mail the notice to the persons on the Commission's service list.

[Order 382, 49 FR 25235, June 20, 1984, as amended by Order 323-B, 52 FR 20709, June 3, 1987]

§ 301.1 Applicability.

The regulations in this part apply to the sales of electric power by any Utility to the Bonneville Power Administration (Bonneville) under section 5(c) of the Pacific Northwest Electric Power Planning and Conservation Act (Northwest Power Act). 16 U.S.C. 839c(c).

§ 301.2 Definitions.

For purposes of this section, the following definitions apply:

Account(s). The Accounts prescribed in the Commission's Uniform System of Accounts in part 101 of this chapter.

Appendix 1. Appendix 1 is the electronic form on which a Utility reports its Contract System Cost, Contract System Load, and other necessary data to Bonneville for the calculation of the Utility's Average System Cost.

Average System Cost (ASC). The rate charged by a Utility to Bonneville for the agency's purchase of power from the Utility under section 5(c) of the Northwest Power Act for each Exchange Period, and the quotient obtained by dividing Contract System Cost by Contract System Load. 16 U.S.C. 839c(c).

Average System Cost delta (ASC delta). The change in a Utility's ASC during the Exchange Period resulting from the inclusion in the Average System Cost forecast model of costs, loads, revenues, and other information related to the commercial operation of a major resource addition or reduction that was identified in the Utility's ASC filing.

Average System Cost forecast model (ASC forecast model). The model Bonneville uses to escalate a Utility's costs, revenues, and other information contained in the Appendix 1 to calculate the Exchange Period ASC.

Average System Cost review process (ASC review process). The administrative proceeding conducted before Bonneville under Bonneville's ASC review procedures in which a Utility's ASC is determined.

Base Period. The calendar year of the most recent Form 1 data.

Base Period ASC. The ASC determined in the Review Period using the Utility's Base Period data and additional specified data.

Contract High Water Mark (CHWM). The average MW amount used to define access to Tier 1 Priced-Power. CHWM is equal to the adjusted historical load for each customer proportionately scaled to Tier 1 System Resources and adjusted for conservation achieved. The CHWM is specified in each eligible customer's CHWM Contract.

Commission. Federal Energy Regulatory Commission.

Consumer-owned Utility. A public body or cooperative that is eligible to purchase preference power from Bonneville under section 5(b) of the Northwest Power Act. 16 U.S.C. 839c(b).

Contract System Cost. The Utility's costs for production and transmission resources, including power purchases and conservation measures, which costs are includable in, and subject to, the provision of Appendix 1. Under no circumstances will Contract System Cost include costs excluded from ASC by section 5(c)(7) of the Northwest Power Act. 16 U.S.C. 839c(c)(7).

Contract System Load. The total regional retail load included in the most recently filed FERC Form 1 or, for a Consumer-owned Utility, the total retail load from the most recent annual audited financial statement, as adjusted pursuant to the ASC methodology.

Direct Analysis. An analysis, including supporting documentation, prepared by the Utility that assigns the costs, debits, credits, and revenues in an Account to the Production, Transmission, and/or Distribution/Other functions of the Utility.

Escalator. A factor used to adjust an Account in the Base Period ASC filing to the value for the period of the Exchange Period ASC.

Exchange Load. All residential, apartment, seasonal dwelling and farm electrical loads eligible for the Residential Exchange Program under the terms of a Utility's Residential Purchase and Sales Agreement.

Exchange Period(s). The period during which a Utility's Bonneville-approved ASC is effective for the calculation of the Utility's Residential Exchange Program benefits. The initial Exchange Period under this ASC methodology is from October 1, 2008, through September 30, 2009. Subsequent Exchange Periods will be the period of time concurrent with Bonneville's wholesale power rate periods beginning October 1 or, if not beginning October 1, then beginning on the effective date of Bonneville's subsequent wholesale power rate periods.

Exchange Period ASC. The Base Period ASC escalated to a year(s) consistent with the Exchange Period.

FERC Form 1. The annual filing submitted to the Federal Energy Regulatory Commission, required by 18 CFR 141.1.

Functionalization. The process of assigning a Utility's costs, debits, credits, and revenues in an Account to the Production, Transmission, and/or Distribution/Other functions of the Utility.

Global Insight. The company that provides the escalation factors identified in § 301.4(a)(3) that are used in the ASC forecasting model, or the successor or replacement of that company, as determined by Bonneville.

Jurisdiction. The service territory of the Utility within which a particular regulatory body has authority to approve the Utility's retail rates. Jurisdictions must be within the Pacific Northwest region as defined in section 3(14) of the Northwest Power Act. 16 U.S.C. 839a(14).

Labor Ratios. The ratios that assign costs on a pro rata basis using salary and wage data for Production, Transmission, and Distribution/Other functions included in the Utility's most recently filed FERC Form 1. For Consumer-owned Utilities, comparable data will be utilized based on the cost-of-service study used as the basis for retail rates at the time of review.

Net Requirements. The amount of Federal power that a Consumer-owned Utility is entitled to purchase from Bonneville under section 5(b) of the Northwest Power Act. 16 U.S.C. 839c(b).

New Large Single Load. That load defined in section 3(13) of the Northwest Power Act, and determined by Bonneville as specified in power sales contracts and Residential Purchase and Sales Agreements with its Regional Power Sales Customers. 16 U.S.C. 839a(13).

Priority Firm Power. Priority Firm Power is electric power (capacity and energy) that Bonneville will make continuously available for direct consumption or resale to public bodies, cooperatives, and Federal Agencies (under the Priority Firm Preference rate) and to Utilities participating in the Residential Exchange Program (under the Priority Firm Exchange rate). Utilities participating in the Residential Exchange Program under section 5(c) of the Northwest Power Act may purchase Priority Firm Power under their Residential Purchase and Sales Agreements with Bonneville. Priority Firm Power is not available to serve New Large Single Loads. Deliveries of Priority Firm Power may be reduced or interrupted as permitted by the terms of the Utilities' power sales contracts and/or Residential Purchase and Sales Agreements with Bonneville.

Public Purpose Charge. Any charge based on a Utility's total retail sales in a Jurisdiction that is provided to independent entities or agencies of state and local governments for the purpose of funding within the Utility's service territory one or both of the following:

(a) Conservation programs in lieu of Utility conservation programs; or

(b) Acquisition of renewable resources.

Rate Period. The period during which Bonneville's wholesale power rates are effective. The period is coincident with the Exchange Period.

Rate Period High Water Mark (RHWM). The amount used to define each customer's eligibility to purchase Tier 1 Priced Power for the relevant Rate Period, subject to the customer's Net Requirement expressed in average megawatts (aMW). RHWM is equal to the customer's CHWM as adjusted for changes in Tier 1 System Resources. The RHWM is determined for each eligible customer in the RHWM Process preceding each Bonneville wholesale power rate case.

Rate Period High Water Mark Process (RHWM Process). The process or processes where each eligible Consumer-owned Utility RHWM is determined.

Regional Power Sales Customer. Any entity that contracts directly with Bonneville for the purchase of power under sections 5(b) (16 U.S.C. 839c(b)), 5(c) (16 U.S.C. 839c(c)), or 5(d) (16 U.S.C. 839c(d)) of the Northwest Power Act for delivery in the Pacific Northwest region as defined by section 3(14) of the Northwest Power Act. 16 U.S.C. 839a(14).

Residential Purchase and Sales Agreement. The contract under section 5(c) of the Northwest Power Act between Bonneville and a Utility that defines and implements the power purchase and sale under the Residential Exchange Program.

Review Period. The period of time during which a Utility's Appendix 1 is under review by Bonneville. The Review Period begins on or about June 1, and ends on or about November 15 of the fiscal year prior to the fiscal year Bonneville implements a change in wholesale power rates.

Regulatory Body. A state commission, Consumer-owned Utility governing body, or other entity authorized to establish retail electric rates in a Jurisdiction.

RHWM Exchange Load. The Exchange Load as determined in section 20 of the Residential Purchase and Sales Agreement.

RHWM System Resources. The Rate Period High Water Mark (RHWM) as calculated in section 4.2.1 of the Tiered Rates Methodology plus the resource amounts used in calculating a customer's Contract High Water Mark (CHWM).

Tier 1 Priced-Power. Priority Firm Power as defined in Bonneville's Tiered Rates Methodology.

Tier 1 System Resources. Resources as defined in Bonneville's Tiered Rates Methodology.

Tiered Rates Methodology. The long-term methodology established by Bonneville for the determination of tiered wholesale power rates.

Utility. A Regional Power Sales Customer that has executed a Residential Purchase and Sales Agreement.

§ 301.3 Filing procedures.

(a) Bonneville's ASC review procedures. The procedures established by Bonneville's Administrator provide the filing requirements for all Utilities that file an Appendix 1 with Bonneville. Utilities must file Appendix 1s, ASC forecast models, and other required documents with Bonneville in compliance with Bonneville's ASC review procedures.

(b) Exchange Period. The Exchange Period will be equal to the term of Bonneville's Rate Period. ASCs will change during the Exchange Period only for the reasons provided in § 301.4.

§ 301.4 Exchange Period Average System Cost determination.

(a) Escalation to Exchange Period. (1) This section describes the method Bonneville will use to escalate the Base Period ASC to and through the Exchange Period to calculate the Exchange Period ASC.

(2) Bonneville will escalate the Bonneville-approved Base Period ASC to the midpoint of the fiscal year for a one-year Rate Period/Exchange Period, and to the midpoint of the two-year period for a two-year Rate Period/Exchange Period to calculate Exchange Period ASCs.

(3) For purposes of the escalation referenced in paragraph (a)(2) of this section, Bonneville will use the following codes in the ASC forecast model to calculate the Exchange Period ASCs:

(i) A&G—Administrative and General.

(ii) CACNT—Customer Account.

(iii) CD—Construction, Distribution Plant.

(iv) CONSTANT—Constant.

(v) CSALES—Customer Sales.

(vi) CSERVE—Customer Service.

(vii) COAL—Coal.

(viii) DMN—Distribution Maintenance.

(ix) DOPS—Distribution Operations

(x) HMN—Hydro Maintenance.

(xi) HOPS—Hydro Operations.

(xii) INF—Inflation.

(xiii) NATGAS—Natural Gas.

(xiv) NFUEL—Nuclear Fuel.

(xv) NMN—Nuclear Maintenance.

(xvi) NOPS—Nuclear Operations.

(xvii) OMN—Other Production Maintenance.

(xviii) OOPS—Other Production Operations.

(xix) SNM—Steam Maintenance.

(xx) SOPS—Steam Operations.

(xxi) TMN—Transmission Maintenance.

(xxii) TOPS—Transmission Operations.

(xxiii) WAGES—Wages.

(4) Table 1 identifies which codes from paragraph (a)(3) of this section apply to the line items and associated FERC Accounts in the Appendix 1. Bonneville will use Global Insight as the source of data for the escalation codes identified in paragraph (a)(3) of this section, except for the NATGAS and CONSTANT codes. For the NATGAS code identified in paragraph (a)(3)(xiii) of this section, Bonneville will calculate the escalation rate using Bonneville's most current forecast of natural gas prices. The code CONSTANT in paragraph (a)(3)(iv) of this section indicates that no escalation to the Account will be made.

(5) Bonneville will base the costs of power products purchased from Bonneville on Bonneville's forecast of prices for its products.

(6) Bonneville will escalate the Public Purpose Charge forward to the midpoint of the Exchange Period by the same rate of growth as total Contract System Load.

(7) If any of the escalators specified in paragraph (a) of this section are no longer available, Bonneville will designate a replacement source of such escalator(s) that, as near as possible, replicates the results produced by the prior escalator. If a replacement source is not available, Bonneville will use the INF escalation code identified in paragraph (a)(3)(xii) of this section as the replacement escalator.

(b) Calculation of sales for resale and power purchases—(1) Long-term and intermediate-term sales for resale and power purchases. Bonneville will use the INF escalation code identified in paragraph (a)(3)(xii) of this section to escalate long-term and intermediate-term (as defined by the Commission) firm purchased power costs and long-term and intermediate-term sales for resale revenues.

(2) Short-term sales for resale and power purchases. (i) The short-term purchases and short-term sales for resale for the Base Period will be used as the starting values. A Utility will be allowed to include new plant additions, and to use a utility-specific forecast for the price of purchased power and for the price of sales for resale in order to value purchased power expenses and sales for resale revenue to be included in the Exchange Period ASC.

(ii) Bonneville will use the following method to determine separate market prices to forecast short-term purchased power expenses and sales for resale revenues to calculate Exchange Period ASCs:

(A) The Utility's average short-term purchased power price and short-term sales for resale price will be calculated for each year for the most recent three years of actual data (Base Period and prior two years).

(B) The midpoint between the Utility's average short-term purchased power price and the average short-term sales for resale price will be calculated for each of the years in paragraph (b)(2)(ii)(A) of this section.

(C) The percentage spread around the Utility's midpoint between the average short-term purchase power price and short-term sales for resale price will be calculated for each of the years identified in paragraph (b)(2)(ii)(A) of this section.

(D) A weighted average spread for the Utility's most recent three years of actual data (Base Period and prior two years) will be calculated. The following weighting scale will be used:

(1) Three (3) times Base Period spread.

(2) Two (2) times (Base Period minus 1) spread.

(3) One (1) time (Base Period minus 2) spread.

(E) The Base Period midpoint calculated in paragraph (b)(2)(ii)(B) of this section will be escalated at the same rate as Bonneville's electric market price forecast.

(F) The weighted average spread calculated in paragraph (b)(2)(ii)(D) of this section will be applied to the escalated midpoint price calculated in paragraph (b)(2)(ii)(E) of this section to determine the purchased power price and sales for resale price to value purchased power expenses and sales for resale revenues to be included in the Exchange Period ASC.

(iii) The method described in paragraph (b)(2)(ii) of this section will be used to forecast the electric market price for power purchases needed to meet load growth not met by major resource additions, and to forecast the electric market price for any additional surplus power sales resulting from major resource additions.

(c) Major resource additions and reductions and materiality thresholds. (1) During the Exchange Period, Bonneville will allow changes to a Utility's ASC to account for major resource additions or reductions that are used to meet a Utility's retail load. These changes, however, must meet the requirements of paragraph (c)(3) of this section and the materiality threshold described in paragraph (c)(4) of this section in order for Bonneville to allow an ASC to change. The ASC reflecting the major resource addition or reduction will be determined by Bonneville in the ASC review process during the Review Period.

(2) For major resource additions, the change to ASC will become effective when the resource begins commercial operation, or power is received under the purchased power contract. For major resource reductions, the change to ASC will become effective when the resource is sold, retired, or transferred.

(3) A major resource addition or reduction must be related to one or more of the following categories to be eligible for consideration as a major resource:

(i) Production or generating resource investments;

(ii) Transmission investments;

(iii) Long-term generating contracts;

(iv) Pollution control and environmental compliance investments relating to generating resources;

(v) Long-term transmission contracts;

(vi) Hydroelectric relicensing costs and fees; and

(vii) Plant rehabilitation investments.

(4) Major resource additions or reductions that meet the criteria identified in paragraph (c)(3) of this section will be allowed to change a Utility's ASC within an Exchange Period provided that the major resource addition or reduction results in a 2.5 percent or greater change in a Utility's Base Period ASC. Bonneville will allow a Utility to submit stacks of individual resources that, when combined, meet the 2.5 percent or greater materiality threshold, provided, however, that each resource in the stack must result in a change to the Utility's Base Period ASC of 0.5 percent or more.

(5) At the time the Utility submits its Appendix 1 filing, the Utility will provide its forecast of major resource additions or reductions and all associated costs. The forecast will cover the period from the end of the Base Period to the end of the Exchange Period.

(6) Bonneville will calculate new transmission wheeling revenues associated with new transmission investment using the following formula:

TTWR = WR (before additions) * [(NTP (before additions) + NTA)/NTP (before additions)]

Where: TTWR = total transmission wheeling revenues WR (before additions) = wheeling revenues (before additions) NTA = new transmission additions NTP (before additions) = Net Transmission Plant (before additions)

(7) The forecast of major resource additions or reduction costs to be included in the Utility's Exchange Period ASC will be reviewed by Bonneville in the ASC review process that is conducted during the Review Period.

(8) All major resources included in an ASC calculation prior to the start of the Exchange Period will be projected forward to the midpoint of the Exchange Period.

(9) For each major resource addition or reduction that is forecasted to occur during the Exchange Period, Bonneville will calculate the difference in ASC between the ASC without the major resource addition or reduction and the ASC with the major resource addition or reduction (ASC delta) at the midpoint of the Exchange Period.

(10) Once the major resource addition or reduction becomes effective, as determined by paragraph (c)(2) of this section, Bonneville will add the ASC delta to the Utility's existing ASC to determine its new ASC.

(11) For purposes of calculating ratios with Distribution Plant, Bonneville will escalate the Base Period average per-MWh cost of Distribution Plant forward to the midpoint of the Exchange Period, and use the escalated average cost to determine the distribution-related cost of meeting load growth since the Base Period.

(12) Bonneville will escalate the cost of General Plant, Accounts 389 through 399.1, forward to the midpoint of the Exchange Period by calculating the ratio of each Account's value in the Base Period to the sum of Production, Transmission, and Distribution plant values in the Base Period, and then multiplying the Base Period ratio times the forecasted value for Production, Transmission, and Distribution plant.

(13) Bonneville will issue procedural rules to ensure the confidentiality of information provided by Utilities regarding any major resource additions or reductions as part of its review process. Bonneville will provide parties with an opportunity to comment on the rules prior to their implementation in the review process. Failure to provide needed information may result in exclusion of the related costs from the Utility's ASC. However, load growth will be assumed to be met with purchases in the wholesale market, as described in paragraph (e) of this section. If the Utility fails to supply confidential resource data, it loses the difference between the cost of the resource and the price of electricity in the wholesale market.

(d) Forecasted Contract System Load and Exchange Load. All Utilities are required to provide a forecast of their Contract System Load and associated Exchange Load, as well as a current distribution loss analysis as described in Endnote e of Appendix 1, with their Appendix 1 filings. The load forecast for Contract System Load and Exchange Load will start with the Base Period and extend through four (4) years after the Exchange Period. The load forecast for Contract System Load and Exchange Load will be provided on a monthly basis for the Exchange Period.

(e) Load growth not met by major resource additions. All forecast load growth not met by major resource additions will be met by purchased power at the forecasted utility-specific, short-term purchased power price.

(1) The Utility's forecast Load Growth will be met with electric market purchases priced at the Utility's forecast short-term purchased power price as determined in paragraph (b) of this section unless the Utility forecasts major resource additions.

(2) In the event of major resource additions, forecast Load Growth will be met by the major resource(s). If the major resource is less than total forecast load growth, the unmet Load Growth will be met with electric market purchases priced at the Utility's forecast short-term purchased power price.

(3) In the event the power provided by a major resource exceeds the Utility's forecast Load Growth, the excess power will be used to reduce the Utility's short-term purchases. If short-term power purchases are reduced to zero, any remaining power will be sold as surplus power at the short-term sales for resale price as determined in paragraph (b) of this section.

(f) Changes to service territory. In the event a Utility forecasts that it will acquire a new service territory, or lose a portion of its existing service territory, and the gain or loss of that territory results in a 2.5 percent or greater change to the Utility's Base Period ASC, the Utility must file two Appendix 1 filings with Bonneville as follows:

(1) First, a Base Period ASC that does not reflect the acquisition or loss of service territory; and

(2) Second, a Base Period ASC that incorporates the following changes:

(i) A forecast of the increase or reduction in Contract System Load associated with the acquisition or reduction in service territory.

(ii) A forecast of the increase or reduction in Contract System Cost associated with the acquisition or reduction of the service territory.

(iii) A forecast of capital and operating cost increases or reductions associated with the change in service territory.

(iv) A forecast of the changes in purchased power expenses, sales for resale revenues, and other debits or credits based on the changes in the service territory.

(3) Because the date of the actual change to the Utility's service territory could differ from the forecast date used to determine the ASC during the Review Period, Bonneville will not adjust the Utility's ASC until the change in service territory takes place.

(g) ASC determination for Consumer-owned Utilities that elect to execute Regional Dialogue High Water Mark contracts. For Consumer-owned Utilities that elect to execute Regional Dialogue CHWM contracts, Bonneville will use the following approach:

(1) Use the RHWM System Resources as determined in the Tiered Rates Methodology (TRM) process.

(2) Determine the RHWM Exchange Load.

(3) Calculate the Utility's Contract System Cost as described in the ASC Methodology.

(4) Determine the fully allocated cost of resources used to meet Contract System Load that is not met by:

(i) The lesser of the Utility's RHWM or Forecast New Requirement, plus

(ii) Existing Resources for CHWM (as defined in the Tiered Rates Methodology).

(5) RHWM Contract System Cost = Contract System Cost minus fully allocated cost of resources (from paragraph (g)(4) of this section).

(6) RHWM Average System Cost = RHWM Contract System Cost (from paragraph (g)(5) of this section)/RHWM System Resource (from paragraph (g)(1) of this section).

(h) Filing of Appendix 1. Utilities must file an Appendix 1, including ASC information, by June 1 of each year, as required in § 301.3, for Bonneville's review and determination of a Base Period ASC. Utilities will file multiple, contingent, Base Period ASC filings to reflect changes to service territories as required in paragraph (f) of this section.

§ 301.5 Changes in Average System Cost methodology.

(a) The Administrator, at his or her discretion, or upon written request from three-quarters of the utilities that are parties to contracts authorized by section 5(c) of the Northwest Power Act, or from three-quarters of Bonneville's preference customers, or from three-quarters of Bonneville's direct-service industrial customers may initiate a consultation process as provided in section 5(c) of the Northwest Power Act. After completion of this process, Bonneville's Administrator may file the new ASC methodology with the Commission.

(b) The Administrator will not initiate any consultation process until one year of experience has been gained under the then-existing ASC methodology, that is, one year after the then-existing ASC methodology is adopted by Bonneville and approved by the Commission, through interim or final approval, whichever occurs first.

(c) The Administrator may, from time to time, issue interpretations of the ASC methodology. The Administrator also may modify the functionalization code of any Account to comply with the limitations identified in sections 5(c)(7)(A)-(C) of the Northwest Power Act or to conform to Commission revisions to the Uniform System of Accounts.

§ 301.6 Appendix 1 instructions.

(a) Appendix 1 is the form on which a Utility reports its Contract System Cost, Contract System Load, and other necessary data for the calculation of ASC. Appendix 1 is an electronic template consisting of seven schedules and several supporting files that must be completed by the Utility in accordance with these instructions and with the provisions of the endnotes following the schedules.

(b) Appendix 1 filings must be accompanied by an attestation statement of the Chief Financial Officer of the Utility or other responsible official who possesses the financial and accounting knowledge necessary to complete the attestation statement.

(c) The primary source of data for the Investor-owned Utilities' Appendix 1 filings is the Utility's prior year FERC Form 1 filings with the Commission. Any items not applicable to the Utility must be identified.

(d) For Consumer-owned Utilities that do not follow the Commission's Uniform System of Accounts, filings must include reconciliation between Utility Accounts and the items allowed as Contract System Cost. In addition, the cost-of-service report must be reviewed by an independent accounting or consulting firm, and must be accompanied by a report from that independent accounting or consulting firm that outlines the review work that was performed in preparing the cost-of-service report along with an assurance statement that the information contained in the cost-of-service report is presented fairly in all material respects.

(e) The Appendix 1 template is available electronically at http://www.bpa.gov/corporate/finance/ascm/. The primary schedules are:

(1) Schedule 1: Plant Investment/Rate Base

(2) Schedule 1A: Cash Working Capital

(3) Schedule 2: Capital Structure and Rate of Return

(4) Schedule 3: Expenses

(5) Schedule 3A: Taxes

(6) Schedule 3B: Other Included Items

(7) Schedule 4: Average System Cost

(f) The filing Utility must reference and attach work papers, documentation and other required information that support costs and loads, including details of allocation and functionalization. All references to the Commission's Accounts are to the Commission's Uniform System of Accounts, as amended by subsequent Commission actions. The costs includable in the attached schedules are those includable by reason of the definitions in the Commission's Accounts. If the Commission's Accounts are later revised or renumbered, any changes will be incorporated into the Appendix 1 by reference, except to the extent Bonneville determines that a particular change results in a change in the type of costs allowable for Residential Exchange Program purposes. In that event, Bonneville will address the changes, including escalation rules, in its review process for the following Exchange Period.

(g) Bonneville may require a Utility to account for all transactions with affiliated entities as though the affiliated entities were owned in whole or in part by the Utility, if necessary, to properly determine and/or functionalize the Utility's costs.

(h) A Utility operating in more than one Pacific Northwest Jurisdiction must file one Appendix 1.

(i)(1) A Utility operating in a Jurisdiction within the Pacific Northwest and within Jurisdictions outside the Pacific Northwest must allocate its total system costs among its Jurisdictions within the Pacific Northwest and outside the Pacific Northwest in accord with the same allocation methods and procedures used by the Regulatory Body(ies) to establish Jurisdictional costs and resulting revenue requirements. The Utility's Appendix filing must include details of the allocation.

(2) The allocation must exclude all costs of additional resources used to meet loads outside the Pacific Northwest, as required by section 5(c)(7) of the Northwest Power Act. All schedule entries and supporting data must be in accord with Generally Accepted Accounting Principles and Practices as these principles and practices apply to the electric utility industry.

(j) A Utility must file an attestation statement with each Appendix 1 filing and supporting documentation for each Review Period.

§ 301.7 Average System Cost methodology functionalization.

(a) Functionalization of each Account included in a Utility's ASC must be according to the functionalization prescribed in Table 1, Functionalization and Escalation Codes. Direct analysis on an Account may be performed only if Table 1 states specifically that a Utility may perform a direct analysis on the Account, with the exception of conservation costs. Utilities will be able to functionalize all conservation-related costs to Production, regardless of the Account in which they are recorded. The direct analysis must be consistent with the directions provided in this section.

(b) Functionalization codes.

(1) DIRECT—Direct Analysis.

(2) PROD—Production.

(3) TRANS—Transmission.

(4) DIST—Distribution/Other.

(5) PTD—Production, Transmission, Distribution/Other Ratio.

(6) TD—Transmission, Distribution/Other Ratio.

(7) GP—General Plant Ratio.

(8) GPM—General Plant Maintenance Ratio.

(9) PTDG—Production, Transmission, Distribution/Other, General Plant Ratio.

(10) LABOR—Labor Ratio.

(c) Functionalization requirements.

(1) Functionalization of certain Accounts may be based on Direct Analysis or with a default ratio associated with that specific Account as shown in Table 1. Once a Utility uses a specific functionalization method for an Account, the Utility may not change the functionalization method for that Account without prior written approval from Bonneville.

(2) The Utility must submit with its Appendix 1 all work papers, documents, or other materials that demonstrate that the functionalization under its Direct Analysis assigns costs, revenues, debits or credits based upon the actual and/or intended functional use of those items. Failure to submit the documentation will result in the entire account being functionalized to Distribution/Other, or Production, or Transmission, as appropriate.

(d) Functionalization methods. (1) Direct analysis, if allowed or required by Table 1, assigns costs, revenues, debits and credits to the Production, Transmission, and/or Distribution/Other function of the Utility. The only exception to this requirement is for Accounts that include conservation-related costs. Subject to the provisions of paragraph (d)(4) of this section, a Utility may conduct a Direct Analysis on any Account that contains conservation-related costs. The Direct Analysis performed by a Utility is subject to Bonneville review and approval.

(2) Bonneville will not allow a Utility to use a combination of Direct Analysis and a prescribed functionalization method for the same Account. The Utility can develop and use a functionalization ratio, or use a prescribed functionalization method, if the Utility, through Direct Analysis, can justify how the ratio reflects the functional nature of the costs, revenues, debits, or credits included in any Account.

(3) A Utility that wishes to include advertising and promotion costs related to conservation will use Direct Analysis.

(4) If a Utility records conservation costs in an Account that is functionalized to Distribution/Other, the Utility will identify and document the conservation-related costs included in the Account, and the balance of the costs will be functionalized to Distribution/Other. The presence of conservation-related costs in an Account does not authorize the Utility to perform a Direct Analysis on the entire Account. This option allows a Utility to assign conservation costs in the specified Account to Production based on analysis and support from the Utility that demonstrates the cost assignment is appropriate. The Utility must submit with its ASC filing all work papers, documents, and other materials that demonstrate the functionalization contained in its Direct Analysis and assign costs based upon the actual and/or intended functional use of those items. Failure to submit the documentation will result in the entire Account being functionalized to Distribution/Other for all schedules with the exception of items included in Schedule 3B, Other Included Items, where certain Accounts must be functionalized to Production as appropriate.

§ 340.1 Suspended rate schedules; procedure; refund requirement; administered by the Federal Energy Regulatory Commission.

(a) Effectiveness of suspended rate schedules. If a rate suspension proceeding initiated under section 15(7) of the Interstate Commerce Act has not been concluded and an order has not been issued by the Commission at the expiration of the suspension period, the proposed rate, charge, classification, or service shall go into in effect so long as the pipeline company complies with all of the requirements of this section.

(b) Recordkeeping. Any pipeline company whose proposed rates or charges were suspended and have gone into effect pending final order of the Commission pursuant to section 15(7) of the Interstate Commerce Act shall keep accurate accounts in detail of all amounts received by reason of the rates or charges made effective as provided in the Commission's order, for each billing period, including the following information by billing period, and by shipper:

(1) The monthly billing determinants of petroleum or petroleum by-products transported to each consignee under the suspended tariffs;

(2) The revenues which would result from such transportation services if they were computed under the rates in effect immediately prior to the date the proposed change became effective, if applicable;

(3) The revenues resulting from such transportation services as computed under the proposed increased rates or charges that became effective after the suspension period; and

(4) The difference between the revenues computed in paragraphs (b)(2) and (3) of this section, if applicable.

(c) Refunds. (1) Any pipeline company that collects charges pursuant to this section shall refund at such time, in such amounts, and in such manner as may be required by final order of the Commission, the portion of any rates and charges found by the Commission in that proceeding not to be justified, together with interest as required in paragraph (c)(2) of this section.

(2) Interest shall be computed from the date of collection until the date refunds are made as follows:

(i) At an average prime rate for each calendar quarter on amounts held on or after February 11, 1983. The applicable average prime rate for each calendar quarter shall be the arithmetic mean, to the nearest one-hundredth of one percent, of the prime rate values published in the Federal Reserve Bulletin, or in the Federal Reserve's “Selected Interest Rates” (Statistical Release G. 13) for the most recent three months preceding the beginning of the calendar quarter; and

(ii) The interest required to be paid under paragraph (c)(2)(i) of this section shall be compounded quarterly.

(3) Any pipeline company required to make refunds pursuant to this section shall bear all costs of such refunding.

(4) If any rate or charge described in paragraph (a) of this section that is found not to be justified by the Commission is shared between two or more pipeline companies, each pipeline company which shared in the unjustified rates or charges is required to refund to the pipeline company that published the tariff, not less than five days prior to the refund date ordered by the Commission under paragraph (c)(1) of this section,

(i) That portion of the unjustified rates or charges shared, and

(ii) The appropriate interest as required in paragraph (c)(2) of this section for the period during which the refundable amounts were held.

The pipeline company that published the tariff shall, on the date set by the Commission in its final order, make refunds with interest to the appropriate shipper for the full period during which the refundable amounts were held.

[Order 273, 48 FR 1289; Jan. 12, 1983]

§ 341.0 Definitions; application.

(a) Definitions. (1) Carrier means an oil pipeline subject to the Commission's jurisdiction under the Interstate Commerce Act.

(2) Concurrence means the agreement of a carrier to participate in the joint rates or regulations published by another carrier.

(3) Local rate means a rate for service over the lines or routes of only one carrier.

(4) Local tariffs means tariffs which contain only local rates.

(5) Joint rate means a rate that applies for service over the lines or routes of two or more carriers made by an agreement between the carriers, effected by a concurrence or power of attorney.

(6) Joint tariffs means tariffs which contain only joint rates.

(7) Posting or post means making current and proposed and tariffs suspended for more than a nominal period available on a carriers' public Web site.

(8) Proportional rates means rates published to apply only to traffic having a prior transportation movement, a subsequent transportation movement, or both.

(9) Rule means any regulation or condition of service stated in the tariff which affects any rate or service provided by the carrier.

(10) Subscriber means a shipper or a person who regularly is furnished a copy of a particular tariff publication (including reissues and amendments) by the publishing carrier or agent.

(11) Tariff publication means all parts of a filed tariff, including revised pages, supplements and sections.

(12) Through rates means the total rates from point of origin to destination. They may be local rates, joint rates, or a combination of separately established rates.

(13) Section means an individual portion of a tariff that is tracked and accorded appropriate legal status (proposed, suspended, effective). A section is the smallest portion of a tariff that can be submitted as part of a tariff filing.

(b) General application. (1) Each carrier must publish, post, and file with the Commission tariff publications which contain in clear, complete, and specific form all the rules and regulations governing the rates and charges for services performed in accordance with the tariff. Tariffs must be published in a format that ensures the tariffs are readable and that their terms and conditions are easy to understand and apply.

(2) The Commission may reject, or may require modification, correction, or reissuance of, any tariff publication or other document not in compliance with the law.

(3) All tariffs filed on or after December 6, 1993 must conform to the regulations of this part. Tariffs which are on file as of that date will not have to be reissued solely to conform to this part.

(4) Each carrier must post and maintain a complete and current set of all proposed, current, and suspended tariff publications which it has issued or to which it is a party. The carrier must identify in its posted tariff files any tariff publication under suspension and investigation. Each carrier must afford inquirers reasonable opportunity to examine its posted tariff files.

[58 FR 58773, Nov. 4, 1993, as amended by Order 606, 64 FR 44404, Aug. 16, 1999; Order 714, 73 FR 57536, Oct. 3, 2008; Order 780, 78 FR 32098, May 29, 2013]

§ 341.1 Electronic filing of tariffs and related materials.

(a) General rule. Filings of tariff publications and related materials must be made electronically.

(b) Requirement for signature. All filings must be signed in compliance with the following:

(1) The signature on a filing constitutes a certification that the contents are true to the best knowledge and belief of the signer, and that the signer possesses full power and authority to sign the filing.

(2) A filing must be signed by one of the following:

(i) The person on behalf of whom the filing is made;

(ii) An officer, agent, or employee of the company, governmental authority, agency, or instrumentality on behalf of which the filing is made; or,

(iii) A representative qualified to practice before the Commission under § 385.2101 of this chapter who possesses authority to sign.

(3) All signatures on the filing or any document included in the filing must comply, where applicable, with the requirements in § 385.2005 of this chapter with respect to sworn declarations or statements and electronic signatures.

(c) Format requirements for electronic filing. The requirements and formats for electronic filing are listed in instructions for electronic filing and for each form. These formats are available through the Commission's website, https://www.ferc.gov.

(d) Only filings filed and designated as filings with statutory action dates in accordance with these electronic filing requirements and formats will be considered to have statutory action dates. Filings not properly filed and designated as having statutory action dates will not become effective, pursuant to the Interstate Commerce Act, should the Commission not act by the requested action date.

[Order 714, 73 FR 57536, Oct. 3, 2008, as amended by Order 714-A, 79 FR 29077, May 21, 2014; Order 899, 88 FR 74032, Oct. 30, 2023]

§ 341.2 Filing requirements.

(a) Service of filings. (1) Carriers must serve tariff publications and justifications to each shipper and subscriber. Such service shall be made in accordance with the requirements of § 385.2010 of this chapter.

(2) Unless it seeks a waiver of electronic service, each customer or party entitled to service under this paragraph (a) must notify the company of the e-mail address to which service should be directed. A customer or party may seek a waiver of electronic service by filing a waiver request under Part 390 of this chapter providing good cause for its inability to accept electronic service.

(b) Notice period. All tariff publications (except for suspension supplements, adoption notices, adoption supplements, and tariff indexes) must be filed with the Commission and posted not less than 30, nor more than 60, days prior to the proposed effective date, unless a different notice period is authorized by the Commission. The notice period shall begin the first full day after the tariff publication is filed with the Commission and shall end on the last day prior to the tariff publication effective date.

(c) Transmittal letter—(1) Contents. Letters of transmittal must describe the filing and explain any changes to the carrier's rates, rules, terms or conditions of service; state if a waiver is being requested, and specify the statute, section, regulation, policy or order requested to be waived; and identify the tariffs supplemental numbers, or tariff sections and the proposed effective date of the tariff publication. Carriers must provide to the Commission, in the letter of transmittal accompanying the filing of a tariff publication containing a joint carrier, the address, phone number, and a contact for each joint carrier listed in the tariff publication.

(2) Certification. Letters of transmittal must certify that the filing has been sent to each subscriber of the tariff publication pursuant to paragraph (a) of this section. For service made on paper, the letters of transmittal must certify that the filing has been sent to each customer or party by first class mail or other agreed-upon means. If there are no subscribers, letters of transmittal must so certify.

[58 FR 58773, Nov. 4, 1993, as amended by Order 606, 64 FR 44404, Aug. 16, 1999; Order 714, 73 FR 57536, Oct. 3, 2008; Order 780, 78 FR 32098, May 29, 2013]

§ 341.3 Form of tariff.

(a) Tariffs may be filed either by dividing the tariff into tariff sections or as an entire document.

(b) Contents of tariff. All tariff publications must contain the following information in the following order:

(1) Title page. The title page of each tariff must contain the following information:

(i) The FERC tariff number designation, in the upper right hand corner, numbered consecutively, and the FERC tariff number designation of the tariff that is canceled, if any, under it;

(ii) The corporate name of the carrier;

(iii) The type of rates, e.g., local, joint, or proportional, and the commodity to which the tariff applies, e.g., crude, petroleum product, or jet fuel;

(iv) Governing tariffs, e.g., separate “rules and regulations” tariffs, if any;

(v) The specific Commission order pursuant to which the tariff is issued;

(vi) The issue date, which must be shown on the lower left side, and the effective date, which must be shown on the lower right side;

(vii) The expiration date, if applicable;

(viii) The name of the issuing officer or duly appointed official issuing the tariff, the complete street and mailing address of the carrier, and the name and phone number of the individual responsible for compiling the tariff publication.

(2) Table of contents. Tariffs of more than nine pages in length must contain a table of contents. A table of contents is optional for tariffs which are less than 10 pages in length.

(3) A list of carriers participating in joint tariffs.

(4) Index of Commodities.

(5) Explanatory statements. These statements must explain the proper application of rates and rules.

(6) Rules governing tariff publications. (i) All rules affecting the rates or the services provided for in the tariff publication must be included. A special rule affecting a particular item or rate must be referred to specifically in that item or in connection with that rate.

(ii) Each rule must be given a separate item number, (e.g., Item No. 1), and the title of each rule must be distinctive.

(iii) Except as provided in § 341.10, tariffs may not include any rules that substitute for any rates named in the tariff or found in any other tariff. Rules may not provide that traffic of any nature will be “transported only by special agreement” or any other provision of similar meaning.

(iv) Rules may be separately published in a general rules tariff when it is not desirable or practicable to include the governing rules in the rate tariff. Rate tariffs that do not contain rules must make specific reference, by FERC Tariff number, to the governing general rules tariff.

(v) When joint rate tariffs refer to a separate governing rules tariff, such separate tariff must be concurred in by all joint carriers.

(7) Statement of rates. Rates must be stated explicitly in cents, or in dollars and cents, per barrel or other specified unit. The names or designations of the places from and to which the rates apply must be arranged in a simple and systematic manner. Any related services performed by the carrier in connection with the rates must be clearly identified and explained. Duplicative or conflicting rates for the same service are prohibited.

(8) Routing. Routing over which the rates apply must be stated so that the actual routes may be ascertained. This may be accomplished by stating that the rates apply via all routes of the carrier except as otherwise specifically stated in the tariff.

(9) Explanation of abbreviations and reference marks. Reference marks, abbreviations, and note references must be explained at the end of each tariff publication. U.S. Postal Service state abbreviations and other commonly used abbreviations need not be explained.

(10) Changes to be indicated in tariff or supplement.

(i) All tariff publications must identify where changes have been made in existing rates or charges, rules, regulations or practices, or classifications. One of the following letter designations or uniform symbols may be used to indicate the change, and insertions, other than to tables and rates, must be indicated by either highlight, background shading, bold, or underline, with deleted text indicated by strike-through:

Description | Option 1 | Option 2

Increase | > | [I]

Decrease | < | [D]

Change in wording only | ⁁ | [W]

Cancel | / | [C]

Reissued Item | ∼ | [R]

Unchanged Rate | = | [U]

New | + | [N]

(ii) Reissued items must include in the square or brackets the number of the tariff supplement where the item was first issued or amended. If the letter designation is used, the number of the supplement must be shown together with the letter. The references must be explained at the end of the tariff. For example: “[R2] Reissued from Supplement No. 2, effective [specify date].”

(iii) The symbols and letter designations contained in paragraph (b)(10)(i) of this section must not be used for any other purpose.

(iv) When the same change is made in all or in substantially all rates in a tariff, a tariff supplement, or a tariff or tariff supplement page, that fact and the nature of the change must be indicated in distinctive type at the top of the title page of the issue, or at the top of each page, as appropriate. For example: “All rates in this issue are increased,” or “All rates on this page are reduced unless otherwise indicated.”

(v) When a tariff publication that cancels a previous tariff publication does not include points of origin or destination, or rates, rules, or routes that were contained in the prior tariff publication, the new tariff publication must indicate the cancellation. If such omissions effect changes in charges or services, that fact must be indicated by the use of the symbols prescribed in paragraph (b)(10)(i) of this section.

(vi) Only revisions to tariff provisions identified in the filing constitute the tariff filing. Revisions to unidentified portions of the rate schedule or tariff are not considered part of the filing nor will any acceptance of the filing by the Commission constitute acceptance of such unmarked changes.

(11) Tariff publications must be consecutively numbered.

[Order 561, 58 FR 58773, Nov. 4, 1993, as amended by Order 714, 73 FR 57536, Oct. 3, 2008; Order 780, 78 FR 32098, May 29, 2013]

§ 341.4 Amendments of tariff filings.

A carrier may file to amend or modify a tariff contained in a tariff filing at any time during the pendency of the filing. Such filing will toll the notice period as provided in § 341.2(b) for the original filing, and the filing becomes provisionally effective 31 days from the original filing and, in the absence of Commission action, fully effective 31 days from the date of the filing of amendment or modification.

[Order 780, 78 FR 32098, May 29, 2013]

§ 341.5 Cancellation of tariffs.

Carriers must cancel tariffs when the service or transportation movement is terminated. If the service in connection with the tariff is no longer in interstate commerce, the tariff publication must so state. Carrier must file such cancellations within 30 days of the termination of service.

[Order 780, 78 FR 32098, May 29, 2013]

§ 341.6 Adoption of tariff by a successor.

Whenever the tariff(s), or a portion thereof, of a carrier on file with the Commission are to be adopted by another carrier as a result of an acquisition, merger, or name change, the succeeding company must file with the Commission, and post within 30 days after such succession, the tariff, or portion thereof, that has been adopted in the electronic format required by § 341.1 bearing the name of the successor company.

[Order 780, 78 FR 32098, May 29, 2013]

§ 341.7 Concurrences.

Concurrences must be shown in the carrier's tariff and maintained consistent with the requirements of Part 341 of this chapter.

[Order 780, 78 FR 32099, May 29, 2013]

§ 341.8 Terminal and other services.

Carriers must publish in their tariffs rules governing such matters as prorationing of capacity, demurrage, odorization, carrier liability, quality bank, reconsignment, in-transit transfers, storage, loading and unloading, gathering, terminalling, batching, blending, commingling, and connection policy, and all other charges, services, allowances, absorptions and rules which in any way increase or decrease the amount to be paid on any shipment or which increase or decrease the value of service to the shipper.

§ 341.9 Index of tariffs.

(a) In general. Each carrier with more than two tariffs or concurrences must post on its public Web site a complete index of all effective tariffs to which it is a party, either as an initial, intermediate, or delivering carrier. The index must be arranged in sections as indicated in paragraphs (b), (c), and (d) of this section and must show as to each tariff:

(1) The FERC Tariff number;

(2) The full name of the issuing carrier or agent;

(3) The type of tariff or description of the traffic to which it applies, including origin and destination points; and

(4) Whether the tariff contains rates for transportation by mode other than pipeline.

(5) Product Shipped and Origin. Each index must identify, for each tariff, the product or products being shipped and the origin and destination points specific to each product or products.

(b) Updates. The index of tariffs must be updated within 90 days of any change to an effective tariff.

[Order 561, 58 FR 58773, Nov. 4, 1993, as amended by Order 780, 78 FR 32099, May 29, 2013]

§ 341.10 Application of rates to intermediate points.

(a) Applicability. (1) A carrier may provide in its tariff that existing rates between points named in the tariff will be applied to transportation movements from intermediate origin points not named in the tariff to named destination points, and from named origin points to intermediate destination points not named in the tariff.

(2) A carrier must file a tariff publication applicable to the transportation movements within 30 days of the start of the service if the intermediate point is to be used on a continuous basis for more than 30 days.

(b) Intermediate point commodity rate regulations—(1) Intermediate origin points. The rate for service provided to a published destination point from an origin point not specifically named in the tariff, but located intermediate to published origin and destination points, must be the same as the published rate from the next more distant origin point. Application of this provision is subject to the following:

(i) If branch or diverging lines create two or more “next more distant” points, the carrier must apply the rate which results in the lowest charge.

(ii) If the intermediate point is located between two published origin points, the carrier must apply the rate which results in the higher charge.

(iii) If the intermediate point is between more than two published origin points due to branch or diverging lines, the carrier must eliminate all such points except that from which the lowest charge is applicable.

(iv) If there is in any other tariff a commodity rate from the proposed intermediate origin point that is applicable to the same movement, the carrier should not apply this rule from such intermediate point.

(2) Intermediate destination points. The rate for service provided from a published origin point to a destination point not specifically named in the tariff, but located intermediate to published origin and destination points, must be the same as the published rate to the next more distant destination point. Application of this provision is subject to the following:

(i) If branch or diverging lines create two or more “next more distant” points, the carrier must apply the rate which results in the lowest charge.

(ii) If the intermediate point is located between two published destination points, the carrier must apply the rate which results in the higher charge.

(iii) If the intermediate point is between more than two published destination points due to branch or diverging lines, the carrier must eliminate all such points except that from which the lowest charge is applicable.

(iv) If there is in any other tariff a commodity rate to the proposed intermediate destination point that is applicable to the same movement, the carrier should not apply the provisions of this rule to such intermediate point.

(3) Intermediate origin and destination points. Both paragraphs (b)(1) and (b)(2) of this section may apply in connection with the same rate. In this instance, both regulations should be used to establish rates from intermediate points of origin to intermediate points of destination.

§ 341.11 Rejection of tariff publications and other filed materials.

(a) Basis for rejection. The Commission may reject tariff publications or any other material submitted for filing that fail to comply with the requirements set forth in this part or violate any statute, or any regulation, policy or order of the Commission.

(b) Numbering and notating tariff publications. The FERC Tariff number assigned to a tariff publication that has been rejected may not be used again.

[Order 561, 58 FR 58773, Nov. 4, 1993, as amended by Order 780, 78 FR 32099, May 29, 2013]

§ 341.12 Informal submissions.

Carriers may informally submit tariff publications or related material for suggestions of Staff prior to the filing of the tariff publications with the Commission.

§ 341.13 Withdrawal of proposed tariff publications.

(a) Proposed tariff publications. A proposed tariff publication which is not yet effective may be withdrawn at any time by filing a notice with the Commission with a certification that all subscribers have been notified by copy of such withdrawal.

(b) Tariff publications that are subject to investigation. A tariff publication that has been permitted to become effective subject to investigation may be withdrawn at any time by filing a notice with the Commission, which includes a transmittal letter, a certification that all subscribers have been notified of the withdrawal, and the previous tariff provisions that are to be reinstated upon withdrawal of the tariff publication under investigation. Such withdrawal shall be effective immediately upon the submission of the notice, unless a specific effective date is set forth in the notice, and must have the following effects:

(1) Any proceeding with respect to such tariff publication shall be terminated;

(2) The previous tariff rate shall be reinstated; and

(3) Any amounts collected under the withdrawn tariff publication which are in excess of the previous tariff rate shall be refunded within 30 days of the withdrawal with interest as calculated by § 340.1 of this chapter.

(c) Numbering and notating tariff publications. The FERC Tariff number assigned to a tariff publication which has been withdrawn may not be used again.

[Order 561, 58 FR 58773, Nov. 4, 1993, as amended by Order 714, 73 FR 57537, Oct. 3, 2008; Order 780, 78 FR 32099, May 29, 2013]

§ 341.14 Special permission.

(a) Procedure. Applications for waiver of the notice and tariff requirements of section 6(3) of the interstate Commerce Act must be filed by the carrier concurrently with the tariff publication being proposed. The letter of transmittal must identify the filing as requesting a waiver under section 6(3) of the Interstate Commerce Act. The application must state in detail any unusual circumstance or emergency situation that supports the requested waiver. If the application requests permission to make changes in joint tariffs, it must state that it is made on behalf of all carriers party to the proposed change. Tariff publications issued on short notice must contain the following statement on the Title Pages:

Issued on [insert number] days notice under authority of 18 CFR 341.14. This tariff publication is conditionally accepted subject to refund pending a 30 day review period.

(b) Conditional acceptance subject to refund. To permit short-notice filings to become effective as requested, the tariff publications filed concurrently with special permission requests for short (less than 30 days) notice will be deemed conditionally accepted for filing, subject to refund, until the Commission has had a full 30-day review period in which to process the filing. Refunds will be collected with interest as calculated according to § 340.1 of this chapter. The refund obligation will automatically terminate with no refunds due at the end of the full 30-day notice period absent an order to the contrary issued by the Commission.

(c) Granting automatic permission. The special permission requested will be deemed automatically granted at the end of the full 30-day notice period absent an order denying such request.

§ 341.15 Long and short haul or aggregate of intermediate rates.

(a) Requests for relief from section 4. Carriers may file requests for relief from the provisions of section 4 of the Interstate Commerce Act in order to charge a greater amount for a shorter distance over the same line or route in the same direction, or to charge greater compensation as a through rate than the aggregate of the intermediate rates. Such request will be deemed granted unless the Commission denies the request within 30 days of the filing.

(b) Information required to be filed. A request for section 4 relief must contain the following information:

(1) The names of the carriers for which the relief is being requested.

(2) The FERC tariff numbers which contain the rates or charges referred to in the application, and identification of all the particular and related rates in question delineating origin and destination points.

(3) An accurate and complete statement giving the basis and reasoning why section 4 relief is necessary.

(4) A statement that the lower rates for longer than for shorter hauls over the same line or route are reasonably compensatory.

(5) A map showing the pipelines and origin and destination points in question and other pertinent information.

(c) Filing tariff publications concurrent with application. Applications for section 4 relief must be filed concurrently with the tariff publication filing establishing those rates. The transmittal letter must identify the filing as requesting section 4 relief.

(d) Tariff statement. Tariff publications filed containing such rates shall plainly state on the title page of the tariff publication that the rates contained therein contravene section 4 of the Interstate Commerce Act.

(e) Rounding through rates. When a carrier aggregates intermediate rates to make up through rates, it may round the resulting through rate to the nearest 0.5 whole cent.

§ 342.0 Applicability.

(a) Except as provided in paragraph (b) of this section, rate changes by oil pipelines shall be governed by this part.

(b) Exception for the Trans-Alaska Pipeline. This part shall not apply to the Trans-Alaska Pipeline authorized by the Trans-Alaska Pipeline Authorization Act (43 U.S.C. 1651, et seq.) or to any pipeline delivering oil directly or indirectly to the Trans-Alaska Pipeline.

§ 342.1 General rule.

Each carrier subject to the jurisdiction of the Commission under the Interstate Commerce Act:

(a) Must establish its initial rates subject to such Act pursuant to § 342.2; and

(b) Must make any change in existing rates pursuant to § 342.3 or § 342.4, whichever is applicable, unless directed otherwise by the Commission.

§ 342.2 Establishing initial rates.

A carrier must justify an initial rate for new service by:

(a) Filing cost, revenue, and throughput data supporting such rate as required by part 346 of this chapter; or

(b) Filing a sworn affidavit that the rate is agreed to by at least one non-affiliated person who intends to use the service in question, provided that if a protest to the initial rate is filed, the carrier must comply with paragraph (a) of this section.

[Order 561, 58 FR 58779, Nov. 4, 1993, as amended at 59 FR 59146, Nov. 16, 1994]

§ 342.3 Indexing.

(a) Rate changes. A rate charged by a carrier may be changed, at any time, to a level which does not exceed the ceiling level established by paragraph (d) of this section, upon compliance with the applicable filing and notice requirements and with paragraph (b) of this section. A filing under this section proposing to change a rate that is under investigation and subject to refund, must take effect subject to refund.

(b) Information required to be filed with rate changes. The carrier must comply with Part 341 of this title. Carriers must specify in their letters of transmittal required in § 341.2(c) of this chapter the rate schedule to be changed, the proposed new rate, the prior rate, the prior ceiling level, and the applicable ceiling level for the movement. No other rate information is required to accompany the proposed rate change.

(c) Index year. The index year is the period from July 1 to June 30.

(d) Derivation of the ceiling level. (1) A carrier must compute the ceiling level for each index year by multiplying the previous index year's ceiling level by the most recent index published by the Commission. The index will be published by the Commission prior to June 1 of each year.

(2) The index published by the Commission will be based on the change in the final Producer Price Index for Finished Goods (PPI-FG), seasonally adjusted, as published by the U.S. Department of Labor, Bureau of Labor Statistics, for the two calendar years immediately preceding the index year. The index will be calculated by dividing the PPI-FG for the calendar year immediately preceding the index year, by the previous calendar year's PPI-FG.

(3) A carrier must compute the ceiling level each index year without regard to the actual rates filed pursuant to this section. All carriers must round their ceiling levels each index year to the nearest hundredth of a cent.

(4) For purposes of computing the ceiling level for the period January 1, 1995 through June 30, 1995, a carrier must use the rate in effect on December 31, 1994 as the previous index year's ceiling level in the computation in paragraph (d)(1) of this section. If the rate in effect on December 31, 1994 is subsequently lowered by Commission order pursuant to the Interstate Commerce Act, the ceiling level based on such rate must be recomputed, in accordance with paragraph (d)(1) of this section, using the rate established by such Commission order in lieu of the rate in effect on December 31, 1994.

(5) When an initial rate, or rate changed by a method other than indexing, takes effect during the index year, such rate will constitute the applicable ceiling level for that index year. If such rate is subsequently lowered by Commission order pursuant to the Interstate Commerce Act, the ceiling level based on such rate must be recomputed, in accordance with paragraph (d)(1) of this section, using the rate established by such Commission order as the ceiling level for the index year which includes the effective date of the rate established by such Commission order.

(e) Rate decreases. If the ceiling level computed pursuant to § 342.3(d) is below the filed rate of a carrier, that rate must be reduced to bring it into compliance with the new ceiling level; provided, however, that a carrier is not required to reduce a rate below the level deemed just and reasonable under section 1803(a) of the Energy Policy Act of 1992, if such section applies to such rate or to any prior rate. The rate decrease must be accomplished by filing a revised tariff publication with the Commission to be effective July 1 of the index year to which the reduced ceiling level applies.

[Order 561, 58 FR 58779, Nov. 4, 1993, as amended by Order 561-A, 59 FR 40256, Aug. 8, 1994; 59 FR 59146, Nov. 16, 1994; Order 606, 64 FR 44405, Aug. 16, 1999; Order 650, 69 FR 53801, Sept. 3, 2004]

§ 342.4 Other rate changing methodologies.

(a) Cost-of-service rates. A carrier may change a rate pursuant to this section if it shows that there is a substantial divergence between the actual costs experienced by the carrier and the rate resulting from application of the index such that the rate at the ceiling level would preclude the carrier from being able to charge a just and reasonable rate within the meaning of the Interstate Commerce Act. A carrier must substantiate the costs incurred by filing the data required by part 346 of this chapter. A carrier that makes such a showing may change the rate in question, based upon the cost of providing the service covered by the rate, without regard to the applicable ceiling level under § 342.3.

(b) Market-based rates. A carrier may attempt to show that it lacks significant market power in the market in which it proposes to charge market-based rates. Until the carrier establishes that it lacks market power, these rates will be subject to the applicable ceiling level under § 342.3.

(c) Settlement rates. A carrier may change a rate without regard to the ceiling level under § 342.3 if the proposed change has been agreed to, in writing, by each person who, on the day of the filing of the proposed rate change, is using the service covered by the rate. A filing pursuant to this section must contain a verified statement by the carrier that the proposed rate change has been agreed to by all current shippers.

[Order 561, 58 FR 58779, Nov. 4, 1993, as amended at 59 FR 59146, Nov. 16, 1994]

§ 343.0 Applicability.

(a) General rule. The Commission's Rules of Practice and Procedure in part 385 of this chapter will govern procedural matters in oil pipeline proceedings under part 342 of this chapter and under the Interstate Commerce Act, except to the extent specified in this part.

§ 343.1 Definitions.

For purposes of this part, the following definitions apply:

(a) Complaint means a filing challenging an existing rate or practice under section 13(1) of the Interstate Commerce Act.

(b) Protest means a filing, under section 15(7) of the Interstate Commerce Act, challenging a tariff publication.

[Order 561, 58 FR 58780, Nov. 4, 1993, as amended by Order 578, 60 FR 19505, Apr. 19, 1995]

§ 343.2 Requirements for filing interventions, protests and complaints.

(a) Interventions. Section 385.214 of this chapter applies to oil pipeline proceedings.

(b) Standing to file protest. Only persons with a substantial economic interest in the tariff filing may file a protest to a tariff filing pursuant to the Interstate Commerce Act. Along with the protest, a verified statement that the protestor has a substantial economic interest in the tariff filing in question must be filed.

(c) Other requirements for filing protests or complaints—(1) Rates established under § 342.3 of this chapter. A protest or complaint filed against a rate proposed or established pursuant to § 342.3 of this chapter must allege reasonable grounds for asserting that the rate violates the applicable ceiling level, or that the rate increase is so substantially in excess of the actual cost increases incurred by the carrier that the rate is unjust and unreasonable, or that the rate decrease is so substantially less than the actual cost decrease incurred by the carrier that the rate is unjust and unreasonable. In addition to meeting the requirements of the section, a complaint must also comply with all the requirements of § 385.206, except § 385.206(b)(1) and (2).

(2) Rates established under § 342.4(c) of this chapter. A protest or complaint filed against a rate proposed or established under § 342.4(c) of this chapter must allege reasonable grounds for asserting that the rate is so substantially in excess of the actual cost increases incurred by the carrier that the rate is unjust and unreasonable. In addition to meeting the requirements of the section, a complaint must also comply with all the requirements of § 385.206, except § 385.206(b)(1) and (2).

(3) Non-rate matters. A protest or complaint filed against a carrier's operations or practices, other than rates, must allege reasonable grounds for asserting that the operations or practices violate a provision of the Interstate Commerce Act, or of the Commission's regulations. In addition to meeting the requirements of this section, a complaint must also comply with the requirements of § 385.206.

(4) A protest or complaint that does not meet the requirements of paragraphs (c)(1), (c)(2), or (c)(3) of this section, whichever is applicable, will be dismissed.

[Order 561, 58 FR 58780, Nov. 4, 1993, as amended by Order 602, 64 FR 17097, Apr. 8, 1999; Order 606, 64 FR 44405, Aug. 16, 1999]

§ 343.3 Filing of protests and responses.

(a) Protests. Any protest pursuant to section 15(7) of the Interstate Commerce Act must be filed not later than 15 days after the filing of a tariff publication. If the carrier submits a separate letter with the filing, providing a telefax number and contact person, and requesting all protests to be telefaxed to the carrier by a protestant, any protest must be so telefaxed to the pipeline at the time the protest is filed with the Commission. Only persons with a substantial economic interest in the tariff filing may file a protest to a tariff filing pursuant to the Interstate Commerce Act. Along with the protest, the protestant must file a verified statement which must contain a reasonably detailed description of the nature and substance of the protestant's substantial economic interest in the tariff filing.

(b) Responses. The carrier may file a response to a protest no later than 5 days from the filing of the protest.

(c) Commission action. Commission action, including any hearings or other proceedings, on a protest will be limited to the issues raised in such protest. If a filing is protested, before the effective date of the tariff publication or within 30 days of the tariff filing, whichever is later, the Commission will determine whether to suspend the tariff and initiate a formal investigation.

(d) Termination of investigation. Withdrawal of the protest, or protests, that caused the initiation of an investigation automatically terminates the investigation.

[Order 561, 58 FR 58780, Nov. 4, 1993, as amended by Order 561-A, 59 FR 40256, Aug. 8, 1994]

§ 343.4 Procedure on complaints.

(a) Responses. The carrier must file an answer to a complaint filed pursuant to section 13(1) of the Interstate Commerce Act within 20 days after the filing of the complaint in accordance with Rule 206.

(b) Commission action. Commission action, including any hearings or other proceedings, on a complaint will be limited to the issues raised in the complaint.

[Order 561, 58 FR 58780, Nov. 4, 1993, as amended by Order 602, 64 FR 17097, Apr. 8, 1999]

§ 343.5 Required negotiations.

The Commission or other decisional authority may require parties to enter into good faith negotiations to settle oil pipeline rate matters. The Commission will refer all protested rate filings to a settlement judge pursuant to § 385.603 of this chapter for recommended resolution. Failure to participate in such negotiations in good faith is a ground for decision against the party so failing to participate on any issue that is the subject of negotiation by other parties.

[Order 578, 60 FR 19505, Apr. 19, 1995]

§ 344.1 Applicability.

The provisions of this part will apply to quotations or tenders made by all pipeline common carriers to the United States Government, or any agency or department thereof, for the transportation, storage, or handling of petroleum and petroleum products at reduced rates as permitted by section 22 of the Interstate Commerce Act. Excepted are filings which involve information, the disclosure of which would endanger the national security.

[Order 561, 58 FR 58778, Nov. 4, 1993]

§ 344.2 Manner of submitting quotations.

(a) The quotation or tender must be submitted to the Commission concurrently with the submittal of the quotation or tender to the Federal department or agency for whose account the quotation or tender is offered or the proposed services are to be rendered.

(b) [Reserved]

(c) Filing procedure. (1) The quotation must be filed with a letter of transmittal that prominently indicates that the filing is in accordance with section 22 of the Interstate Commerce Act.

(2) All filings pursuant to this part must be filed electronically consistent with §§ 341.1 and 341.2 of this chapter.

(d) Numbering. The copies of quotations or tenders which are filed with the Commission by each carrier must be numbered consecutively.

(e) Supersession of a quotation or tender. A quotation or tender which supersedes a prior quotation or tender must, by a statement shown immediately under the number of the new document, cancel the prior document number.

[Order 561, 58 FR 58778, Nov. 4, 1993, as amended by Order 714, 73 FR 57537, Oct. 3, 2008]

§ 346.1 Content of filing for cost-of-service rates.

A carrier that seeks to establish rates pursuant to § 342.2(a) of this chapter, or a carrier that seeks to change rates pursuant to § 342.4(a) of this chapter, or a carrier described in § 342.0(b) of this chapter that seeks to establish or change rates by filing cost, revenue, and throughput data supporting such rates, other than pursuant to a Commission-approved settlement, must file, consistent with the requirements of §§ 341.1 and 341.2 of this chapter:

(a) A letter of transmittal which conforms to §§ 341.2(c) and 342.4(a) of this chapter;

(b) The proposed tariff; and

(c) The statements and supporting workpapers set forth in § 346.2.

[59 FR 59146, Nov. 16, 1994, as amended by Order 588, 61 FR 38569, July 25, 1996; Order 714, 73 FR 57537, Oct. 3, 2008]

§ 346.2 Material in support of initial rates or change in rates.

A carrier that files for rates pursuant to § 342.2(a) or § 342.4(a) of this chapter, or a carrier described in § 342.0(b) that files to establish or change rates by filing cost, revenue, and throughput data supporting such rates, other than pursuant to a Commission-approved settlement, must file the following statements, schedules, and supporting workpapers. The statement, schedules, and workpapers must be based upon an appropriate test period.

(a) Base and test periods defined. (1) For a carrier which has been in operation for at least 12 months:

(i) A base period must consist of 12 consecutive months of actual experience. The 12 months of experience must be adjusted to eliminate nonrecurring items (except minor accounts). The filing carrier may include appropriate normalizing adjustments in lieu of nonrecurring items.

(ii) A test period must consist of a base period adjusted for changes in revenues and costs which are known and are measurable with reasonable accuracy at the time of filing and which will become effective within nine months after the last month of available actual experience utilized in the filing. For good cause shown, the Commission may allow reasonable deviation from the prescribed test period.

(2) For a carrier which has less than 12 months' experience, the test period may consist of 12 consecutive months ending not more than one year from the filing date. For good cause shown, the Commission may allow reasonable deviation from the prescribed test period.

(3) For a carrier which is establishing rates for new service, the test period will be based on a 12-month projection of costs and revenues.

(b) Cost-of-service summary schedule. This schedule must contain the following information:

(1) Total carrier cost of service for the test period.

(2) Throughput for the test period in both barrels and barrel-miles.

(3) For filings pursuant to § 342.4(a) of this chapter, the schedule must include the proposed rates, the rates which would be permitted under § 342.3 of this chapter, and the revenues to be realized from both sets of rates.

(c) Content of statements. Any cost-of-service rate filing must include supporting statements containing the following information for the test period.

(1) Statement A—total cost of service. This statement must summarize the total cost of service for a carrier (operating and maintenance expense, depreciation and amortization, return, and taxes) developed from Statements B through G described in paragraphs (c) (2) through (7) of this section.

(2) Statement B—operation and maintenance expense. This statement must set forth the operation, maintenance, administration and general, and depreciation expenses for the test period. Items used in the computations or derived on this statement must consist of operations, including salaries and wages, supplies and expenses, outside services, operating fuel and power, and oil losses and shortages; maintenance, including salaries and wages, supplies and expenses, outside services, and maintenance and materials; administrative and general, including salaries and wages, supplies and expenses, outside services, rentals, pensions and benefits, insurance, casualty and other losses, and pipeline taxes; and depreciation and amortization.

(3) Statement C—overall return on rate base. This statement must set forth the rate base for return purposes from Statement E in paragraph (c)(5) of this section and must also state the claimed rate of return and the application of the claimed rate of return to the overall rate base. The claimed rate of return must consist of a weighted cost of capital, combining the rate of return on debt capital and the real rate of return on equity capital. Items used in the computations or derived on this statement must include deferred earnings, equity ratio, debt ratio, weighted cost of capital, and costs of debt and equity.

(4) Statement D—income taxes. This statement must set forth the income tax computation. Items used in the computations or derived on this statement must show: return allowance, interest expense, equity return, annual amortization of deferred earnings, depreciation on equity AFUDC, underfunded or overfunded ADIT amortization amount, taxable income, tax factor, and income tax allowance.

(5) Statement E—rate base. This statement must set forth the return rate base. Items used in the computations or derived on this statement must include beginning balances of the rate base at December 31, 1983, working capital (including materials and supplies, prepayments, and oil inventory), accrued depreciation on carrier plant, accrued depreciation on rights of way, and accumulated deferred income taxes; and adjustments and end balances for original cost of retirements, interest during construction, AFUDC adjustments, original cost of net additions and retirements from land, original cost of net additions and retirements from rights of way, original cost of plant additions, original cost accruals for depreciation, AFUDC accrued depreciation adjustment, original cost depreciation accruals added to rights of way, net charge for retirements from accrued depreciation, accumulated deferred income taxes, changes in working capital (including materials and supplies, prepayments, and oil inventory), accrued deferred earnings, annual amortization of accrued deferred earnings, and amortization of starting rate base write-up.

(6) Statement F—allowance for funds used during construction. This statement must set forth the computation of allowances for funds used during construction (AFUDC) including the AFUDC for each year commencing in 1984 and a summary of AFUDC and AFUDC depreciation for the years 1984 through the test year.

(7) Statement G—revenues. This statement must set forth the gross revenues for the actual 12 months of experience as computed under both the presently effective rates and the proposed rates. If the presently effective rates are not at the maximum ceiling rate established under § 342.3 of this chapter, then gross revenues must also be computed and set forth as if the ceiling rates were effective for the 12 month period.

[59 FR 59146, Nov. 16, 1994, as amended by Order 588, 61 FR 38569, July 25, 1996; Order 606, 64 FR 44405, Aug. 16, 1999]

§ 346.3 Asset retirement obligations.

(a) A carrier that files material in support of initial rates or change in rates under § 346.2 and has recorded asset retirement obligations on its books must provide a schedule, as part of the supporting workpapers, identifying all cost components related to the asset retirement obligations that are included in the book balances of all accounts reflected in the cost of service computation supporting the proposed rates. However, all cost components related to asset retirement obligations that would impact the calculation of rate base, such as carrier property and related accumulated depreciation and accumulated deferred income taxes, may not be reflected in rates and must be removed from the rate base calculation through a single adjustment.

(b) A carrier seeking to recover nonrate base costs related to asset retirement costs in rates must provide, with its filing under § 346.2 of this part, a detailed study supporting the amounts proposed to be collected in rates.

(c) A carrier who has recorded asset retirement obligations on its books but is not seeking recovery of the asset retirement costs in rates, must remove all asset retirement obligations related cost components from the cost of service supporting its proposed rates.

[Order 631, 68 FR 19625, Apr. 21, 2003]

§ 347.1 Material to support request for newly established or changed property account depreciation studies.

(a) Means of filing. Filing of a request for new or changed property account depreciation rates must be made with the Secretary of the Commission.

(b) All filings under this Part must be made electronically pursuant to the requirements of §§ 341.1 and 341.2 of this chapter.

(c) Transmittal letter. Letters of transmittal must give a general description of the change in depreciation rates being proposed in the filing. Letters of transmittal must also certify that the letter of transmittal (not including the information to be provided, as identified in paragraphs (d) and (e) of this section) has been sent to each shipper and to each subscriber. If there are no subscribers, letters of transmittal must so state.

(d) Effectiveness of property account depreciation rates. (1) The proposed depreciation rates being established in the first instance must be used until they are either accepted or modified by the Commission. Rates in effect at the time of the proposed revision must continue to be used until the proposed revised rates are approved or modified by the Commission.

(2) When filing for approval of either new or changed property account depreciation rates, a carrier must provide information in sufficient detail to fully explain and justify its proposed rates.

(e) Information to be provided. The information in paragraphs (e)(1) through (5) of this section must be provided as justification for depreciation changes. Modifications, additions, and deletions to these data elements should be made to reflect the individual circumstances of the carrier's properties and operations. Any information in paragraphs (e)(1) through (5) of this section, the release of which would violate section 15(13) of the Interstate Commerce Act, must be provided in a format that will protect individual shippers.

(1) A brief summary relating to the general principles on which the proposed depreciation rates are based (e.g., why the economic life of the pipeline section is less then the physical life).

(2) An explanation of the organization, ownership, and operation of the pipeline.

(3) A table of the proposed depreciation rates by account.

(4) An explanation of the average remaining life on a physical basis and on an economic basis.

(5) The following specific background data must be submitted at the time of and concurrently with any request for the establishment of, or modification to, depreciation rates for carriers. If the information listed is not applicable, it may be omitted from the filing:

(i) Up-to-date engineering maps of the pipeline including the location of all gathering facilities, trunkline facilities, terminals, interconnections with other pipeline systems, and interconnections with refineries/plants. Maps must indicate the direction of flow.

(ii) A brief description of the carrier's operations and an estimate of any major near-term additions or retirements including the estimated costs, location, reason, and probable year of transaction.

(iii) The present depreciation rates being used by account.

(iv) For the most current year available and for the two prior years, a breakdown of the throughput (by type of product, if applicable) received with source (e.g. name of well, pipeline company) at each receipt point and throughput delivered at each delivery point.

(v) The daily average capacity (in barrels per day) and the actual average capacity (in barrels per day) for the most current year, by line section.

(vi) A list of shipments and their associated receipt points, delivery points, and volumes (in barrels) by type of product (where applicable) for the most current year.

(vii) For each primary carrier account, the latest month's book balances for gross plant and for accumulated reserve for depreciation.

(viii) An estimate of the remaining life of the system (both gathering and trunk lines) including the basis for the estimate.

(ix) For crude oil, a list of the fields or areas from which crude oil is obtained.

(x) If the proposed depreciation rate adjustment is based on the remaining physical life of the properties, a complete, or updated, if applicable, Service Life Data Form (FERC Form No. 73) through the most current year.

(xi) Estimated salvage value of properties by account.

[59 FR 59147, Nov. 16, 1994, as amended at 60 FR 358, Jan. 4, 1995; Order 714, 73 FR 57537, Oct. 3, 2008]

§ 348.1 Content of application for a market power determination.

(a) If, under § 342.4(b) of this chapter, a carrier seeks to establish that it lacks significant market power in the market in which it proposes to charge market-based rates, it must file and provide an application for such a determination. An application must include a statement of position and the information required by paragraph (c) of this section.

(b) The carrier's statement of position required by paragraph (a) of this section must include an executive summary of its statement of position and a statement of material facts in addition to its complete statement of position. The statement of material facts must include citation to the supporting statements, exhibits, affidavits, and prepared testimony.

(c) The carrier must include with its application the following information:

(1) Statement A—geographic market. This statement must describe the geographic markets in which the carrier seeks to establish that it lacks significant market power. The carrier must include the origin market and the destination market related to the service for which it proposes to charge market-based rates. The statement must explain why the carrier's method for selecting the geographic markets is appropriate.

(2) Statement B—product market. This statement must identify the product market or markets for which the carrier seeks to establish that it lacks significant market power. The statement must explain why the particular product definition is appropriate.

(3) Statement C—the carrier's facilities and services. This statement must describe the carrier's own facilities and services in the relevant markets identified in statements A and B in paragraphs (c) (1) and (2) of this section. The statement must include all pertinent data about the pipeline's facilities and services.

(4) Statement D—competitive alternatives. This statement must describe available transportation alternatives in competition with the carrier in the relevant markets and other competition constraining the carrier's rates in those markets. To the extent available, the statement must include all pertinent data about transportation alternatives and other constraining competition.

(5) Statement E—potential competition. This statement must describe potential competition in the relevant markets. To the extent available, the statement must include data about the potential competitors, including their costs, and their distance in miles from the carrier's terminals and major consuming markets.

(6) Statement F—maps. This statement must consist of maps showing the carrier's principal transportation facilities, the points at which service is rendered under its tariff, the direction of flow of each line, the location of each of its terminals, the location of each of its major consuming markets, and the location of the alternatives to the carrier, including their distance in miles from the carrier's terminals and major consuming markets. The statement must include a general system map and maps by geographic markets. The information required by this statement may be on separate pages.

(7) Statement G—market power measures. This statement must set forth the calculation of the market concentration of the relevant markets using the Herfindahl-Hirschman Index. The statement must also set forth the carrier's market share based on receipts in its origin markets and deliveries in its destination markets, if the Herfindahl-Hirschman Index is not based on those factors. The statement must also set forth the calculation of other market power measures relied on by the carrier. The statement must include complete particulars about the carrier's calculations.

(8) Statement H—other factors. This statement must describe any other factors that bear on the issue of whether the carrier lacks significant market power in the relevant markets. The description must explain why those other factors are pertinent.

(9) Statement I—prepared testimony. This statement must include the proposed testimony in support of the application and will serve as the carrier's case-in-chief, if the Commission sets the application for hearing. The proposed witness must subscribe to the testimony and swear that all statements of fact contained in the proposed testimony are true and correct to the best of his or her knowledge, information, and belief.

[59 FR 59160, Nov. 16, 1994]

§ 348.2 Procedures.

(a) All filings under this part must be made electronically pursuant to the requirements of §§ 341.1 and 341.2 of this chapter. A carrier seeking privileged treatment for all or any part of its filing must submit a request for privileged treatment in accordance with § 388.112 of this chapter.

(b) A carrier must provide a copy of its letter of transmittal and its proposed form of protective agreement to each shipper and subscriber on or before the day the material is transmitted to the Commission for filing.

(c) A letter of transmittal must describe the market-based rate filing, including an identification of each rate that would be market-based, and the pertinent tariffs, state if a waiver is being requested and specify the statute, section, subsection, regulation, policy or order requested to be waived. Letters of transmittal must be certified pursuant to § 341.1(b) of this chapter.

(d) An interested person must make a written request to the carrier for a copy of the carrier's complete application within 20 days after the filing of the application. The request must include an executed copy of the protective agreement. Any objection to the proposed form of protective agreement must be filed under § 385.212 of this chapter.

(e) A carrier must provide a copy of the complete application to the requesting person within seven days after receipt of the written request and an executed copy of the protective agreement.

(f) A carrier must provide copies as required by paragraphs (b) and (e) of this section by first-class mail or by other means of transmission agreed upon in writing.

(g) Any intervention or protest to the application must be filed within 60 days after the filing of the application and must be filed pursuant to §§ 343.2 (a) and (b) of this chapter. A protest must also be telefaxed if required by § 343.3(a) of this chapter.

(h) A protest filed against an application for a market power determination must set forth in detail the grounds for opposing the carrier's application, including responding to its position and information and, if desired, presenting information pursuant to § 348.1(c).

(i) After expiration of the date for filing protests, the Commission will issue an order in which it will summarily rule on the application or, if appropriate, establish additional procedures and the scope of the investigation.

[59 FR 59160, Nov. 16, 1994, as amended by Order 714, 73 FR 57537, Oct. 3, 2008; Order 769, 77 FR 65475, Oct. 29, 2012]

§ 349.1 Notice to audited person.

An audit conducted by the Commission or its staff under authority of the Interstate Commerce Act may result in a notice of deficiency or audit report or similar document containing a finding or findings that the audited person has not complied with a requirement of the Commission with respect to, but not limited to, the following: A filed tariff or tariffs, contracts, data, records, accounts, books, communications or papers relevant to the audit of the audited person; and the activities or operations of the audited person. The notice of deficiency, audit report or similar document may also contain one or more proposed remedies that address findings of noncompliance. Where such findings, with or without proposed remedies, appear in a notice of deficiency, audit report or similar document, such document shall be provided to the audited person, and the finding or findings, and any proposed remedies, shall be noted and explained. The audited person shall timely indicate in a written response any and all findings or proposed remedies, or both, in any combination, with which the audited person disagrees. The audited person shall have 15 days from the date it is sent the notice of deficiency, audit report or similar document to provide a written response to the audit staff indicating any and all findings or proposed remedies, or both, in any combination, with which the audited person disagrees, and such further time as the audit staff may provide in writing to the audited person at the time the document is sent to the audited person. The audited person may move the Commission for additional time to provide a written response to the audit staff and such motion shall be granted for good cause shown. Any initial order that the Commission subsequently may issue with respect to the notice of deficiency, audit report or similar document shall note, but not address on the merits, the finding or findings, or the proposed remedy or remedies, or both, in any combination, with which the audited person disagreed. The Commission shall provide the audited person 30 days to respond to the initial Commission order concerning a notice of deficiency, audit report or similar document with respect to the finding or findings or any proposed remedy or remedies, or both, in any combination, with which it disagreed.

[Order 675-A, 71 FR 29785, May 24, 2006]

§ 349.2 Response to notification.

Upon issuance of a Commission order that notes a finding or findings, or proposed remedy or remedies, or both, in any combination, with which the audited person has disagreed, the audited person may: Acquiesce in the findings and/or proposed remedies by not timely responding to the Commission order, in which case the Commission may issue an order approving them or taking other action; or challenge the finding or findings and/or any proposed remedies with which it disagreed by timely notifying the Commission in writing that it requests Commission review by means of a shortened procedure, or, if there are material facts in dispute which require cross-examination, a trial-type hearing.

§ 349.3 Shortened procedure.

If the audited person subject to a Commission order described in § 349.1 notifies the Commission that it seeks to challenge one or more audit findings, or proposed remedy or remedies, or both, in any combination, by the shortened procedure, the Commission shall thereupon issue a notice setting a schedule for the filing of memoranda. The person electing the use of the shortened procedure, and any other interested entities, including the Commission staff, shall file, within 45 days of the notice, an initial memorandum that addresses the relevant facts and applicable law that support the position or positions taken regarding the matters at issue. Reply memoranda shall be filed within 20 days of the date by which the initial memoranda are due to be filed. Only participants who filed initial memoranda may file reply memoranda. Subpart T of part 385 of this chapter shall apply to all filings. Within 20 days after the last date that reply memoranda under the shortened procedure may be timely filed, the audited person who elected the shortened procedure may file a motion with the Commission requesting a trial-type hearing if new issues are raised by a party. To prevail in such a motion, the audited person must show that a party to the shortened procedure raised one or more new issues of material fact relevant to resolution of a matter in the shortened procedure such that fundamental fairness requires a trial-type hearing to resolve the new issue or issues so raised. Parties to the shortened procedure and the Commission staff may file responses to the motion. In ruling upon the motion, the Commission may determine that some or all of the issues be litigated in a trial-type hearing.

§ 349.4 Form and style.

Each copy of such memorandum must be complete in itself. All pertinent data should be set forth fully, and each memorandum should set out the facts and argument as prescribed for briefs in § 385.706 of this chapter.

§ 349.5 Verification.

The facts stated in the memorandum must be sworn to by persons having knowledge thereof, which latter fact must affirmatively appear in the affidavit. Except under unusual circumstances, such persons should be those who would appear as witnesses if hearing were had to testify as to the facts stated in the memorandum.

§ 349.6 Determination.

If no formal hearing is had the matter in issue will be determined by the Commission on the basis of the facts and arguments submitted.

§ 349.7 Assignment for oral hearing.

Except when there are no material facts in dispute, when a person does not consent to the shortened procedure, the Commission will assign the proceeding for hearing as provided by subpart E of part 385 of this chapter. Notwithstanding a person's not giving consent to the shortened procedure, and instead seeking assignment for hearing as provided for by subpart E of part 385 of this chapter, the Commission will not assign the proceeding for a hearing when no material facts are in dispute. The Commission may also, in its discretion, at any stage in the proceeding, set the proceeding for hearing.