[Federal Register Volume 60, Number 196 (Wednesday, October 11, 1995)] [Rules and Regulations] [Pages 53019-53075] From the Federal Register Online via the Government Publishing Office [www.gpo.gov] [FR Doc No: 95-24722] ======================================================================= ----------------------------------------------------------------------- DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Parts 2, 157, 158, 201, 250, 260, 284, 381, and 385 [Docket No. RM95-4-000; Order No. 581 Revisions to Uniform System of Accounts, Forms, Statements, and Reporting Requirements for Natural Gas Companies Issued: September 28, 1995. AGENCY: Federal Energy Regulatory Commission, DOE. ACTION: Final rule. ----------------------------------------------------------------------- SUMMARY: The Federal Energy Regulatory Commission is amending its Uniform System of Accounts, its forms, and its reports and statements for natural gas companies. The amendments reflect the current regulatory environment of unbundled pipeline sales for resale at market-based prices and open-access transportation of natural gas. The Commission seeks to simplify and streamline its requirements to reduce the burden of respondents. [[Page 53020]] EFFECTIVE DATE: The final rule is effective November 13, 1995, except for the changes to the Uniform System of Accounts (Part 201). FOR FURTHER INFORMATION CONTACT: Jeffrey A. Braunstein, Office of the General Counsel, Federal Energy Regulatory Commission, 825 North Capitol Street, NE., Washington, DC 20426, (202) 208-2114. SUPPLEMENTARY INFORMATION: In addition to publishing the full text of this document, excluding Appendices B (FERC Form No. 2), C (FERC Form No. 2-A), and D (FERC Form No. 11), in the Federal Register, the Commission also provides all interested persons an opportunity to inspect or copy the contents of this document during normal business hours in Room 3104, 941 North Capitol Street, NE., Washington, DC 20426. The Commission Issuance Posting System (CIPS), an electronic bulletin board service, provides access to the texts of formal documents issued by the Commission. CIPS is available at no charge to the user and may be accessed using a personal computer with a modem by dialing (800) 856-3920. To access CIPS, set your communications software to 19200, 14400, 12000, 9600, 7200, 4800, 2400 or 1200bps, full duplex, no parity, 8 data bits, and 1 stop bit. The full text of this document will be available on CIPS in ASCII and WordPerfect 5.1 format. The complete text on diskette in Wordperfect format may also be purchased from the Commission's copy contractor, La Dorn Systems Corporation, also located in Room 3104, 941 North Capitol Street, NE., Washington, DC 20426. I. Introduction The Federal Energy Regulatory Commission (Commission) hereby amends its Uniform System of Accounts,1 its forms, and its reports and statements for natural gas companies.2 This Final Rule is a companion to the Commission's Final Rule ``Filing Requirements for Interstate Natural Gas Company Rate Schedules and Tariffs'', which amends Part 154 of the Commission's regulations and is issued contemporaneously with this rule. The Commission has received 41 comments on the Notice of Proposed Rulemaking (NOPR)3 in this docket from the commenters listed in Appendix A.4 \1\Section 8 of the Natural Gas Act (NGA), 15 U.S.C. 717g (1988), authorizes the Commission to prescribe rules and regulations concerning accounts, records and memoranda as necessary or appropriate for purposes of administering the NGA. The Commission may prescribe a system of accounts for jurisdictional companies and, after notice and opportunity for hearing, may determine the accounts in which particular outlays and receipts will be entered, charged, or credited. \2\Section 10 of the NGA, 15 U.S.C. 717i (1988), authorizes the Commission to prescribe rules and regulations concerning annual and other periodic or special reports, as necessary or appropriate for purposes of administering the NGA. The Commission may prescribe the manner and form in which such reports are to be made, and require from natural gas companies specific answers to all questions on which the Commission may need information. The reports must be made under oath unless the Commission otherwise specifies. \3\Revisions to Uniform System of Accounts, Forms, Statements, and Reporting Requirements for Natural Gas Pipelines, 60 FR 3141 (January 13, 1995), IV FERC Stats. & Regs. Proposed Regulations para. 32,512 (December 16, 1994). \4\Appendix A also sets forth the names by which the commenters are referred to herein. --------------------------------------------------------------------------- In brief, the Commission, in this rule, addresses the Uniform System of Accounts' treatment of gas in underground storage reservoirs and in pipelines,5 revenues6 and gas supply expenses,7 eliminates all accounts for Nonmajor respondents and redesignates accounts used only by Major respondents for use by all respondents. The Commission also changes or eliminates various forms, reports, and statements. This includes changes to, and deletions from, FERC Form No. 2 (Form No. 2), Annual report of Major natural gas companies, and FERC Form No. 2-A (Form No. 2-A), Annual report of Nonmajor natural gas companies, and FERC Form No. 11 (Form No. 11), Natural gas pipeline company monthly statement.8 \5\The Commission amends Account 117, Account 164.1, and other accounts that refer to Account 117. \6\The Commission amends Account 489 and Account 495. \7\The Commission amends Account 806, Account 813, and Account 823. \8\Form No. 2 consists of approximately 162 non-consecutively numbered pages and a four-page index. See 18 CFR 260.1. The current version bears OMB approval No. 1902-0028. Form No. 2-A consists of approximately 22 consecutively numbered pages, 1-22, and 32 non- consecutively numbered substitute pages from the Form No. 2 that may be used in lieu of the comparable pages in the first section. See 18 CFR 260.2. The current version bears OMB approval No. 1902-0030. Form No. 11 consists of approximately 4 consecutively numbered pages, 1-4. See 18 CFR 260.3. The current version bears OMB approval No. 1902-0032. --------------------------------------------------------------------------- The Commission is making the changes in order to create forms, reports, and statements that reflect the current regulatory environment of unbundled pipeline sales for resale at market-based prices and open- access transportation of natural gas. In doing that, the Commission seeks to simplify and streamline its requirements to reduce the burden on respondents. Hence, the Commission is eliminating reporting requirements (as well as a few non-reporting requirements) that are outdated or nonessential in light of current regulation, or are duplicative of other reporting requirements. At the same time, the revisions, especially of Form No. 2, will provide financial, rate, and statistical information on transactions that is more useful than what is currently available to regulatory agencies and other users of the financial statements and reports of natural gas companies. The Commission believes the changes to Form No. 2 are needed because the characteristics of certain balance sheet and income statement items for the restructured industry are different from what they were when the current accounting regulations were adopted. In addition, the Commission has significantly increased the thresholds for the reporting of various information. In Part III-A of this rule, the Commission will address the changes to the Uniform System of Accounts with respect to storage gas. In Part III-B the Commission will address other revisions to the Uniform System of Accounts. In Part IV, the Commission will discuss the changes to Part 158 of the Commission's regulations with respect to the certification of compliance with the accounting regulations. In Part V, the Commission will discuss the changes to Part 250 of the Commission's regulations, ``Approved Forms, Natural Gas Act.'' In Part VI, the Commission will discuss the changes to Part 260 of the Commission's regulations, ``Statements and Reports (Schedules).'' That discussion will include the changes to Forms No. 2,9 No. 2-A,10 and Form No. 11.11 In Part VII, the Commission will discuss the changes to Part 284 of the Commission's regulations, ``Certain Sales and Transportation of Natural Gas Under the Natural Gas Policy Act of 1978 and Related Authorities.'' \9\Appendix B consists of the revised Form No. 2. Appendix B is not being published in the Federal Register, but is available from the Commission's Public Reference Room. \10\Appendix C consists of the revised Form No. 2-A. Appendix C is not being published in the Federal Register, but is available from the Commission's Public Reference Room. \11\Appendix D consists of the revised Form No. 11. Appendix D is not being published in the Federal Register, but is available from the Commission's Public Reference Room. --------------------------------------------------------------------------- In the NOPR, the Commission stated that the changes to these regulations and forms and to the regulations in the companion rule titled, ``Filing Requirements for Interstate Natural Gas Company Rate Schedules and Tariffs,'' will necessitate modifications to the electronic formats for the affected filings and forms. The Commission will discuss electronic filings in Part IX below. [[Page 53021]] The changes to the Uniform System of Accounts and Form Nos. 2, 2-A, and 11 in this rule will be effective January 1, 1996.12 The remainder of the rule will be effective 30 days after publication in the Federal Register. \12\That is, the pipelines must comply with the revised Uniform System of Accounts starting January 1, 1996, and they must report 1996 information on the FERC Form Nos. 2 and 2-A filed in 1997. The Form No. 2 filed in 1996 will be the current Form No. 2 and will report for the year 1995. --------------------------------------------------------------------------- II. Public Reporting Burden The subject final rule establishes new reporting requirements, modifies existing reporting requirements, and eliminates those requirements that are now obsolete. In addition, the final rule reflects many of the changes suggested by industry comments filed in response to Commission's Notice of Proposed Rulemaking. This simplification and streamlining of Commission reporting requirements has reduced the burden on pipelines. The collective reduction in reporting burden is estimated to be 61,824 hours annually. The final rule will affect eight of the Commission's existing data collections. It is expected to reduce or eliminate the current reporting burden associated with the following six information collections: FERC Form No. 2 ``Annual Report of Major Natural Gas Companies'' (1902-0028) (FERC-2); FERC Form No. 11, ``Natural Gas Pipeline Company Monthly Statement (1902-0032) (FERC-11); FERC-549, ``Gas Pipeline Rates: Natural Gas Policy Act Title III Transactions'' (1902-0086) (FERC-549); FERC-576, ``Reports on Pipeline Systems Service Interruptions'' (1902-0004) (FERC-576); FERC Form No. 8, ``Underground Gas Storage Report'' (1902-0026) (FERC-8); and FERC Form No. 14, ``Annual Report for Importers and Exporters of Natural Gas'' (1902-0027) (FERC-14) The FERC Form Nos. 8 and 14 will be eliminated entirely as a result of this rule. One of the affected data collections--FERC Form No. 2-A, ``Annual Report of Nonmajor Natural Gas Companies'' (1902-0030) (FERC- 2A)--will have no substantive change in its current reporting burden.13 Only one of the data collections will have a slight increase in burden. The burden associated with FERC-549B, ``Gas Pipeline Rates: Capacity Release Information'' (1902-0169) (FERC-549B) will increase as a result of the institution of the Index of Customers. \13\No net change in the reporting burden is expected because of offsetting increases and decreases within the data collection. --------------------------------------------------------------------------- The aggregate annual reporting burden as a result of the final rule for all affected data collections is estimated to total 437,835 hours based on an expected 981 filings per year. The summary table below shows the impact/reduction on each affected data collection. The Commission's estimates of public reporting burden for the data collections include the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. ---------------------------------------------------------------------------------------------------------------- Estimated Estimated Net change in Estimated No. Estimated Affected data collection (RM95-4- annual burden annual burden annual burden of filings/yr burden hrs per 000) hrs (rule) hrs (current) hrs (rule) filing (rule) ---------------------------------------------------------------------------------------------------------------- FERC-2.......................... 68,310 113,850 -45,540 46 1,485.0 FERC-549........................ 14795 14,045 -13,250 1590 168.8 FERC-549 (B).................... 350,308 349,060 1,248 17546 641.6 FERC-576........................ 12 36 -24 12 1.0 FERC-11......................... 600 3,420 -2,820 200 3.0 FERC-2A......................... 2,610 2,610 0 87 30.0 FERC-818........................ 0 1,296 -1,296 0 0 FERC-1418....................... 0 142 -142 0 0 ------------------------------------------------------------------------------- Total..................... 422,635 484,459 -61,824 981 430.8 ---------------------------------------------------------------------------------------------------------------- \14\Comprised of 750 hours for transportation filings and 45 hours for sales filings. \15\Comprised of 75 transportation filings and 15 sales filings. \16\The weighted average of 10.0 hours per transportation filing and 3.0 hours per sales filing. \17\Includes 468 Index of Customer filings. \18\This data collection is discontinued by the subject rule. With respect to the gas companies filing FERC Form No. 2, the Commission believes that there will be a total reporting burden decrease of 45,540 hours, or approximately 990 hours per respondent each year due to the elimination of about 34 schedules and significant increases in the thresholds for the reporting of information on other schedules. There will be some additional information required, but there should be a minimal burden increase as a result, because much of the information is already collected by the industry in other contexts. The Commission estimates that the existing public reporting burden for the other filing requirements under the rule will also be decreased. With respect to FERC Form No. 11, the quarterly Form No. 11 will contain monthly details of data required annually on an aggregate basis in FERC Form No. 2. The filing of FERC Form No. 11, quarterly rather than monthly, will reduce the number of reports from 600 to 200. In addition, data are primarily required by rate schedule or Uniform System of Accounts entries. These consistencies in reporting will simplify the filing burden. The revised reporting schedule will reduce the existing reporting burden by a total of 2820 hours, or approximately 56 hours per respondent each year. The elimination of initial, subsequent, termination, and annual reports, FERC-549, for interstate pipelines, and the retention of only the annual transportation reports for intrastate pipelines and the annual sales reports for interstate pipelines, will reduce the reporting burden by a total of 13,250 hours. The Commission estimates that the annual report for the 75 remaining intrastate respondents will require an average of 10 hours to complete. The annual sales report for the 15 interstate respondents requires an average of 3 hours to complete. The Index of Customers requirement will add approximately 1,248 hours to the total burden under FERC-549B. In [[Page 53022]] its Notice of Proposed Rulemaking, the Commission estimated that this requirement would add 11,700 hours to the reporting burden for FERC- 549B. However, the Commission has deleted the paper filing requirement, and required that the index be filed electronically with the Commission and be available through a pipeline's electronic bulletin board. It is now estimated that the Index of Customers will take approximately 4 hours for each quarterly update for the 78 pipeline respondents. Allowing reporting of service interruptions in FERC-576 by any electronic means, including facsimile or telegraph, will expedite the notice process, and reduce the burden to one hour per response from three hours. This report is required only in the event of an interruption to normal service lasting three hours or longer. The elimination of the FERC Form Nos. 8 and 14 will reduce industry reporting burden by 1,296 and 142 hours, respectively. A copy of this rule is being provided to OMB. Interested persons may send comments regarding these burden estimates, or any other aspect of these collections of information, including suggestions for further reductions of burden, to the Federal Energy Regulatory Commission, Washington, D.C. 20426 [Attention: Michael Miller, Information Services Division, (202) 208-1415, FAX: (202) 208-2425]. Comments on the requirements of this final rule may also be sent to the Office of Information and Regulatory Affairs of OMB, Washington, D.C. 20503 [Attention: Desk Officer for Federal Energy Regulatory Commission, (202) 395-3087, FAX: (202) 395-5167]. III. Revisions to Uniform System of Accounts (Part 201) A. Storage Accounting 1. The NOPR In the NOPR, the Commission proposed to require that the maximum designated gas volumes maintained for system balancing purposes,19 including those needed for no-notice transportation service, and recoverable base gas volumes be accounted for as a fixed asset rather than as inventory held for sale, which is the current practice.20 Collectively these volumes are referred to as ``system gas''. \19\System balancing, as used here, refers to those situations where the pipeline provides gas from its own source of supply in order to meet deficiencies caused by a shipper tendering less volumes to the pipeline at the receipt point than it takes from the system at the delivery point. The term can also be used to refer to situations where the shipper tenders more volumes than it takes from the system. \20\The Commission is not changing the accounting requirements for initial line pack, LNG heel, and non-recoverable base gas. The cost of this gas will continue to be recorded in the utility plant accounts. --------------------------------------------------------------------------- Under the fixed asset model, system gas would be accounted for as a noncurrent asset or permanent investment. In contrast, under the inventory model, system gas would be accounted for as inventory. The two models differ in how the pipeline's investment in gas is valued and in how gains and losses on balancing transactions are measured and recognized.21 \21\See the NOPR at pps. 32,999-33,001 for a full discussion of the differences between the fixed asset and inventory models. --------------------------------------------------------------------------- To implement the fixed asset accounting model for system gas, the NOPR proposed that Account 117, Gas Stored Underground--Noncurrent, be replaced by new accounts Account 117.1, Gas Stored--Base Gas, Account 117.2, System Balancing Gas, Account 117.3, Gas Stored in Reservoirs and Pipelines--Noncurrent, and Account 117.4, Gas Owed to System Gas. 2. Comments on Mandating the Fixed Asset Model The fixed asset approach is supported in whole or in part by Columbia, ANR, Enron, Tennessee, Texas Gas, KN, NGSA, and NI-Gas. It is opposed by Panhandle, Transco, and AGD. INGAA and other commenters22 maintain that the pipelines should be able to choose either the fixed asset or inventory model. INGAA submits that this flexibility is justified for two reasons. First, it argues that adoption of the fixed asset model will not ensure uniformity in accounting for storage because that model is not uniform among non-pipeline storage owners and operators, such as independent storage operators and local distribution companies. Second, INGAA contends that flexibility would prevent a number of distortions which will arise from pipelines converting from the inventory method to the fixed asset model. Third, INGAA asserts that the change from the inventory to the fixed asset model could increase state ad valorem taxes and could be considered a change in accounting by the IRS, causing it to rescind permission to use the LIFO inventory method for income tax purposes. \22\ANR, Kern River, Transco, Enron, Tennessee, KN, Williston, and Consumers Power. --------------------------------------------------------------------------- 3. The Treatment of System Gas As stated above, there is support for both the fixed asset model and the inventory model as the appropriate approach for accounting for investments in system gas. Upon review of the comments, the Commission concludes that valid arguments can be made in support of either approach. Accordingly, the Commission will permit pipelines to adopt either the fixed asset model or the inventory model to account for system gas.23 \23\The Commission is not setting forth the arguments for and against the models in light of the decision not to mandate a particular model. --------------------------------------------------------------------------- Each pipeline must inform the Commission of the method it adopts for accounting for system gaswhen it files its Form No. 2 in 1997. The method adopted by each pipeline must be used consistently from year to year and appropriate records must be maintained. The pipeline must obtain Commission approval for any change in method. The Commission will not permit a pipeline to adopt one method for determining its rates and another method for accounting purposes. For example, if a pipeline elects the fixed asset model for accounting purposes, it must derive its rates via that model in its first full rate proceeding subsequent to its accounting decision. Similarly, if a pipeline uses the fixed asset model in developing its rates, it must use the same method for accounting purposes. 4. The Rule a. Investment in System Gas. To implement this rule, the Commission is revising its accounting regulations to allow pipelines two alternative methods of accounting for all pipeline investment in system gas. Under those regulations, pipelines may continue to account for their gas using a consistently applied inventory method, or pipelines may adopt the ``fixed asset'' method. As noted above, the Commission is not changing the accounting requirements for initial line pack, LNG heel, and non-recoverable base gas. The cost of this gas will continue to be recorded in the utility plant accounts. The Commission is replacing Account 117, Gas Stored Underground-Noncurrent with four new accounts: Account 117.1, Gas Stored--Base Gas, Account 117.2, System Balancing Gas, Account 117.3, Gas Stored in Reservoirs and Pipelines- Noncurrent, and Account 117.4, Gas Owed to System Gas. Account 117.1 will include the cost of recoverable gas volumes that are necessary to maintain pressure and deliverability requirements for the storage facility. Nonrecoverable gas volumes used for this purpose will continue to be recorded in Account 352.3, Nonrecoverable Natural Gas. [[Page 53023]] Account 117.2 will be used to record a pipeline's investment in any additional system gas volumes, including gas stored in pipelines above initial line pack, designated as maximum system gas needed for load balancing, no notice transportation, and other operational purposes. Account 117.3 will be used to record the cost of noncurrent company- owned stored gas not includable in Accounts 117.1 or 117.2. Account 117.4 will primarily be used by pipelines that account for system gas using the fixed asset model. Account 117.4 will reflect encroachments upon system gas that result from transportation imbalances, no-notice transportation, and other operational needs. It may also be used to reflect encroachments on volumes recorded in Account 117.1 for pipelines using an inventory method. The initial investment cost to be recorded in Account 117.1 and 117.2 is to be determined from the book balances in Account 117 on the date of adoption of the new accounts. If there is no Commission approved method to the contrary, volumes in Account 117.1 and Account 117.2 are to be priced at their historical cost consistent with the inventory method previously in use.24 If at the date of adoption, a pipeline's volumes in storage are less than the maximum volume authorized by the Commission for operational purposes, the deficient volumes are to be priced at the then current market price25 with an equal amount being credited to Account 117.4. \24\The cost of any volumes of base or system gas actually in storage that has previously been charged to expense should be carried in the accounts at zero cost. \25\Current market price is the delivered spot price of gas as published in a recognized industry journal. The publication used must be the same one identified in the pipeline's tariff for use in its cash-out provision, if it has one. If the pipeline does not have a cash-out provision, the pipeline must use a publication representative of the cost of gas in its supply area, use the same publication consistently, and identify the publication in its records. --------------------------------------------------------------------------- b. Use of System Gas. (1) Fixed Asset Method. Under the fixed asset method the Commission is adopting in this rule, future encroachments upon system gas are to be credited to Account 117.4 at the then current market price of gas with a corresponding charge to Account 808.1, Gas Withdrawn From Storage- Debit. If the volumes are used to meet transportation imbalances, Account 806, Exchange Gas, will be credited and Account 174, Miscellaneous Current and Accrued Assets, will be debited for the same amount and simultaneously with the entries to system gas. Pipelines will be required to maintain records supporting Account 117.4 of monthly encroachment volumes and unit prices unless the pipeline revalues its total encroachment balance monthly. If a pipeline revalues the balance in Account 117.4, it should charge or credit a separate subaccount of Account 813, Other Gas Supply Expenses, with the amount of the revaluation. To the extent that there are corresponding changes in the value of imbalance receivables or payables, the pipeline should make an appropriate adjustment to Account 174, Miscellaneous Current and Accrued Assets or Account 242, Miscellaneous Current and Accrued Liabilities, with contra-entries to Account 813. If a customer responsible for an owed-to-system gas balance meets his responsibility for repayment by delivering gas in-kind, the recorded balance for such customer in Account 174 will be reversed and Account 806 will be debited. The amount recorded in Account 117.4 for such volumes must be cleared and Account 808.2, Gas Delivered to Storage--Credit, credited. If the customer responsible for an owed-to-system gas balance meets his responsibility through a cash-out provision, similar accounting will be followed. To recognize settlement of the receivable, the pipeline will reverse the recorded amount in Account 174. Any difference between the cash-out settlement amount and the recorded receivable will be recognized as a gain in Account 495 or a loss in Account 813, as appropriate. When the pipeline replaces the gas, any difference between the cost of the gas and the amount cleared from Account 117.4 will result in a gain or loss. The pipeline should record the gain or loss in Account 495, Other Gas Revenues, or Account 813 as appropriate with contra entries to Account 808.2. In instances in which a pipeline's tariff requires that gains and losses on system balancing transactions are to be passed along to customers, pipelines should record the gains or losses directly in Account 254, Other Regulatory Liabilities, or Account 182.3, Other Regulatory Assets, as appropriate. (2) Inventory Method. Under the inventory method, withdrawals of system gas are to be credited to Account 117.2, at the inventory cost of gas\26\ with a corresponding charge to Account 808.1, Gas Withdrawn From Storage-Debit. If the volumes are used to meet transportation imbalances, Account 806, Exchange Gas, will be credited and Account 174, Miscellaneous Current and Accrued Assets, will be debited for the same amount and simultaneously with the entries to system gas. \26\Withdrawals of gas may be priced according to the first-in- first-out, last-in-first-out, or weighted average cost method, in connection with which ``the fixed asset method'' may be employed provided the method adopted by the utility is used consistently from year to year and the inventory records are maintained in accordance therewith. --------------------------------------------------------------------------- The pipeline must also account for withdrawals of gas from Account 117.1 under the inventory method. However, if encroachments upon Account 117.1 volumes are to be replaced within 12 months, the pipeline may, at its option, account for such withdrawals in accordance with the requirements for encroachments of system gas under the fixed asset method. The method chosen should be applied consistently from year to year and not changed without express approval of the Commission. 5. Fixed Asset Accounting Implementation Issues A number of commenters requested clarification of certain aspects of the proposed fixed asset model and noted various implementation difficulties with the Commission's approach. The following discussion is the Commission's response to the concerns expressed by commenters. As stated above, the Commission is replacing Account 117, Gas Stored Underground-Noncurrent, with four new accounts: Account 117.1, Gas Stored-Base Gas and Account 117.2, System Balancing Gas, 117.3, Gas Stored in Reservoirs and Pipelines--Noncurrent, and 117.4, Gas Owed to System Gas. The Comments address those accounts. a. Accounts 117.1 and 117.2. Williston asks for clarification that gas previously capitalized in Account 101 [utility plant] is not to be reclassified as Account 117.1 gas. The Commission clarifies that the cost of gas volumes properly includable in Account 101 is not to be reclassified to Account 117.1. The rule is making no change to the requirements of the existing Uniform System of Accounts that the cost of non-recoverable gas in underground reservoirs used for the storage of gas, and the first cost of gas introduced into the utility's system necessary to bring the pipeline system up to its designed operating capacity or increases therein, are to be included in the plant accounts. Enron maintains that Accounts 117.1 and 117.2 should be combined into a single account titled ``System Gas,'' because there is no clear line between volumes serving a pressure maintenance function and volumes used for system balancing. [[Page 53024]] The Commission will not adopt Enron's suggestion. The Commission recognizes that a bright line separating the volumes necessary for maintaining storage pressure and deliverability requirements from those necessary for efficient transmission operation (i.e. system balancing gas) does not exist for most if not all storage facilities. However, base gas volumes in storage reservoirs are used to maintain pressure and deliverability requirements for both customer storage and pipeline storage of system gas. Because storage rates are often separate from transmission only rates, it is necessary to separately identify the cost of base gas so that proper allocations of base storage costs can be made between storage and transmission services. Commingling base storage with system balancing gas would make cost and rate determinations more difficult. CNG urges the Commission to delete the requirement to report line pack in Account 117.2 because CNG includes line pack in plant accounts or has expensed it already and its line pack fluctuations are immaterial from month to month. The final rule does not require the cost of line pack gas previously charged to expense to be included in Account 117.2. However, pipelines must account for volumes stored in the pipeline above line pack volumes consistent with the rule. That is, the cost of such additional volumes must be recorded in Account 117.2 or 117.3, as appropriate. If the pipeline has previously charged the cost of any such additional volumes on its system to expense such volumes must be included in the accounts at zero cost. NGSA would create a number of new accounts to deal with system gas. NGSA states that although both Accounts 117 and 164.1, Gas Stored Underground--Current, should be maintained as fixed assets, Account 164 also should be used for system balancing transactions because it is NGSA's belief that working gas, not base gas, is cycled. It would amend the accounts instructions to require pipelines to record both volumes and dollars and would establish specific subaccounts in Account 164, rather than Account 117, to match the pipeline's accounting of imbalances by service type and rate schedule (e.g., no-notice, exchange, gathering, FT and IT). Gas Owed to System Gas would be reflected in Account 174.4 and a separate asset account would be established for line pack. The Commission will not adopt NGSA's proposal because the Commission believes it is unnecessary to establish a separate account for line pack or to prescribe numerous subaccounts of storage gas by service type and rate schedule. The proposed new Accounts 117.1 through 117.4 should be adequate for accounting for all system gas. In this regard, the Commission will modify instruction A of the proposed Account 117.3 to include the cost of all stored gas in excess of system, whether or not it is available for sale. Although the Commission declines to require specific subaccounts for system gas, pipelines may establish whatever subaccounts they deem necessary to facilitate the needs of their individual pipelines. Panhandle interprets the NOPR's proposal to price volumes includible in Account 117.2 ``at the inventory price that would be applicable to the last volumes that would be withdrawn from storage before encroachment upon base gas'' (NOPR at p. 33,002), as requiring restatement of all system gas that had previously been accounted for using a LIFO or FIFO inventory method. Panhandle maintains this is improper. Panhandle's interpretation is incorrect. The proposed rule was not intended to require or permit pipelines to restate the carrying value of system gas in storage upon implementation of the new accounting. The proposed rule clearly states that the initial investment cost to be recorded in Accounts 117.1 and 117.2 is to be determined from the book balances on the date of adoption of the new accounts. The statement cited by Panhandle was intended to address potential situations where the initial volumes of gas in storage exceeded the volumes designated as system gas. In these situations, the cost to be assigned to Account 117.2 should be determined based on historical inventory price layers starting with the pricing layer applicable to the last volumes that would be withdrawn from storage before encroachment upon base gas and continuing until all of the volumes of system gas have been priced. b. Account 117.4. (1) Nature of the Account. The Commission proposed Account 117.4 as an account that would reflect the obligation to replace volumes that encroached on system supply. Panhandle contends that the Commission has not explained whether Account 117.4 is designed as a liability or a valuation account and that, in any event, the proposed approach is not in accordance with Generally Accepted Accounting Principles (GAAP). It asserts that there is no liability on the pipeline's part to restore system gas. It then argues that, like a valuation account, Account 117.4 reduces the carrying value of the system gas asset, but it ``reduces system gas to a value that is neither cost-based nor market-based, but a varying hybrid which does not qualify as an asset account.''\27\ \27\Comments at 16. --------------------------------------------------------------------------- Williston maintains that the characteristics of Account 117.4 gas (encroachments) ``do not satisfy the characteristics of a fixed asset for Balance Sheet presentation.''\28\ Similarly, Enron submits that the gas owed to system gas account is a temporary valuation adjustment to the system gas accounts and should not be a part of the fixed asset accounts. Enron further maintains that ``working capital would be misstated if the gas owed to system gas account is a fixed asset account, with the companion imbalance recorded as a receivable.''\29\ It suggests that ``gas owed to system gas should be established as a current asset/liability account rather than a fixed asset account.''\30\ Texas Gas also argues that encroachments should be presented in a current asset/liability account to avoid large non-cash fluctuations in fixed assets and working capital. It submits this would be in accordance with gas receivables/payables recorded in Accounts 174/242 as proposed in the NOPR. \28\Comments at 4. \29\Comments at 4. \30\Id. --------------------------------------------------------------------------- Enron and Texas Gas believe that Account 117.4 is a temporary valuation account that is more in the nature of a current asset. Treating it as a fixed asset will misstate working capital because the companion imbalance would be recorded as a receivable. Account 117.4 has characteristics of both a liability account and a valuation account. A pipeline has a constructive requirement to replace encroachments of system gas if it is to remain in the business as a transporter. Accordingly, the amounts that are to be recorded in Account 117.4 represent, in significant respects, probable future sacrifices of economic resources resulting from past transactions (the encroachments). Thus, the amounts seem to generally fit the conceptual definition of a liability. Yet, as Panhandle points out, the pipeline does not have a legal obligation to one or more entities to purchase replacement gas and therefore the amounts would not constitute a recognizable liability under generally accepted accounting principles. The amount to be recorded in Account 117.4 is an estimate of the cost to be incurred by the pipeline to replace the encroachments to system gas that have occurred. As such, the Commission believes Account 117.4 is more in the nature of a valuation [[Page 53025]] account than a liability. Although different from the example cited in Concepts Statement No. 6, the owed to system gas account is consistent with the following more general discussion of ``valuation accounts'' contained in the Statement:\31\ \31\See paragraph 34 of FASB Statement of Financial Accounting Concepts No. 6, ``Elements of Financial Statements'', FASB Original Pronouncements, Vol. II (1995). --------------------------------------------------------------------------- A separate item that reduces or increases the carrying amount of an asset sometimes found in financial statements. Those ``valuation'' accounts are part of the related assets and are neither assets in their own right nor liabilities. Since the Commission views Account 117.4 to be more in the nature of a valuation account, it has decided to retain its classification within the Account 117 grouping of accounts. This is consistent with the usual financial statement display of valuation accounts as reductions of the accounts to which they relate. As the Commission stated in the NOPR, however, the amounts recorded in account 117.4 and the companion imbalance receivable and payable accounts can be taken into consideration in determining cash working capital requirements. (2) Valuation/Pricing. In the NOPR the Commission proposed that encroachments on system gas would be valued at the current market price. When a customer responsible for an owed-to-system gas balance met his responsibility for repayment by delivering gas in kind, the NOPR proposed that Account 117.4 be cleared at the same price originally used to record the encroachment. If the balance in Account 117.4 was due to more than one transaction, the NOPR proposed that the accounting would follow a queue with the earliest transaction first, until the credit balance in Account 117.4 was eliminated. El Paso objects to the ``aging of imbalances by contract and month and the tracking of all shipper over/under performance in and out of storage accounts using a queue.''\32\ It does so because ``[w]hile there in fact may be some relationship between changes in storage and changes in imbalances, the two events cannot be tied together on a shipper by shipper, contract by contract basis.''\33\ It adds that such reporting ``would serve no purpose and would lead to arbitrary results.''\34\ It recommends, as an alternative, that ``[c]hanges in storage should be treated in the aggregate and not tied to any individual shipper or contracts.''\35\ \32\Comments at 5. \33\Id. \34\Id. \35\Id. --------------------------------------------------------------------------- Columbia concurs with valuing Account 117.4 gas at the current market price. Texas Gas recommends that the pipelines have discretion to determine the value of encroachment gas. It further maintains that ``accounting for storage activity on a transaction-by-transaction basis by following `a queue' would be impractical and an administrative burden which would, in Texas Gas's situation, be of no value, as all system activity is tracked and Texas Gas incurs no gains/losses resulting from pricing differentials.'' It also submits that ``obligations to repay gas in-kind to or from a pipeline should be presented in the financial statements at an established value at a point in time (i.e., the date of the balance sheet) not at the current market price in effect on the date each transaction took place.''\36\ It asserts that ``since the obligation is to replace the gas in-kind, the `market price' on the date it was borrowed is irrelevant.''\37\ \36\Id. \37\Comments at 4. --------------------------------------------------------------------------- Kern River opposes valuing imbalance quantities at current market prices. It submits that for it such a current market valuation of Account 117.4 gas is unnecessary and unduly burdensome. It states that it never, since its initial line pack purchases, bought gas for fuel, imbalances, or to replenish line pack. Hence, it asserts that it is justified in recording all imbalances at its historical average unit cost of line pack. Panhandle maintains that the layered pricing as proposed in the NOPR would be burdensome by increasing the annual recorded transactions of its pipeline group from 48 to approximately 17,300. Panhandle also claims that it will have to create and maintain two sets of calculations to the extent gains/losses are calculated differently from the relevant tariff method. And it claims a significant burden increase of from 8,010 hours to 16,050 hours due to the procedures in the proposed rule. Columbia, Enron, and Tennessee urge the Commission to simplify the accounting and recordkeeping requirements by allowing pipelines to net all transactions and record one monthly entry with one month-end price for valuation purposes, as well as monthly repricing of the cumulative net imbalances. After considering the comments, the Commission has decided not to adopt suggestions that would allow alternatives for valuing encroachments under the fixed asset model. Instead, the Commission will require all pipelines to value encroachments at current market price as originally proposed. For purposes of valuing the encroachments, current market price means the delivered spot price of gas as published in a recognized industry journal. The publication used must be the same one identified in the pipeline's tariff for use in its cash-out provision, if it has one. If the pipeline does not have a cash-out provision, the pipeline must use a publication representative of the cost of gas in its supply area, use the same publication consistently, and identify the publication in its records. The Commission recognizes that for in-kind transactions pipelines do not separately purchase replacement gas and therefore do not recognize a gain or loss on the use and replacement of system gas. However, the accounting event to be recognized is the encroachment, and the prospect of obtaining replacement gas in kind from a customer should not produce a measurement different from what would be obtained in a cash transaction. Upon consideration of the comments, the Commission will simplify the proposed recordkeeping for encroachments and replacements of system gas under the fixed asset method. The NOPR proposed that different price layers be maintained for monthly encroachments on system gas and that replacements of system gas be priced following a queue. The Commission now believes that this approach is unnecessarily complex. Instead, the Commission will adopt the suggestions of INGAA and others to allow pipelines to revalue cumulative net imbalances, net all transactions and record one monthly entry with one month-end price for valuation purposes. The Commission believes that this modification will reduce the recordkeeping burden associated with the fixed asset model without materially affecting the validity or reliability of the accounting measurements. (3) Losses on Settlement of Imbalances. CNG submits that the Commission's proposal to revise Account 813, Other Gas Supply Expenses, so that it will include losses on settlements of imbalance receivables would have an adverse impact on its record keeping. It states that in order to calculate gains and/or losses on imbalance settlements, historical imbalance data, including gas prices, would need to be tracked. There will be no need to track gas prices or use historical imbalance data for calculating gain or loss. The Commission's simplification of the recordkeeping requirements for storage [[Page 53026]] imbalances under the fixed asset method should substantially mitigate CNG's concern over the record keeping requirements necessary to calculate gains or losses of imbalances. For imbalances in which the pipeline has delivered more than the shipper injected at the receipt point, gains (or losses) will be the difference between the cash-out price and the pipeline's purchase cost of replacement gas volumes. For cashed-out imbalances in which the pipeline has delivered less than the shipper has tendered into the pipeline, the gain (or loss) will be the difference between the cash-out price paid by the pipeline and the current price of volumes recorded in Account 117.4. For system gas accounted for under the inventory method, gain or loss will be the difference between the cash-out price and the inventory price of the gas imbalance. (4) Storage Losses. The NOPR did not explicitly address the accounting for storage losses. CNG maintains that Account 117.4 needs to be revised to address encroachments due to storage losses and suggests specific instructions for losses. The Commission agrees that the Uniform System of Accounts should contain explicit instructions for gas losses. The Commission has therefore added instructions to require: (1) losses of gas stored in underground reservoirs be charged to Account 823, Gas Losses. The Commission did not adopt CNG's specific language changes related to storage losses. However, the Commission agrees that under the fixed asset model, losses of system gas should be priced at the same rate used to price withdrawals in the month in which the loss is recognized (i.e. the current market price of gas available to the utility). Storage losses under the inventory model will continue to be priced at inventory cost. (5) Other Item. Columbia requests clarification of the requirements for Account 117.4, Gas Owed to System Gas. Columbia apparently seeks confirmation that Account 117.4 is to be used to record imbalances only after Columbia has exhausted other options for resolving imbalances. In other words, the pipeline could use customer-owned storage quantities to the extent permitted by its tariff prior to using its own gas. This recognizes that the gas borrowed from storage to meet imbalances belongs to the storage customers. Columbia is permitted to borrow the gas from storage because of an arrangement between Columbia and its customers that, consistent with Columbia's tariff, allows Columbia to use its customer's gas for balancing purposes. Thus, Columbia and any other similarly situated pipeline would record amounts in Account 117.4 only after customer gas available to the utility for system balancing purposes has been exhausted. This accounting is appropriate because the pipeline is using its customers' gas to meet imbalances on its transportation system. If however, it is necessary for the pipeline to use its own gas for system balancing purposes and if such use results in an encroachment upon the system gas volumes amounts would be required to be entered in Account 117.4 under the fixed asset model. Under the inventory model, use of the pipeline's gas for balancing would require entries directly to the system gas accounts. d. EBB reporting. AGD maintains that the estimated volumes in Accounts 117.1 through 117.4 and particularly 117.4 should be calculated by the pipeline and provided to shippers daily through the EBB. The Commission concludes that no purpose is served by posting this information in the EBB. In addition, the maintenance of this data would be burdensome by being time-consuming and labor intensive. Hence, the Commission is not requiring posting of this data on the EBB. B. Shipper Supplied Gas 1. The NOPR In the NOPR, the Commission addressed the issue of the appropriate accounting treatment of gas furnished to the pipelines by their shippers for compressor fuel and other pipeline system use.\38\ The Commission concluded that the pipelines must include the value of that gas in their reported revenues and in their reported expenses. \38\For example, gas furnished by shippers to cover line losses incurred as part of the transportation service. --------------------------------------------------------------------------- The Commission also invited comments from the industry about whether a price index should be used to account for the value of gas furnished by customers; and, if so, asked what would be the appropriate price index, and how that price should be applied. The Commission concluded that no changes were needed to the USofA to effect its proposal. However, the Commission stated that the records supporting the purchased gas accounts for retained gas must be so maintained that there will be readily available for each shipper and point of receipt, the quantity of gas tendered, and the values assigned. 2. Comments on Accounting Treatment INGAA suggests that the Commission not mandate the procedure for accounting and valuation of customer-provided compressor fuel as revenue because the Commission's proposal contradicts a majority of the pipelines' tariff provisions and mechanisms. ANR also maintains that each company should be able to use its current method. Columbia and AGD support the NOPR's proposal. However, Panhandle, ANR, MRT, Great Lakes, Williams, Transco, Enron, Texas Gas, National Fuel, and Kern River oppose the NOPR's proposal. 3. The Rule Upon consideration of the comments, the Commission concludes that it is not appropriate to mandate revenue recognition for gas provided by shippers for compressor fuel and other pipeline system use and used to provide transportation services.\39\ Instead, each pipeline will have the discretion to determine whether it will recognize revenue for these transactions in its accounting records. \39\The Commission is not setting forth the arguments of the commenters in light of the decision not to mandate a particular approach. --------------------------------------------------------------------------- The Commission is taking this approach because of the apparent divergence between relevant accounting standards. In one view, as in the NOPR, these volumes represent an inflow of assets to the pipeline from delivery or producing goods, rendering services or other activities that constitute the pipeline's ongoing major or central operations. Recognition of an economic value for these volumes therefore meets the conceptual definition of revenues set forth in Statement of Financial Accounting Concepts No. 6, paragraph 78.\40\ Therefore, it is conceptually appropriate to recognize gas received from shippers in exchange for transportation services as revenue. However, based on the filed comments, it is less than clear that current accounting standards for enterprises in general require such recognition. Hence, to avoid potential differences between pipeline financial statements filed with the Commission and financial statements issued to the public, the Commission will not mandate that [[Page 53027]] pipelines recognize shipper provided gas as revenue. \40\Contrary to Panhandle's assertion, the fact that most of the gas may be used in pipeline operations simultaneously upon its receipt does not mean that it is not an asset. It means only that it is an asset momentarily--as the pipeline receives and uses it. See SFAC No. 6 paragraph 31 for a discussion of this phenomenon. --------------------------------------------------------------------------- 4. Entries--Revenue Recognition Pipelines electing to recognize shipper provided gas as revenue must also recognize an equal amount of purchased gas expense. Pipelines would credit the appropriate transportation revenue account (Accounts 489.1 through 489.4)\41\ and record an equal amount in Account 805, Other Gas Purchases. \41\New revenue accounts 489.1, Revenues from Transportation of Gas of Others Through Gathering Facilities, 489.2, Revenues from Transportation of Gas of Others Through Transmission Facilities, 489.3, Transportation of Gas of Others Through Distribution Facilities, and 489.4, Revenues from Storing Gas of Others. --------------------------------------------------------------------------- 5. Entries--Non Revenue Recognition Although the Commission is not requiring revenue recognition for the volumes received from shippers, pipelines must recognize all gas consumed in compressor stations or used for other operational purposes in the appropriate expense accounts in accordance with existing Uniform System of Accounts requirements.\42\ Contra-credits for these amounts are to be recorded in Account 810, Gas Used for Compressor Station Fuel--Credit, Account 811, Gas Used for Products Extraction--Credit, and Account 812, Gas Used for Other Utility Operations--Credit, as appropriate. This will result in comparability of transmission operating expenses among pipelines and will avoid the statistical anomalies that exist under current practices.\43\ Further, the value of gas received from shippers under tariff allowances that is not consumed in operations nor returnable to customers through rate tracking mechanisms shall be credited to Account 495, Other Gas Revenues and charged to Account 805. Pipelines must simultaneously charge Accounts 117.3 or 117.4 as appropriate, with contra credits to Account 808.2, Gas Delivered to Storage--Credit. \42\For example, the cost of gas used for transmission compressor stations is to be recorded in Account 854, Gas for Compressor Station Fuel, and gas used for underground storage compressor stations is to be recorded in Account 819, Compressor Station Fuel and Power. \43\For example, in 1994 Panhandle and Columbia moved 1.2 billion mcf and 1.3 billion mcf of gas respectively on their systems. While the volumes moved were approximately the same, the two pipelines reported widely disparate amounts for the cost of gas used in transmission compressor stations--$2.7 million for Panhandle and $28.7 million for Columbia. While the two pipeline systems are obviously different and therefore fuel usage can not be expected to necessarily correlate precisely with throughput, the figures adequately demonstrate the statistical anomalies and lack of comparability that results from different accounting and reporting practices. --------------------------------------------------------------------------- 6. Pricing Since all pipelines must recognize the cost of shipper-supplied gas, it is necessary to determine the appropriate measure of such cost. In the NOPR the Commission stated that an appropriate measure of the revenues and cost of gas furnished by a customer for compressor fuel should be the cost that would have been incurred had the pipeline been required to purchase the gas itself. The Commission invited comments from the industry about whether a price index should be used, and if so, what would be the appropriate price index and how should it be applied. INGAA maintains that there should not be a mandatory index for all pipelines, because of their different operations, locations, and contractual arrangements. Panhandle supports an index that is reasonable for each pipeline and is applicable to all points on the pipeline. It argues that indices for different points would complicate the calculations and increase burden. National Fuel submits that a pipeline should be able to use the index described in its tariff or an average if it uses different indices for cash-out purchases and sales. CNG maintains that the ``Appalachian CNG Spot'' price as quoted in Natural Gas Intelligence is the best representation of the price of gas received onto its system. It submits that this price should be used for CNG and similarly situated pipelines in valuing fuel retained, gas used in company operations, storage encroachment, and transport and exchange imbalances. Transco suggests that an industry-wide price index not be used. It proposes to use the same spot prices that it uses for its fuel tracker. Columbia supports use of an index specific and applicable to the pipeline's primary supply area to value the fuel usage and retainage quantities supplied by customers. Enron maintains that in calculating the expense reimbursement, pipelines should use existing tariff indices. ANR stated that it was unreasonable to apply an arbitrary price to shipper supplied gas. Great Lakes stated that pipelines do not know the price shippers paid for the gas, and that indices do not necessarily reflect prices paid under different contracts. MRT and National Fuel opposed the assignment of arbitrary values to gas received for compressor fuel. INGAA stated that there should not be a mandatory index for all volumes as no one price index can reflect every pipeline's operations, geographic location or contractual arrangements. Pipelines recognizing revenue and purchased gas expense for shipper provided gas should value such amounts at current market value. Values to be assigned to fuel consumed in compressor stations or used for other operational purposes should be similarly determined. The Commission agrees with commenters that use of a single index applied to all pipelines would not adequately recognize differences in gas prices between geographical regions. Instead, the Commission believes that the current market value must be determined by reference to the delivered spot price of gas as published in a recognized industry journal. The publication used must be the same one identified in the pipeline's tariff for use in its cash-out provision, if it has one. If the pipeline does not have a cash-out provision, the pipeline must use a publication representative of the cost of gas in its primary supply area, use the same publication consistently, and identify the publication in its records. Use of such values would allay any concerns as to whether the values recorded by a company on its books relate to the operations of that company. 7. Recordkeeping Although the Commission did not propose any changes to the Uniform System of Accounts to account for shipper supplied gas, the Commission made it clear that the purchased gas accounts for retained gas must be so maintained that there will be readily available for each shipper and point of receipt, the quantity of gas tendered and the values assigned. INGAA maintains that receipt point allocation of fuel to specific shippers will result in a significant increase in burden because pipelines do not track compressor fuel in that fashion. It states that many pipelines' tariffs state that fuel needs are calculated and collected on a zone or service basis. Great Lakes opposes the accounting for compressor fuel by shipper by receipt point when many pipelines operate under a mechanism where fuel is allocated by zones or service categories. It submits that such a calculation would involve burdensome assumptions and allocations, serve no useful purpose, and would be inconsistent with tariffs. KN maintains that the supporting information requirement will result in a significant administrative burden. It refers to its numerous receipt and delivery points within a contract for several shippers. ANR submits that the [[Page 53028]] calculation of fuel by shipper and receipt point would involve a number of assumptions and allocations that would be arbitrary, inaccurate, and burdensome and, therefore, would not serve any valid statistical basis. This is so, it says, because many pipelines calculate fuel by zone or service category. AGD requests that pipelines record both actual fuel consumed and fuel retained or paid for, on a rate schedule and rate zone basis. The Commission concludes that it would be unduly burdensome for pipelines to maintain supporting information by receipt and delivery points within a contract for each shippers. Therefore, the Commission will revise the recordkeeping to require records to be maintained and readily available for shipper supplied gas on a rate schedule and zone basis. 8. Accounts--Revenue--Expense Account In the NOPR the Commission stated that the expense account to be charged with the gas provided by shippers is the same purchased gas account that would have been charged if the gas was separately purchased in a cash transaction. INGAA states that the choice of purchased gas account may become unnecessarily complex if the proposal is adopted, because the appropriate account will apparently be determined by the location of the receipt point for the compressor fuel. INGAA next asserts that if the Commission determines that pipelines must separately account for volumes received for fuel, it must establish appropriate accounts as a credit to expense. Columbia recommends the use of one gas purchase account and one market rate rather than the multiple gas purchase Accounts 800 through 805. It would delete Accounts 800 through 804. Based on the comments, the Commission concludes it would be an undue burden to require pipelines to classify these amounts according to the receipt point of the gas. Therefore, we are adopting Columbia's recommendation to permit the use of Account 805, Other Gas Purchases, to record such amounts. C. Revenues At present, a pipeline includes in Account 489, Revenues from Transportation of Gas of Others, ``revenues from transporting gas for other companies through the production, transmission, and distribution lines, or compressor stations of the utility.'' Service charges for the storage of gas of others are included in Account 495, Other Gas Revenues. (See Item No. 5 of Account 495). The Commission is deleting Account 489 in its entirety and Item No. 5 of Account 495 and replacing it with four new accounts. These are: Account 489.1, in which the pipeline would include revenues from transportation of gas through gathering facilities; Account 489.2, in which the pipeline would include revenues from transportation of gas through transmission facilities; Account 489.3, in which the pipeline would include revenues from transportation of gas through distribution facilities; and Account 489.4, in which the pipeline would include revenues from storing gas of others. In addition, the Commission is adding two new items to the list of items in Account 495 to (1) address recognition of gains on settlements of imbalances and (2) provide for the recording of penalty revenues. The above changes are supported in whole or in part by INGAA, KN, Columbia, Panhandle, NGSA, and AGD. The Commission is adopting the above changes in order to appropriately record revenues from unbundled services. The Commission will address below specific concerns of some commenters and requests for clarification. 1. Accounts Panhandle suggests that the Commission create a new Account 489.5 to cover other operating revenues. The Commission believes that there is no need to establish a fifth account in which to record other revenues since current Account 495, Other Gas Revenues, already adequately provides for revenues not includible in other gas revenue accounts. In this regard, the Commission is adding Item 9 to the list of items included in Account 495 to explicitly provide for the recording of penalties earned pursuant to tariff provisions, including cash-out penalties. This change codifies existing practice in the industry. NGSA recommends that Account 495 be broken into subaccounts that represent the list of items proposed by the NOPR, including subdividing proposed new item 8, ``Gains on Imbalance Settlements,'' into five subaccounts, ``495.81 No-Notice,'' ``495.82, Exchange,'' ``495.83, Gathering'', ``495.84, Transportation,'' and ``495.85, Other (specify).'' AGD requests that the Commission direct the companies to keep separate sub-accounts in Account 495 for shipper imbalances, so that these amounts can be properly scrutinized in rate cases. The Commission will not adopt NGSA's or AGD's recommendations. This level of subaccount detail is unduly burdensome.44 However the Commission will require pipelines to maintain a separate subaccount within Account 495 for gains from settlement of imbalances. The Commission's decision not to require additional subaccounts does not relieve the pipeline of its burden to keep its books and records so as to be able to furnish readily full information for any item included in any account.45 \44\Similarly the Commission concludes it would be unduly burdensome to require pipelines to establish separate subaccounts for administrative and general expenses involving affiliates merely to aid rate case proceedings as requested by AGD. \45\See 18 CFR Part 201, General Instruction No. 2, Records. (1995) --------------------------------------------------------------------------- KN asks for clarification on how to account for no-notice service revenues because no-notice service combines storing gas and transporting gas. The new accounts require classification of revenues according to the type of service or services provided. For example, revenues from no-notice service that is predominantly transportation should be recorded in Account 489.2, Revenue from Transportation of Gas of Others through Transmission Facilities, whereas revenues from no- notice service that is billed under a separate storage rate schedule should be recorded in Account 489.4, Revenues From Storing Gas of Others. Revenues from no-notice services which combine transportation and storage services, such as KN's Rate Schedule NNS, should be recorded in Account 489.2.46 \46\Form 2 page 305 footnote 6 specifies that revenues from bundled transportation and storage services should be reported in Account 489.2. --------------------------------------------------------------------------- 2. Accounting for Gains and Losses In the NOPR, the Commission proposed to include gains on settlements of imbalance receivables in Account 495, Other Gas Revenues. Losses were to be included in Account 813, Other Gas Supply Expenses. Additionally, the Commission proposed that gains recorded in Account 495 that are to be passed along to customers in future periods were to be offset by charging Account 407.3, Regulatory Debits, and crediting Account 254, Other Regulatory Liabilities. In a similar fashion, losses that are to be passed along to customers in future periods were to be offset by crediting Account 407.4, Regulatory Credits, and charging Account 182.3, Other Regulatory Assets. Panhandle objects to the recording of gains on imbalance transactions that are to be passed through to customers in Account 495, Other Gas Revenues, because it could create additional state [[Page 53029]] gross receipts tax expense due to the increase in reported revenues. It adds that the Commission would need to provide a gross-up factor to allow pipelines appropriate cost recovery. Williston opposes new item 8 of Account 495 as part of its opposition to the Commission's treatment of gains and losses on the settlement of imbalance receivables in Accounts 495, 806, Exchange Gas, and 813 (see infra). It states that settlements of imbalances and exchange transactions flow through the company's imbalance tracking mechanism and no gains or losses are recognized. It requests the Commission to allow pipelines that account for such gas through an imbalance mechanism the flexibility to continue accounting for settlement units of imbalance receivables pursuant to their current procedures. The Commission will modify its proposed accounting for gains and losses on imbalance transaction in instances in which a pipeline's tariff requires that such gains and losses be passed along to customers. Rather than initially recording a gain or loss (in Account 495 and Account 813, respectively and separately deferring the gain or loss as a regulatory asset or liability (by charging Account 407.3, Regulatory Debits, or crediting Account 407.4, Regulatory Credits, respectively), the Commission will require pipelines to record the gain or loss on imbalances directly in Account 254, Other Regulatory Liabilities, or Account 182.3, Other Regulatory Assets, as appropriate consistent with Order No. 552.47 This modification should satisfy both Panhandle's and Williston's concerns. \47\III FERC Stats. & Regs. para.34 967 (1993). --------------------------------------------------------------------------- D. Gas Supply Expenses The Commission is revising Account 806, Exchange Gas, so that it will include debits or credits for the cost of gas in unbalanced transactions and not just unbalanced exchange transactions. Such unbalanced transactions would be those whereby gas is delivered to another party in exchange, load balancing, or no-notice transportation transactions. The cost of exchanged gas is to be determined from the current market price of gas at the time the gas is tendered for transportation. Contra entries to those in Account 806 will be made to Account 174, Miscellaneous Current and Accrued Assets, and Account 242, Miscellaneous Current and Accrued Liabilities. As recommended by commenters, the Commission is modifying its proposed rule to require that records be maintained only by customer, quantity and cost of gas delivered and received, rather than by point of receipt and delivery. Additionally, the Commission is moving the requirements for the recording of gains and losses on settlement of receivables and payables to the text of Accounts 174 and 242. The comments are discussed below. 1. Recordkeeping INGAA recommends that imbalance data be kept by category or on a contract basis. CNG maintains that the level of detail and tracking by customer is too burdensome. Williams contends that tracking transportation balances on a transaction-by-transaction basis is administratively very burdensome and not required for regulatory purposes. MRT maintains that data on load-balancing or no-notice transportation is maintained by quantity (not value of gas) and not broken down to the specific receipt point level. The Commission concludes that it is appropriate to require information by customer of the quantity and cost of gas delivered and received. This information would be that typically maintained by pipelines in any event to support their receivable and payable balances, and should not result in an additional burden. Conversely, since the Commission does not have a regulatory need for information by point of receipt and delivery, it will not adopt the NOPR proposal to require pipelines to maintain such information. In response to MRT's assertion, the Commission is not proposing a new requirement to maintain the cost of exchange transactions; it has always required pipelines to record the cost, as well as the quantity of exchanges. Cost information is essential in determining the pipeline's expenses as well as its exchange receivables and payables. Therefore, the Commission will continue to require the recording of the cost of imbalance transactions. Panhandle generally agrees with the proposal but maintains that the Account 806 instructions create needless difficulties. It asserts, ``While Account 806 records only imbalance activity settled by receipt or delivery of gas, paragraph C of the account description includes a burdensome record-keeping procedure that requires records to be maintained for quantities and consideration, by receipt and delivery point, for all imbalance activity, including imbalances settled in cash.'' It also ``believes the procedures should not be included in the instructions to Account 806. The detail requested in the instructions will not track the entries made to Account 806 if cash-out transactions are excluded from this account.'' It ``suggests the required record keeping be dropped due to the excessive burden or, if there is some demonstrated need for this activity, the requirement should be moved elsewhere in the Uniform System of Accounts to avoid confusion about the makeup of Account 806.'' The Commission agrees with Panhandle that the proposed instructions to Account 806 require pipelines to maintain detailed information on all exchange transactions, including non-gas exchanges, e.g., exchanges settled in cash. Panhandle correctly maintains that because cash-out transactions would not be included in Account 806, the proposed detailed records would not track the entries to Account 806. Therefore, the Commission will adopt Panhandle's suggestion to move the detailed recordkeeping requirements for cash-out transactions to other accounts. Those recordkeeping requirements will be moved from Account 806 to Accounts 174 and 242. Accounts 174 and 242 are the accounts used to record all exchanges, including non-gas transactions. 2. Valuation In the NOPR the Commission proposed that Account 806 include the cost of gas in unbalanced transactions determined from the current market price of gas at the time gas is tendered for transportation. Columbia agrees with the proposed Account 806 but maintains that gas should be priced at its value and not its cost because it incurs no cost. The Commission concludes that the amounts recorded in Account 806 should be based on the measurement attribute of the gas received or delivered in the exchange. If gas delivered in an exchange has been priced on a historical cost basis (which would include gas withdrawals from storage priced on an inventory method), the amounts to be recorded in Account 806 should be based on the historical cost of the gas. If gas delivered in an exchange is priced at current market value (which would be the case for gas withdrawals from storage priced on a fixed asset method), the amount to be recorded in Account 806 would be the current market value. Exchange gas received that is not a satisfaction of an existing exchange gas receivable should be recorded in Account 806 at current market value. 3. Accounting Recognition of Exchanges The NOPR did not address the appropriate accounting recognition for exchanges involving customer-owned gas. [[Page 53030]] Williams states that under FERC Order No. 636, it retained storage capacity for system balancing purposes, but did not retain an investment in its working gas in storage. Williams argues that because it does not take title to gas flowing on its system, it need not price [record] transportation imbalances. Williams recognizes that it has an operational obligation to redeliver gas to the owner; however it submits that it has no recordable liability under GAAP. Williams also maintains that it should not record a positive customer imbalance just as it does not record gas injected into storage because both represent inventory on consignment. Williams' arguments for not recording transportation imbalances appears similar to Columbia's request for clarification of the use of Account 117.4. Both companies address the situation in which a pipeline uses customer supplied gas to meet imbalances. As with Columbia, it appears that Williams has an arrangement with its customers which allows Williams to use its customers' gas for balancing purposes. Accordingly, Williams (and any other similarly situated pipeline) must record amounts in Account 117.4 only after customer gas available to the utility for system balancing purposes has been exhausted. Williams (and any other similarly situated pipeline) should record a receivable and payable for all customer gas that is used to meet exchange imbalances to reflect its right to receive gas from one shipper and its obligation to provide gas to another shipper. 4. Imbalance Sub-Accounts The Commission proposed revisions to Account 806 to include the cost of gas in all unbalanced transactions, but did not propose any new subaccounts of Account 806. AGD states its concern that the Commission's changes might result in higher rates by claims for excessive amounts associated with imbalance issues. It requests separate subaccounts to Accounts 813, 806, and 495 to permit proper scrutiny in rate cases. NGSA suggests renaming Account 806 as ``System Gas'' because exchanges are only one specific component of this account. It also suggests subaccounts for Account 806 for no-notice (806.1), Exchange (806.2), Gathering (806.3), Transportation (806.4), and 806.5. (other specify)48 It states that these should be reported by rate schedule. \48\See also Accounts 164, 174, and 808.10, 808.20, and 813 for similar subaccount proposals. --------------------------------------------------------------------------- The Commission will not rename Account 806 as suggested by NGSA because the only amounts to be reflected in Account 806 are for exchange imbalances. Neither will the Commission prescribe separate subaccounts of Account 806 as proposed by AGD and NGSA, as this level of subaccount detail appears unduly burdensome. However, as required by General Instruction No. 2 of the Uniform System of Accounts, pipelines must maintain their books and records so as to be able to readily furnish full information as to any item included in Account 806. This information should be adequate to allow the Commission to address claims by pipelines associated with imbalance issues and thereby satisfy AGD's concerns. 5. Gas Losses The Commission did not propose new accounts for the recording of gas losses other than those related to storage. NGSA suggests the Commission include a separate transmission expense account for gas losses. KN maintains that an account is needed for gas losses for transmission, gathering, and distribution similar to Account 823 for storage. The Commission agrees that it is necessary to designate an account for non-storage gas losses. Therefore, the Commission is revising the text of Account 813, Other Gas Supply Expenses, to provide for the recording of losses of system gas not associated with underground storage. 6. Rates The Commission did not address potential ratemaking issues in this rulemaking. Some commenters expressed ratemaking concerns. NI-Gas submits that any change to existing tariff mechanisms must be handled through an appropriate tariff filing. AGD asks for clarification that the Commission's accounting standards are not determinative of the rate treatment of the recorded amounts. This rule is establishing accounting that is intended to measure and recognize the economic effects of transactions, events and circumstances affecting pipelines. While the final rule is expected to provide information useful for ratemaking purposes, the Commission's financial accounting requirements do not necessarily dictate how costs related to the transactions, events or circumstances should enter into the determination of rates. Ultimately the manner in which costs are considered for ratemaking purposes is a matter to be resolved in a rate proceeding. 7. Other Issue Several commenters requested clarification as what type of imbalances are to be included Accounts 806 and 813. Account 806 will include all imbalances, including those arising from unbalanced transactions whereby gas is delivered to another party in exchange, load balancing, or no-notice transportation transactions. As stated in Footnote 12 of the NOPR, system balancing refers to those situations where the pipeline provides gas from its own source of supply in order to meet deficiencies caused by a shipper tendering less volumes to the pipeline at the receipt point than it takes from the systems at the delivery point. The term can also be used to refer to situations where the shipper tenders more volumes than it takes from the system. Account 813 will include losses on settlement of imbalance transactions. E. Major/Nonmajor Accounts The Commission is eliminating all Nonmajor accounts in the Uniform System of Accounts and is requiring all natural gas companies to use the same accounts. The Commission is, thus, also changing the Major accounts to eliminate their application to Major natural gas companies only and is revising the instructions, notes, and items accordingly. In addition, as discussed below, the Commission is revising Form No. 2-A to require Nonmajor respondents to file certain Form No. 2 pages as their Form No. 2-A report. The Commission is revising part 158 of the regulations to delete the references to Major and Nonmajor in sections 158.10 and 158.11. INGAA and KN support the elimination of Nonmajor accounts in the Uniform System of Accounts. No commenter opposes it. F. Mcf to Dth At present, the Uniform System of Accounts requires reporting volumes by Mcf. The Commission is amending the Uniform System of Accounts where applicable to measure gas by dekatherms rather than by Mcf to reflect the current measurement of gas by heat content rather than by volume. INGAA and others49 support the change from Mcf to Dth in gas measurement. Kern River, however, maintains that its measurement standards should not be changed from volumetric to thermal. A significant majority of pipelines state their rates on the basis of either MMBtu or Dth. Only a few pipelines continue to state their [[Page 53031]] rates in Mcf. The Commission earlier adopted in section 284.4 of its regulations MMBtu measurement base for all reports submitted under Part 284. The change to the regulations in this rulemaking is intended to expand on the Commission's earlier action and reflect the prevalent practice in the industry. However, some of the remaining companies may perceive a hardship in switching from Mcf to Dth or MMBtu. Those companies may seek waiver of this provision. The Commission will consider any arguments set forth by those companies at that time. \49\KN, Columbia, NGSA, and Panhandle. --------------------------------------------------------------------------- Transok agrees with the change from Mcf to Dth, but it suggests that the Commission ``require uniform measurement of dekatherms at a specific pressure base, i.e. 14.65 psia, a specific temperature base, i.e. sixty degrees Fahrenheit (60 deg.F), and specific Btu water content measurement, i.e., dry or saturated.''50 It submits that this will provide uniform reporting so that precise comparisons can be made between pipelines. Even though pressure, temperature, and water content affect the heating value of gas, the Commission will not require uniform reporting because pipeline tariffs do not contain a standard definition of heating value. \50\Comments at 5. --------------------------------------------------------------------------- G. Merchant Accounts Several commenters point out that state public utility commissions have required utilities under their jurisdiction to adopt this Commission's Uniform System of Accounts and Form 2. Missouri requests that the Commission retain the requirements related to the purchase and sale of natural gas, at least during a 2-3 year transition period. PG&E maintains that the revised Uniform System of Accounts is inconsistent with the role and needs of LDCs. It submits that it is not adequate in some instances (e.g., no accommodation for bundled sales) and onerous in others (e.g., tracking the cost of gas used for imbalance transactions for each customer each month on a FIFO inventory basis). It suggests that the Commission either establish separate accounts that support the accounting and reporting functions of transport-only and non-transport-only pipeline companies respectively or retain accounts that support the continuing merchant functions of LDCs. Last, PG&E suggests convening a technical conference to explore maintaining uniform accounting practices in the natural gas industry. Columbia Distribution suggests the Commission consult with the National Association of Regulatory Utility Commissioners and use an extended transition period. Consumers Power also maintains that elimination of the sales accounts would result in regulatory confusion because LDCs would have to use accounts that were not intended to reflect the sales function. It believes the Commission should retain the account numbers that relate to the merchant function. Missouri also submits that pipelines are not prohibited from acting as merchants and, therefore, the existing gas purchase and sale accounts and reporting requirements should be retained. It states that a pipeline can indicate that those requirements are not applicable to its circumstances. AGA maintains that certain LDCs and pipelines still provide a merchant function and hence none of the sales accounts should be eliminated. The Commission's reason for deleting the Form No. 2 schedules reporting merchant activities is to recognize that pipelines for the most part are now engaged in transportation activities and not sales. Hence there is no longer a need for such schedules. While it is true that two pipelines and many LDCs engage in merchant activities, they may continue to retain the deleted schedules if needed for reporting to other jurisdictions. None of the merchant accounts have been eliminated from the Uniform System of Accounts and so they may still be used for this purpose. However, for the Commission to retain these Form No. 2 schedules implies they are still needed for the Commission's regulatory activities, which is not the case. Therefore, the Commission will delete these schedules as proposed in the NOPR. Last, the Commission sees no need to convene a technical conference. H. Index MRT requests that the Commission consider developing a subject matter index to Parts 201 and 216 as an aid to pipelines in complying with these regulations. The Commission believes that the current Charts of Accounts and headings are adequate. IV. Part 158 (CPA Certification Statement) The Commission is to remove the designations ``Major and Nonmajor'' from sections 158.10(a) and 158.11. In addition, the Commission is requiring independent licensed public accountants to be licensed on or before December 30, 1970, as is the case in current section 158.10(b). Moreover, the Commission is deleting present section 158.10(b). Further, the Commission is revising section 158.11 to require the filing of the independent accountant's letter or report of certification with the original and each copy of the Form No. 2 or Form No. 2-A rather than having the option to file it with the original or within 30 days after the filing of the Annual Reports as is the case now. Last, the Commission is revising section 158.12 to remove an outdated provision. Columbia objects to the revised Part 158 as potentially broad in scope and views it as unclear whether the intent is to modify the current scope or report of the independent certified public accountant in issuing its opinion on the Form No. 2. It argues that the proposed revisions to section 158.10 with respect to the independent accountant identifying questionable matters and to section 158.11 with respect to the independent accountant's letter or report certifying approval make no mention of the significance or materiality of the issues to be identified. It next maintains that the statements could be interpreted as requiring the independent accountant to, in effect, perform a compliance audit. It argues that it is entirely inappropriate for the Commission to modify the scope of the work at present performed by the independent accountant or to require a report inconsistent with Generally Accepted Accounting Standards. It asserts that the accounting firm should be required only to opine that the Form 2 pages are, in its opinion, fairly stated and, if not, explain the deviation in an explanatory paragraph, if it is significant or material with respect to the Uniform System of Accounts. Columbia also objects to Part 158's statement ``that the independent accountant will seek advisory rulings by the Commission on such [questionable] items.'' It maintains that it is the responsibility of management to resolve questionable accounting and reporting issues. It is not the function of the independent accountant to do that without management's authorization or to perform compliance audits with the Commission. The changes to Sections 158.10 and 158.11 of our regulations do not modify the current scope of work of the independent certified public accountant in issuing its opinion on the Form 2. In addition, the Commission is not requiring a report inconsistent with Generally Accepted Auditing Standards. To the contrary, these changes, together with other Form-2 reporting changes discussed infra, will permit our certification requirements to be met in a manner consistent with the reporting requirement standards under Generally Accepted Auditing Standards. [[Page 53032]] The Commission has addressed the issue of significance or materiality in Instruction No. III(c)(i) of the revised Form No. 2, which requires that a letter or report be submitted which will ``* * * contain a paragraph attesting to the conformity, in all material aspects, of the below listed schedules * * *.'' With respect to identifying questionable matters and seeking advisory rulings, those provisions are unchanged and relate to the early resolution of questionable matters to aid the certification process. Whether an independent accountant will seek such a ruling on any item is for it to determine in appropriate consultation with the respondent. V. Part 250 Part 250 of the Commission's regulations specifies the use of certain forms for accomplishing specific actions. As further described below, the Commission generally is simplifying, updating, or eliminating certain sections of Part 250 to reflect current regulatory practice, and the deregulation of the wellhead gas market. However, in the NOPR, the most significant change that the Commission proposed to Part 250 was the removal in section 250.16 (Format of compliance plan for transportation services and affiliate transactions) of the transportation discount information that a pipeline transporting gas under subparts B or G of Part 284 and conducting discounted transportation transactions with a marketing or brokering affiliate must maintain for each billing period. The Commission proposed to eliminate the discount reporting requirements from section 250.16(d) because they replicate to some extent the information required by the discount reports under section 284.7(d)(5)(iv). The Commission had proposed to modify section 284.7(d)(5)(iv) (proposed section 284.7(c)(6)) to include, among other things, most of those requirements currently required under section 250.16(d) that are not already duplicated in section 284.7(d)(5)(iv). Thus, the Commission proposed to delete section 250.16(d) as unnecessary. As discussed in greater detail infra, cthe Commission is not adopting the proposal to expand section 284.7 to include the requirements of 250.16(d). Consequently, the Commission must retain section 250.16(d). Therefore, the Commission is not adopting the proposal to delete that section. The Commission will continue to rely on the two, separate requirements--one reporting and one records maintenance--to ensure nondiscriminatory discounting of firm and interruptible transportation. However, the Commission is deleting two items of transportation discount information from section 250.16(d). We do not need to require pipelines to include in the discount report the shipper's designation, such as local distribution company, intrastate pipeline, end-user, etc., or the affiliate relationship between the pipeline and the shipper. This information can be determined from other, public sources, and therefore, its exclusion will not affect the Commission's ability to effectively monitor affiliate discounts. Most commenters responded to the proposed changes to the discounting reporting requirements with comments addressing the new, proposed reporting requirement, section 284.7(c)(6). The commenters that express support for the deletion of section 250.16(d), such as SoCal and APGA, also support the proposed changes to section 284.7. In other words, no party argues for the deletion of section 250.16(d) even if section 284.7 is retained in its present form.51 \51\Columbia notes its support for the deletion of section 250.16(d), but is silent with respect to the proposed modifications to section 284.7. --------------------------------------------------------------------------- However, NGSA objects to the removal of 250.16(d). NGSA fears that the submergence of information on affiliated deals within information on all discounted transportation programs will provide pipelines a greater degree of obscurity within which grants of affiliate preference may go unnoticed. Our retention of section 250.16(d) satisfies these concerns. Finally, in paragraphs (c)(3) and (d)(2) of section 250.16, the Commission is deleting reference to the Commission's street address. The Commission is modifying the following other sections of Part 250, as described below. Essentially, these modifications either update the forms to conform to current regulatory practice, or eliminate the forms related to the regulation of producers and gatherers, since the wellhead gas market has been finally deregulated and such forms are required by regulations that have been removed in Parts 154 and 157. Section 250.2 sets forth the forms required under section 154.64 (new section 154.602) for notification to the Commission of a cancellation of a filed tariff or part thereof, or a termination of the tariff by its own terms, when no new tariff or part thereof is to be filed in its place. The Commission is simplifying and clarifying section 250.2 by stating that the notices of cancellation to be used when canceling an entire tariff or an entire rate schedule should be filed as a tariff sheet. Currently, the existing forms themselves include the header and footer information normally associated with a tariff sheet, which is unnecessary and confusing. In addition, the Commission is modifying section 250.2 by eliminating the requirement that a specific form be used when providing notice of the cancellation of individual tariff sheets. Rather, section 250.2 will provide that when a single sheet is canceled, it should be reserved for future use. This does not represent a substantive change, but more accurately represents the current practice in canceling a tariff sheet, and will allow the sheet to conform better to the Commission's electronic tariff sheet filing requirements. Section 250.3 specifies the form required under section 154.64 (new section 154.602) for notification to the Commission of a cancellation or termination of a contract, or executed service agreement. The Commission is changing the current instruction in the form to indicate the ``name of purchaser or purchasers'' to an instruction to indicate the ``name of customer or customers.'' The use of ``customer'' rather than ``purchaser'' better reflects the shift in today's gas market from sales to transportation service. The Commission is modifying the headings of sections 250.2, 250.3, and 250.4 (governing the form of the certificate of adoption required under existing section 154.65 (new section 154.603) to be used when the tariff or contracts of a natural gas company are to be adopted by a successor entity) to refer to the new section numbers of the regulations from which their authority stems, since the Commission, in the companion rulemaking, is redesignating the referenced sections of Part 154. Thus, the reference in sections 250.2 and 250.3 to section 154.64 is changed to section 154.602, and the reference in section 250.4 to section 154.65 is changed to section 154.603. In section 250.4, the Commission is also modifying the line indicating the date of the form of certificate of adoption by removing the year indicator of ``194--.'' Many of the forms set forth in Part 250 relate to the filing requirements of natural gas producers and gatherers under Parts 154 and 157 of the Commission's regulations. Specifically, section 250.5 specifies the form of contract summary required to be filed under section 154.24(a) by independent producers applying for a certificate of public convenience and necessity under section 7 of the NGA for the transportation, or sale for resale, of [[Page 53033]] natural gas in interstate commerce. Section 250.7 specifies the form of contract summary required to be filed under section 157.30(b) by independent producers seeking abandonment authorization. Section 250.8 specifies the form for the summary of contract information required by section 154.92(d) to be filed by independent producers seeking authority to provide natural gas service, previously authorized by the Commission, as a successor-in-interest. Section 250.9 specifies the form of notice required under section 154.97(a) to be filed by an independent producer when a rate schedule is proposed to be cancelled, or will terminate by its own terms, and no new schedule is to be filed in its place. Section 250.10 specifies the form required to be filed under section 157.40(b)(4) by independent producers applying for a small producer exemption from certain filing requirements. Section 250.14 specifies the form of the initial billing statement required under section 154.92 to be filed with the filing of a rate schedule by every independent producer, and the form required under section 154.94(f) to be used by an independent producer seeking a change in its rate schedule. All of the above-referenced sections of Parts 154 and 157 have been removed from the Commission's regulations by Order No. 567, issued July 28, 1994, in Docket No. RM94-18-000.52 Order No. 567 deleted certain regulations related to natural gas producer rate regulation that were either obsolete or nonessential in light of the deregulation of wellhead gas prices under the Natural Gas Wellhead Decontrol Act of 1989,53 that finally occurred on January 1, 1993. Since the regulations requiring that independent producers make certain filings, and in specific forms, have been deleted, sections 250.5, 250.7, 250.8, 250.9, 250.10, and 250.14 of part 250, setting forth the actual forms, will also be deleted. Thus, the Commission is removing these sections. \52\68 FERC para.61,135 (1994). \53\Pub. L. No. 101-60; 103 Stat. 157 (1989). --------------------------------------------------------------------------- The Commission is also removing section 250.12, governing the form of escrow agreements. This regulation was originally promulgated by Order No. 400, issued April 28, 1970, in Docket No. R-376. It is rarely used. In the instances in which companies are required to place funds in escrow, the Commission will determine in the proceeding establishing the escrow requirement, the form of the escrow agreement, and whether the form should be filed with the Commission. In the NOPR, the Commission invited comments from parties who believe it would be useful to retain a form of escrow agreement, or suggestions as to how this regulation could be modified to become more useful, rather than eliminated. Only two parties commented in response to the Commission's inquiry. Missouri states that it has no concerns with the removal of this section as long as the Commission will still require the placement of funds in escrow when it deems such a remedy appropriate. Missouri believes that establishing the requirements for such an escrow arrangement in the proceeding where it is found appropriate is acceptable. The Industrials, however, object to the elimination of the form of escrow agreement in its present form from the regulations. They urge the retention of the escrow agreement due to its value in preserving ratepayers' refunds. They argue that if a case arises in which a modification to the form may be appropriate, the changes to the agreement may be addressed at the time it arises in the individual proceedings. The intent of the Commission's inquiry in the NOPR was to determine whether there was support for retention of the escrow agreement in its present form, or for adoption of a different form of escrow agreement, instead. None of the comments suggested a more appropriate form of escrow agreement. Rather, the parties' comments reflected concern that the Commission was proposing to eliminate altogether the use of escrow agreements to preserve ratepayers' refunds. The Commission's inquiry was not intended as a referendum on the utility of escrow agreements. The removal of section 250.12 does not prejudge the usefulness of an escrow agreement in a particular proceeding. The decision whether an escrow agreement should be imposed in a particular proceeding will have to be made in that proceeding, whether section 250.12 is retained or not. The elimination of the form of the escrow agreement should not impact the availability of escrow agreements or degree to which they are utilized. Therefore, since no comments were received suggesting why the current form of escrow agreement should be retained, or any improvements to the form of escrow agreement, the Commission will remove this section of the regulations. Finally, the Commission is changing all references in Part 250 from the ``FPC'' and the ``Federal Power Commission'' to the ``FERC,'' and to the ``Federal Energy Regulatory Commission,'' respectively. VI. Part 260 The provisions of Part 260 require that pipelines file certain forms and reports with the Commission, such as the FERC Form Nos. 2, 2- A, 11, and 549-ST. As further discussed below, the Commission is modifying the actual Form Nos. 2, 2-A, and 11, and various sections of Part 260. The changes to Part 260 are designed to update these reporting requirements to reflect current regulatory practice, and to conform these prescriptive requirements to the changes to the other parts of the Commission's regulations in this rule. A. Revisions to Form No. 2 The Commission is revising Form No. 2 for a variety of reasons. First, it is desirable to update Form No. 2 by deleting unneeded schedules, or individual data elements, by clarifying and modernizing schedules and instructions, and by increasing the thresholds for the reporting of certain information. Second, it is vital to revise Form No. 2 to accurately present the restructured nature of the natural gas pipeline industry, which is primarily focused on the transportation of gas rather than the sale of gas. Only then will the Form No. 2 provide more useful and relevant information to the Commission and to pipeline customers for the assessment of pipeline operations. A sample copy of the revised Form No. 2 is attached as Appendix B. The specific changes the Commission is making are: General Information--Pages i and ii The Commission is requiring Form No. 2 to be filed by each major interstate natural gas company having combined gas transported or stored for a fee exceeding 50 million dekatherms (Dth) in each of the three previous calendar years. This will replace the present requirement that Form No. 2 must be filed by major companies which are those having combined gas sold for resale and gas transported or stored for a fee exceeding 50 million Mcf at 14.70 psia (60 deg.F) in each of the three previous calendar years. The elimination of ``gas sold for resale'' reflects the current nature of the pipeline industry, in which pipelines are primarily transporters of gas and make sales for resale on an unbundled basis in the supply area. The replacement of Mcf with Dth reflects the current measurement of gas by heat content rather than by volume. The Commission also is revising the first two sentences of Instruction 1 on page i to eliminate as not needed the [[Page 53034]] statement that Form 2 is a regulatory support requirement. The last sentence in Instruction 1 is being revised to eliminate the reference to the Energy Information Administration's statistical publication (Financial Statistics of Interstate Natural Gas Pipeline Companies). The first sentence in Instruction II on page i is being revised to read ``Each major natural gas company that meets the requirements of 18 CFR 260.1 must submit this form.'' The Commission is revising Instruction III (a) to include the present requirement for filing on an electronic medium. The Commission is changing Instruction III(c) to replace the present Certified Public Accountant (CPA) certification statement with a flexible format that will enable the respondent's CPA firm to prepare its certification statement in accordance with current standards of reporting and still attest as to the conformity of listed FERC Form No. 2 schedules with the Commission's Uniform System of Accounts and the Chief Accountant's published accounting releases. In addition, the Commission is requiring that the letter or report required by Instruction III(c) for the CPA certification be submitted with each copy as well as with the original submission and be submitted with that submission rather than alternatively within 30 days after the filing date for Form No. 2. INGAA supports the above-described revisions. AGD maintains that the schedule on page 108, ``Important Changes During the Year'' should be covered by the audit report by including this page on page (i) in the list of schedules to which the independent auditor attests. AGD also suggests that, once the Commission updates its electronic filing capabilities, pipelines be required to file their Form No. 2 electronically and that this filing include all backup data that supports and elucidates the Form No. 2 information. It believes this monthly data is critical to detect trends, spot nonrecurring items, test the reasonableness of base period actuals, and determine the need for a Section 5 complaint. It also suggests that pipelines post their Form No. 2 filing on their electronic bulletin boards. Last, AGD submits that the Commission should establish new accounts to track computer system expenses. The Commission does not agree that page 108 should be covered by the independent auditor's attestation. The purpose of the CPA certification requirement is to obtain an independent verification that the basic financial statements in the Form No. 2 and 2-A were prepared in conformity in all material respects with the Commission's Uniform System of Accounts and published accounting releases. Page 108 requires the reporting of information that is not required to be disclosed on the face of the financial statements or the accompanying notes. To include this page as part of a CPA certification would require expanding the scope of the work conducted by the CPA beyond what was necessary to attest to the conformity of the financial statements to Uniform System of Accounts' requirements. Therefore the Commission will not adopt AGD's request. In addition, the Commission believes the additional burden that would be imposed would be greater than the benefit to be realized from it. The Commission therefore rejects the inclusion of page 108 as part of the independent auditor's attestation. The Commission concludes that AGD's electronic filing suggestions would be too burdensome. Therefore, although the Commission requires pipelines to file Form No. 2 on electronic media, it will not expand the scope of the electronic filing requirements to include all supporting data or to require posting on an electronic bulletin board. In addition, the Commission will not establish new accounts to track computer system expenses because existing accounts are adequate for this purpose. KN would eliminate all paper copies where electronic filings are required. Paper copies are still needed because not all respondents have electronic capability this time. General Instructions--Page iii The Commission is replacing Mcf with Dth in General Instruction II on page (ii) and ``14.73 psia and a temperature base of 60 deg.F'' with ``in Btu and Dth,'' in General Instruction XII on page (iii). The Commission also is deleting General Instruction V with respect to the means of completing the report as outdated and unnecessary. INGAA supports the above described revisions. Definitions--Page iv The Commission is defining dekatherm as a unit of heating value equivalent to 10 therms or 1,000,000 Btu.54 \54\Btu refers to British Thermal Unit--the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. --------------------------------------------------------------------------- INGAA supports the above-described definition. Excepts From the Law--Page iv The Commission is correcting the quoted language of the Natural Gas Act. INGAA supports this correction. List of Schedules (Natural Gas Company)--Pages 2-3 The Commission is revising the list of schedules to conform with the changes to the schedules adopted by this NOPR. No comments were filed. Control Over Respondent--Page 102 The Commission is revising the instructions and providing a format for information required with respect to entities controlling the respondent natural gas company to provide better reporting of the vertical integration of the respondent and its parents. The Commission is deleting referencing the SEC 10-K Report Form because most respondents are included in consolidated reports and do not prepare separate SEC 10-K reports. INGAA would allow referencing the SEC 10-K report. It would clarify that the instruction refers to a direct link between the holding company and the respondent. Missouri submits that the pipelines should report information about affiliate relations of other companies controlled by the pipeline's parent. It suggests including the name, manner of control, extent of control and a brief description of the business purpose. Panhandle maintains that this schedule should be deleted because material matters will be described in financial footnotes. The Commission is removing the ability of pipelines to reference the SEC 10-K reports for information because such references in the past have been inadequate for regulatory purposes. The Commission's experience has shown that the information contained in a respondent's parent's SEC 10-K generally has not provided the detail on the respondent that is needed by the Commission. Therefore, the Commission is rejecting the arguments that it not adopt the NOPR's proposed deletion of the respondent's ability to reference the SEC 10-K reports for information. Further, based on past filings, the Commission believes that the information to be required on page 102 will not be included in sufficient detail (if at all) in the footnotes to the financial statements for Commission regulatory purposes. The Commission will therefore require the information to be reported on page 102. On the other hand, requiring the respondents to report information about affiliates of other companies controlled by the pipeline's parent appears to be beyond what is needed for regulatory purposes at this time. Therefore, the Commission will not adopt Missouri's suggestion to [[Page 53035]] require the reporting of such information. Corporations Controlled By Respondent--Page 103 The Commission is deleting instruction 4, which permits referencing the SEC 10-K Report Form filing for the reason stated above. The Commission also is adding a new instruction 4 and new column (b) for designation of the type of control held by the respondent. The Commission is relettering columns (b)-(d) as (c)-(e). INGAA would allow referencing the SEC 10-K report. Panhandle would delete this schedule because material matters will be disclosed in financial statements. The Commission is adopting the changes proposed in the NOPR for page 103 for the reasons given for adopting the proposals for page 102. Officers--Page 104 The Commission is deleting this page because it is not needed for Commission regulatory purposes. INGAA supports deletion of this schedule. Directors--Page 105 The Commission is deleting this page because it is no longer needed for Commission regulatory purposes. INGAA supports deletion of this page. Security Holders and Voting Powers--Page 106 (Now 107) Panhandle would delete this page because material matters will be disclosed in financial footnotes. Based on past filings, the Commission believes that information sought by the instructions to page 106 will not be presented in the notes to the financial statements in the detail needed for Commission regulatory purposes. Therefore, this page will be retained. Security Holders and Voting Powers (Continued)--Page 107 The Commission is deleting this continuation page because it is not needed with electronic reporting since supplemental pages can be added if more space is needed. INGAA supports deletion of this page. Important Changes During the Year--Page 108 The Commission is deleting item 12, which allows the respondent to substitute notes from the annual report to stockholders for required data because the Commission's experience shows those notes to be inadequate or unresponsive due in part to the fact that many respondents are included in consolidated reports to stockholders and do not prepare separate annual reports. INGAA suggests deleting page 108 because the information is reported in the Notes to Financial Statement. Panhandle would also delete this page because material matters will be disclosed in financial statements. Williston asserts that the information required in item 8 is proprietary and that item 11 should be deleted because it is misleading due to the timing of final Commission rate orders and the impact on reserves for refund purposes. The Commission does not agree with INGAA or Panhandle that the information reported in the Notes to Financial Statements duplicates that required on page 108. In fact, to prevent duplication, the instructions on page 108 direct the respondent to reference the schedule in which information required by Page 108 appears, rather than report the same information in both places. As to Williston's comments, the Commission does not agree that the information required in item 8 is proprietary because an adequate response to the requirement to report the estimated annual effect and nature of any important wage scale changes may be prepared so as to not reveal proprietary information. The Commission also does not agree with Williston that information on the estimated increase or decrease in annual revenues due to important rate changes required by item 11 is misleading. The respondent can and should provide explanations to prevent wrongful interpretations of the data. Important Changes During the Year--Page 109 The Commission is deleting this continuation page because it is not needed with electronic reporting. No comments were filed. Comparative Balance Sheet (Assets and Other Debits)--Page 110 The Commission is modifying column (c) by deleting ``Balance at Beginning of Year'' and inserting ``Balance at End of Current Year (in dollars)'' and is modifying column (d) by deleting ``Balance at End of Year (in dollars)'' and inserting ``Balance at End of Previous Year (in dollars).'' The Commission also is deleting ``Gas Stored Underground Noncurrent (117)'' at Line 12 and replacing it with four new accounts-- Gas Stored--Base Gas (117.1), System Balancing Gas (117.2), Gas Stored in Reservoirs and Pipelines--Noncurrent (117.3), and Gas Owed to System Gas (117.4). The Commission further is changing the title on Line 16 from ``Other'' to ``Other Property and Investments.'' The comments addressing the proposed storage accounting are discussed above. Comparative Balance Sheet (Assets and Other Debits) (Continued)--Page 111 The Commission is modifying column (c) by deleting ``Balance at Beginning of Year'' and inserting ``Balance at End of Current Year (in dollars)'' and is modifying column (d) by deleting ``Balance at End of Year'' and inserting ``Balance at End of Previous Year (in dollars).'' No comments were filed. Comparative Balance Sheet (Liabilities and Other Credits)--Page 112 The Commission is modifying column (c) by deleting ``Balance at Beginning of Year'' and inserting ``Balance at End of Current Year (in dollars)'' and is Modifying Column (d) by deleting ``Balance at End of Year'' and inserting ``Balance at End of Previous Year (in dollars).'' The Commission also is adding the language ``(Less) Current Portion of Long-Term Debt'' to Line 22. INGAA supports the above-described revisions. Comparative Balance Sheet (Liabilities and Other Credits) (Continued)-- Page 113 The Commission is modifying column (c) by deleting ``Balance at Beginning of Year'' and inserting ``Balance at End of Current Year (in dollars)'' and modifying column (d) by deleting ``Balance at End of Year'' and inserting ``Balance at End of Previous Year (in dollars).'' INGAA supports the above-described revisions. The Commission is adding the language ``Current Portion of Long-Term Debt'' as line No. 33. Statement of Income For the Year--Pages 114-116 The Commission is moving instructions 5 and 6 from this schedule to Notes to Financial Statements on page 122. INGAA would clarify that the proper accounts for lines 9 and 10 are 407.1 and 407.2 to be consistent with the Uniform System of Accounts. The Commission agrees and is changing the account numbers on lines 9 and 10 to 407.1 and 407.2 respectively. The Commission is deleting instruction 7, which permits the attaching at page 122 of any notes appearing in the report to stockholders that are applicable to this Statement of Income, and is moving instruction 8 [[Page 53036]] from this schedule to Notes to Financial Statements on page 122. INGAA supports the above-described revisions. The Commission is adding the words ``(in dollars)'' to column headings (c) through (j). Statement of Retained Earnings For the Year--Page 118 The Commission is modifying column (c) by deleting ``Amount'' and inserting ``Current Year Amount (in dollars)'' and by adding column (d) ``Previous Year Amount (in dollars).'' The Commission also is deleting instruction 8, which requires the attaching at page 122 of applicable notes in the annual report to stockholders. INGAA supports the above-described revisions. Consistent with discussion of the revisions to page 118 of Form No. 2-A, the Commission will revise line 36 to read ``Balance--End of Year (Total of lines 1, 9, 15, 16, 22, 28, 34, and 35)''. Statement of Retained Earnings For the Year (Continued)--Page 119 The Commission is modifying column (c) by deleting ``Amount'' and inserting ``Current Year Amount (in dollars)'' and is adding column (d) ``Previous Year Amount (in dollars).'' INGAA supports the above-described revisions. Statement of Cash Flows--Pages 120 and 121 The Commission is deleting the first sentence of instruction 1, which requires the attachment at page 122 of applicable notes in the annual report to stockholders. The Commission is modifying column (b) by deleting ``Amounts'' and inserting ``Current Year Amount'' and by adding Column (c) ``Previous Year Amount.'' INGAA supports the above-described revisions. Notes to Financial Statements--Page 122 The Commission is changing instruction 1 to require at least the same level of detail for disclosures that would be given in shareholder annual reports and is adding new instructions to provide significant details on: the respondent's pension and other benefit plans and disclosure of financial changes either to the respondent or the respondent's consolidated group that will directly affect the respondent's gas pipeline operations. The Commission also is deleting instructions 3 (``For Account 116, Utility Plant Adjustments'') and 6 (permitting the attaching of notes to financial statements in the annual report to stockholders). In addition, as stated above, the Commission is moving three instructions from pages 114 and 115 to page 122. As discussed below, the Commission is not adopting proposed instructions 4 (income taxes) or 7 (differences between financial statements to stockholders/public and Form No. 2). INGAA recommends changes to improve the focus of information to be provided on this page. It would allow a reference to SEC 10-K reporting or reliance on GAAP for information on pensions, benefits, deferred taxes, etc. It suggests removing the requirement in Instruction 1 that notes be grouped under subheadings for each financial statement because most notes apply to more than one financial statement. It submits that this requirement could increase the number of notes and the duplication of information. It adds that GAAP does not require grouping of notes by financial statement and that this requirement creates a difference between GAAP and FERC reporting that is not needed or useful to the reader. It would delete instructions 2, 4, and 5. It would revise Instruction 3 to exclude the disclosure of cash contributions to pension, PBOP and other post-employment benefit plans since, it asserts, GAAP disclosures for those plans are adequate for Form 2. It would revise Instruction 7 because this should not be a regulatory requirement, except in limited instances where differences are not consistent with the Uniform System of Accounts or FERC Orders. It further states that the general purpose financial statements issued to shareholders or the public generally refer to the respondent's financial statements, and not those of the respondent's parent or ultimate parent. It states that instruction 11 requires explanations of changes in accounting methods made during the year which had an effect on net income. It maintains that instruction 11 should be revised to limit the requirement to significant changes. AGD would include any differences in accounting classifications between Form No. 2 and the latest NGA section 4 rate filing with more than a $3-4 million impact. Columbia maintains it would be an undue burden to list pursuant to proposed instruction 7 the differences in the way transactions are presented in the stockholders annual report versus the Form No. 2. It argues that the proposed requirement to disclose financial changes that will directly affect pipeline operations is unnecessarily duplicative of information that is reported on page 108. National Fuel submits that disclosures should be in accordance with GAAP as reflected in general purpose financial statements to the public or to shareholders, so that pipelines would not be forced to rewrite their Notes for the version of their financial statements incorporated in the Form No. 2. It also suggests that, because Form No. 2 will include a complete set of Notes to Financial Statements, any accompanying notes filed on an interim basis in other contexts (e.g., a new rate case) be deemed sufficient if they make the financial statements not misleading. It states that it assumes the reader has read the most recent Form No. 2. The Commission concurs with the commenters who question the regulatory applicability and the burden that will be caused by proposed instruction 7 and is deleting it. The Commission concurs with the comment that GAAP is sufficient for information on income taxes and is deleting proposed instruction 4. The Commission also agrees that instruction 11 should only require information on significant changes in accounting methods made during the year that had an effect on net income and is revising the wording in that instruction to read: ``* * * significant changes in accounting methods * * *'' The Commission does not agree that a reference to the SEC 10-K is sufficient and therefore will not allow referencing the SEC 10-K. As explained above, the Commission has found that such references in the past were inadequate for regulatory purposes. The Commission does not agree that instruction 1 should be revised as proposed by National Fuel because no rewriting is needed of the disclosures in general purpose financial statements. Rather, respondent merely will supplement those disclosures with information needed for Commission regulatory purposes. The Commission also does not agree with the comment that the requirement in instruction 1 to group notes by financial statement subheadings will result in duplication. The instruction is flexible in allowing separate disclosure of items that are applicable to more than one financial statement. In answer to the commenter who wants to exclude from proposed instruction 3 the cash contributions to pension, PBOP and other post- employment benefit plans, the reporting of cash contributions is necessary to aid the Commission staff in their determination of the level of these costs includible in a pipeline's rates. [[Page 53037]] Likewise, the retention of instructions 2 and 5 is essential in the Commission's ongoing analysis of the effect on rates of certain actions taken by a company. The Commission will not adopt AGD's recommendation to require reporting of significant differences between Form 2 accounting classifications and those used for rate filings because the accounting required for Form No. 2 must be consistent with that used for ratemaking purposes. Last, the Commission rejects National Fuel's suggestion that Form No. 2 notes may be filed in other contexts, because the Commission does not believe that filing updated notes will be unduly burdensome. Notes to Financial Statement (Continued)--Page 123 The Commission is deleting this continuation page because it is not needed with electronic reporting. No comments were received. Summary of Utility Plant and Accumulated Provisions for Depreciation, Amortization and Depletion (Continued)--Page 201 The Commission is deleting columns (f) and (g) both entitled ``other (specify)'' as unneeded because electronic reporting permits additional columns to be added as necessary. INGAA supports the above-described revision.55 \55\In this schedule's pages, the Commission is also deleting duplicative columns of account numbers. --------------------------------------------------------------------------- Gas Plant In Service (Accounts 101, 102, 103, and 106)--Pages 204-209 The Commission proposed no changes to these pages. However, consistent with the Commission discussion below of revisions to these pages of Form No. 2-A, the Commission will modify these Form No. 2 pages to indicate which lines are used for totals. Gas Property and Capacity Leased From Others--Page 212 The Commission is adding a new schedule to provide information about gas property and capacity leased from others. The Commission is requiring only the reporting of property leases in which the average annual lease payment under the initial term of the lease exceeds $500,000. INGAA responds that information requested by the NOPR is at a level of detail that is not needed. It asks for clarification that reporting is for gas property and capacity leased from others pertaining to gas operations. INGAA and Panhandle comment that pipelines should disclose only names of lessor, description of leases, and lease payments. Panhandle would raise the threshold to $1,000,000. The Commission clarifies that reporting is for gas property and capacity leased from others pertaining to gas operations and agrees that pipelines need to disclose only the name of the lessor, description of lease, and lease payments. The instructions will so indicate. The Commission will not raise the threshold to $1,000,000 because that level is too high for the reporting of meaningful information. Gas Property and Capacity Leased To Others--Page 213 The Commission is revising the schedule on page 213 entitled ``Gas Plant Leased to Others (Account 104)'' by changing the schedule and instructions about gas property and capacity leased to others. The changes are necessary to provide information that would allow the Commission to determine whether ratepayers are paying for facilities not used in the respondent's utility operations. The Commission is requiring only the reporting of property leases in which the average annual lease income over the initial term of the lease exceeds $500,000. INGAA asks for clarification that reporting is for gas property and capacity leased to others pertaining to gas operations. It comments that columns (c) and (e) are missing on the form. The Commission so clarifies and has corrected the columns. Gas Plant Held For Future Use (Account 105)--Page 214 The Commission is raising the reporting threshold of $250,000 to $1,000,000 as suggested by INGAA, rather than to $500,000 as proposed in the NOPR. The Commission is also deleting the language in Line No. 1 which refers to pages 500-01, which are proposed to be deleted. Production Properties Held For Future Use (Account No. 105.1)--Page 215 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports deletion of this schedule. Construction Work In Progress--Gas (Account 107)--Page 216 The Commission is raising the threshold from $500,000 to $1,000,000 as suggested by INGAA and Panhandle. The NOPR had proposed no change to the $500,000 threshold. Construction Overheads--Gas--Page 217 The Commission, as suggested by INGAA, is deleting this page because page 218 reports adequate information. Gas Stored (Accounts 117.1, 117.2, 117.3, 117.4, 164.1, 164.2, and 164.3)--Page 220 The Commission is deleting Account 117 and replacing it with four new accounts as discussed above. The Commission also is changing Mcf to Dth in instruction 1 and lines 6 and 7, is redesignating the column letters, eliminating instructions 2 through 5 as no longer necessary, and adding a new instruction on encroachments on base gas, system balancing gas, and gas properly recordable in the plant accounts. INGAA suggests that additional changes may be required on this page to accommodate the actual use of storage inventories. NGSA states this page should match page 513 and page 513 should have reporting by account. The Commission believes this schedule is adequate as proposed and will make no further changes to it. The Commission does not agree with the comment that this page should match page 513; the two schedules serve different purposes. Page 220 is a supplement to the Balance Sheet and page 513 is meant only for operational data. Nonutility Property (Account No. 121) and Accumulated Provision For Depreciation and Amortization of Nonutility Property (Account 122)-- Page 221 The Commission is deleting these schedules because they are not needed for Commission regulatory purposes. INGAA supports this deletion. The APGA opposes deletion because this page has vestigial value about changes is a pipeline's business. The Commission does not believe that vestigial value supports the burden of reporting this information. Investments (Accounts 123, 124, 136)--Pages 222-225 and Investments in Subsidiary Companies (Account 123.1)--Pages 224 and 225 The Commission did not propose any changes to these pages. INGAA and Panhandle would delete these pages. INGAA states the information has no regulatory purpose. Panhandle states that material matters will be described in financial footnotes. The Commission will retain these pages because the required data provides the Commission with relevant information that is useful in [[Page 53038]] determining the respondent's affiliations and in analyzing financing arrangements that may affect regulated pipeline operations. In addition, the Commission, based on past filings, concludes that the data will not be presented in the notes to the financial statements in the detail needed for Commission regulatory purposes. Gas Prepayments Under Purchase Agreements--Pages 226 and 227 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports this deletion. But the APGA opposes it because this page has vestigial value about changes in a pipeline's business. The Commission does not believe that vestigial value supports the burden of reporting this information. Advances For Gas Prior to Initial Deliveries or Commission Certification (Accounts 124, 166, and 167)--Page 229 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports deleting this schedule. Prepayments (Account 165)--Page 230 The Commission is eliminating the instruction requiring the reporting of all payments for undelivered gas and the completion of pages 226 to 227, along with Line 5, Gas Prepayments (pages 226-227). Pages 226 and 227 are also eliminated. INGAA supports the revisions in order to make this page consistent with pages 226 and 227. The Commission is also adding a column entitled ``Balance at Beginning of year.''56 \56\This column is also being added to the schedules, ``Extraordinary Property Losses (Account 182.1)'' and ``Unrecovered Plant and Regulating Study Costs (Account 182.2).'' --------------------------------------------------------------------------- Preliminary Survey and Investigation Charges (Account 183)--Page 231 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports deleting this schedule. Other Regulatory Assets (Account 182.3)--Page 232 The Commission is raising the reporting threshold for minor items from $50,000 to $250,000 rather than to $100,000 as proposed in the NOPR. The Commission is adding new instruction 4--``Report separately any `deferred regulatory Commission expenses' that are also reported on pages 350-351, Regulatory Commission Expenses''. INGAA agrees with the proposed revisions and, along with Columbia, suggests the addition of a beginning balance field. Transco would raise the threshold to $500,000 and Panhandle would raise it to $1,000,000. The Commission will add a beginning balance field and, as stated, will raise the threshold to $250,000, consistent with the threshold we are adopting for other asset and liability schedules. This threshold will mitigate the reporting burden on pipelines while providing the Commission with useful information for small as well as large pipelines. Miscellaneous Deferred Debits (Account 186)--Page 233 The Commission is raising the reporting threshold for minor items from $100,000 to $250,000 and is deleting Line No. 48 ``Deferred Regulatory Commission Expenses (see pages 350-351). INGAA and Columbia support this revision, but would also delete ``Account charged'' col. (d). Transco would raise the threshold to $500,000. Panhandle would raise it to $1,000,000. The Commission believes that column (d) should be retained as it provides useful information and that the $250,000 threshold is the appropriate threshold level for this information. Accumulated Deferred Income Taxes (Account 190)--Pages 234-235 The Commission did not propose any changes to these pages. INGAA would delete the ``Notes'' section and follow the pages 274 and 275 format, which it says is more consistent and better organized. The Commission will make the format of pages 234-235 consistent with that of pages 274-275. However, the Commission will retain the ``Notes'' section. Capital Stock (Accounts 201 and 204)--Pages 250 and 251 The Commission is deleting part of instruction 1, which permits referencing the SEC 10-K Report Form filing. The Commission is making this deletion because many respondents are included in consolidated reports that do not provide the required information about the respondent. The Commission discusses below the arguments to delete this schedule. Capital Stock subscribed, Capital Stock Liability For Conversion, Premium on Capital Stock, and Installments Received on Capital Stock (Accounts 202 and 205, 203 and 206, 207, 217)--Page 252 The Commission below discusses the arguments to delete this schedule. Other Paid-in Capital (Accounts 208-211, inc.)--Page 253 The Commission discusses below the arguments to delete this schedule. Discount on Capital Stock (Account 213)--Page 254 The Commission discusses below the arguments to delete this schedule. Capital Stock Expense (Account 214)--Page 254 The Commission discusses below the arguments to delete this schedule. Securities Issued or Assumed and Securities Refunded or Retired During the year 1992--Page 255 The Commission discusses below the arguments to delete this schedule. Long-Term Debt (Accounts 221, 222, 223, and 224)--Page 256 The Commission is deleting part of instruction 1, which permits referencing the SEC 10-K report Form filing for the reason stated above. The Commission discusses below the arguments to delete this schedule. Unamortized Debt Expense, Premium and Discount on Long-term Debt (Accounts 181, 225, and 226)--Pages 258 and 259 The Commission discusses below the arguments to delete this schedule. Unamortized Loss and Gain on Reacquired Debt (Accounts 189, 257)--Page 260 INGAA and Panhandle maintain that the above pages (250-260) should be deleted because material matters will be in the Footnotes to the Financial Statements or there is no regulatory purpose for the information. The Commission disagrees with INGAA and Panhandle. The information required to be reported on pages 250-260 is not detailed in the footnotes to the Financial Statements. This information allows the Commission and the public to determine the cost and changes in the levels of the respondent's debt, preferred and common stock. Such information is directly relevant to the pipeline's cost of providing service. Therefore, the Commission will not delete these pages. [[Page 53039]] Reconciliation of Report Net Income With Taxable Income for Federal Income Taxes--Page 261 The Commission did not propose any changes to this page. INGAA would delete this schedule because there is no regulatory purpose for this information. The Commission disagrees. The information on this page is useful in analyzing the pipeline's Federal income tax component of its cost of service, including its deferred taxes. Therefore, this page will be retained. Taxes Accrued, Prepaid and Charged During Year--Pages 262 and 263 The Commission proposed no change to this schedule. INGAA suggests the grouping of minor items under $250,000 and the reporting by type rather then by state and year. Panhandle would revise the instructions to report taxes prepaid and charged by type only and eliminate the excessive detail of reporting by type of tax, by state, and by year. The Commission does not agree that reporting by type of tax, by state and by year is excessive detail. Rather, it is essential to the Commission in determining the yearly effects of federal and local taxes on the costs of pipeline operations. To only report the type of tax without any breakdown by year or local jurisdiction would render the information practically useless for analysis or analytical purposes. The Commission will permit the grouping of items under $250,000. Investment Tax Credits Generated and Utilized--Pages 264 and 265. The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports this deletion. But the APGA would retain this schedule because the information has vestigial value about changes in a pipeline's business. The Commission does not believe that vestigial value supports the burden of reporting this information. Accumulated Deferred Investment Tax Credits (Account 253)--Pages 266 and 267 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports deleting this schedule. But the APGA would retain this schedule because the information has vestigial value about changes in a pipeline's business. The Commission does not believe that vestigial value supports the burden of reporting this information. Miscellaneous Current and Accrued Liabilities (Account 242)--Page 268 The Commission is raising the reporting threshold for minor items from $100,000 to $250,000. INGAA supports this revision. Transco, however, would raise the threshold to $500,000. The Commission believes that $250,000 is the appropriate threshold level for this information. Other Deferred Credits (Account 253)--Page 269 The Commission is raising the reporting threshold for minor items from $100,000 to $250,000 and is deleting instruction 4 as not needed for Commission regulatory purposes in that it refers to undelivered gas obligations to customers under take-or-pay clauses in sales agreements. INGAA supports above-described revisions and would delete ``Contra account,'' col. (c), as would Columbia. Panhandle would raise the threshold to $1,000,000. Transco would raise it to $500,000. The Commission will not delete column (d) because it provides useful information and the Commission believes that $250,000 is the appropriate threshold level for this information. Undelivered Gas Obligations Under Sales Agreements--Pages 270 and 271 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports deleting this schedule. But the APGA would retain it because it has vestigial value about changes in a pipeline's business. The Commission does not believe that vestigial value supports the burden of reporting this information. Accumulated Deferred Income Taxes--Accelerated Amortization Property (Account 281)--Pages 272 and 273 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports deleting this schedule. But the APGA would retain it because it has vestigial value about changes in a pipeline's business. The Commission does not believe that vestigial value supports the burden of reporting this information. Accumulated Deferred Income Taxes--Other Property (Account 283)--Pages 276 and 277 The Commission proposed no change to this schedule. INGAA would make the format consistent with pages 274 and 275. In the Form No. 2 appendix in the final rule, the two schedules will be consistent. Other Regulatory Liabilities (Account 254)--Page 278 The Commission is raising the reporting threshold for minor items from $50,000 to $250,000 as suggested INGAA, rather than to $100,000 as proposed in the NOPR. The Commission is correcting a typographical error and, as suggested by INGAA and Columbia, is adding a beginning balance field. INGAA would delete ``Contra account'' col. (b). Panhandle would raise the threshold to $1,000,000. Transco would raise it to $500,000. The Commission will not delete column (b) ((now (c)) because it provides useful information needed for regulatory purposes. In addition, the Commission believes the $250,000 threshold is the appropriate threshold for this information. Gas Operating Revenues (Account 400)--Pages 300 and 301 The Commission is adopting substantial and significant changes to this schedule. The changes are: (1) The elimination of instruction 1's reference to manufactured gas revenues; (2) the deletion of instruction 2 defining natural gas; (3) the deletion of instruction 3 and present columns (f) and (g) concerning average number of natural gas customers per month; (4) the deletion of instruction 4 with respect to Mcf and therms; (5) the revision of instruction 5 to eliminate the reference to columns (c), (e), and (g); (6) the deletion of instruction 6 concerning commercial and industrial sales; (7) the revision of instruction 7 to read, on page 108, include information on major changes during year, new service, and important rate increases or decreases;'' (8) the addition of new instruction 2 to provide that revenues for transition costs include transition costs from upstream pipelines;57 (9) the addition of new instruction 3 to provide that other revenues in columns (f) and (g) include reservation charges received by the pipeline plus usage charges less revenues reflected in columns (b) through (e);58 (10) the addition of a new instruction 6 with respect to reporting the revenue of bundled transportation and storage service as transportation service revenue; (11) the revising of operating revenues in columns (b) and (c) to revenues for transition costs and take-or-pay costs, (12) the deletion of lines 2-12 and 28-32, which provide for [[Page 53040]] the reporting of sales revenues; (13) the addition of lines to show separately gas sales revenues,59 and transportation revenues associated with gathering, transmission, and distribution facilities, and revenues from storage services; and (14) added columns for GRI and ACA revenues, other revenues, and total operating revenues and dekatherms of natural gas, each for the current reporting year and the previous year.60 \57\For example, Order No. 636 transition costs. \58\The respondent must include in columns (f) and (g) revenues for Accounts 480-495. \59\The proposed new sales line includes Accounts 480-84 which are now reported on lines 2-12. \60\Penalty revenues are to be reported on page 308, Other Gas Revenues. --------------------------------------------------------------------------- The Commission's main reason for adopting these changes is to recognize that pipelines now receive most of their revenues from transportation and not sales. Hence, the breakout of information by types of sales is not needed. The Commission is breaking out Account 489 into four new accounts (Accounts 489.1--489.5) as discussed above. INGAA maintains that gathering quantities should not be included in total throughput columns (l) and (m), because they may also be reported as transmission. It seeks clarification whether dekatherms are to be reported in millions. It seeks clarification that ``other'' revenues includes only the pipeline's transition or take or pay costs and not those of upstream pipelines. It seeks clarification that GSR costs included in interruptible rates need not be reported separately. Commission response: The Commission has not provided for totals in the dekatherm columns to avoid double counting. Dekatherms are to be reported in units rather than in millions. As stated above, upstream pipeline transition and take-or-pay costs are to be included in revenues in columns (b) and (c). Last the allocated portion of GSR costs for interruptible rates should be included in columns (b) and (c) and not separately reported. AGD maintains that the Commission should require pipelines to show revenues by month to avoid standard data requests in rate cases for that information. The Commission concludes that such reporting would be unduly burdensome because it is too detailed for reporting purposes. Revenues from Transportation of Gas of Others Through Gathering Facilities (Account 489.1) and Dth Gathered--Pages 302 and 303 The Commission is replacing the schedule ``Distribution Type Sales by States'' with several new schedules. The current schedule, which reflects residential, commercial, and industrial revenues and volumes by state is no longer needed for Commission regulatory purposes because with unbundling those sales are now unbundled and occur in the production area rather than in the market area. In response to the comments,61 the Commission is combining into a single schedule the NOPR's proposed schedules on pages 302-304 and 312(b) and 313(b) to eliminate redundant reporting. However, the Commission is not, as suggested by some commenters,62 combining these proposed schedules and the schedule on pages 300-301 into a single schedule. The Commission believes it convenient for gathering, transportation, and storage data to be reported on their own schedules. \61\E.g., Columbia. \62\E.g., INGAA. --------------------------------------------------------------------------- The Commission does not agree with Panhandle and ANR that these should only be one schedule with only summary totals.63 Such limited information is not adequate for regulatory purposes. \63\CNG maintains that dekatherm does not equal throughput. Dekatherms is an appropriate and recognized way to measure deliveries even though it does not measure volumes. Most pipelines' rates are based on dekatherms. --------------------------------------------------------------------------- In the new Revenues from Transportation of Gas of Others Through Gathering Facilities Schedule, the pipeline will have to report its revenues by zone of receipt and by rate schedule.64 The pipeline would have to report for both the current and previous year its revenues for transition costs and take-or-pay costs, revenues for GRI and ACA, other revenues,65 and total operating revenues, and its Dth of gas delivered.66 The Commission believes that this schedule will provide the information needed with respect to gathering to obtain a good description of the pipeline's activities in the unbundled environment. \64\If a pipeline has no rate schedule, it should report by rate. \65\Other revenues include reservation charges received by the pipelines plus usage charges, less revenues reflected in columns (b) through (e). \66\As suggested by INGAA, the Commission has eliminated duplicative column (a). --------------------------------------------------------------------------- The Commission has deviated from the NOPR by requiring reporting by zone of receipt and by rate schedule rather than by state of delivery, by customer, by rate as in the NOPR's proposed gathering schedules. The Commission believes that reporting by zone of receipt and by rate schedule will provide the appropriate information needed for regulatory purposes without undue burden on the pipeline industry. The Commission does not believe that such customer information is necessary outside of the context of a rate proceeding. The Commission believes that it has thus addressed INGAA's concernabout providing customer data and its concern that pipelines may not know the exact delivery point from a multi-point contract, and will have to make an arbitrary allocation to a state. The Commission will discuss further here only those comments specific to gathering. Comments applicable to gathering and also to other services will be addressed below in the discussion of the transportation schedule. Columbia maintains that gathering revenues should be reported by state of receipt into the system. As stated above, the Commission is requiring reporting by zone of receipt into the pipeline's system. Revenues from Transportation of Gas of Others Through Transmission Facilities (Account 489.2)--Pages 304 and 305 In the new Revenues from Transportation of Gas of Others Through Transmission Facilities and Dth Transported Schedule, the pipeline would have to report its revenues by zone of delivery and by rate schedule. The pipeline would have to report for both the current and previous year its revenues for transition costs, and take-or-pay costs, revenues for GRI and ACA, other revenues,67 and total operating revenues, and its Dth of gas delivered. The Commission believes that this reporting reflects the current unbundled environment's emphasis on transportation for others. \67\Other revenues include reservation charges received by the pipeline plus usage charges, less revenues reflected in columns (b) through (e). --------------------------------------------------------------------------- The Commission has deviated from the NOPR by requiring reporting by zone of delivery and by rate schedule rather than by state of delivery by customer and by rate schedule as in the NOPR's proposed transportation schedules. The Commission believes that reporting by zone of delivery and by rate schedule will provide the appropriate information needed for regulatory purposes without undue burden on the pipeline industry. The Commission does not believe that such customer information is necessary outside of the context of a rate proceeding. The Commission believes that it has thus addressed INGAA's concern about providing customer data, including its concern about the difficulty of complying with the NOPR's customer-data requirement for some pipelines. The Commission also observes, as did INGAA, that Form EIA-176 collects state information which, in any event, is not of use to the [[Page 53041]] Commission. The Commission further observes that both the NGSA and AGD support reporting by zones.68 \68\As suggested by Transco, the Commission has deleted the requirement that revenues be reported in millions. --------------------------------------------------------------------------- INGAA also submits that transportation quantities appear to require gathering quantities to be included in transportation totals and since gathering system quantities will already be included in transmission deliveries, gathering should not be added to other quantities. CNG also maintains that gathering is included in transportation. As clarified with respect to pages 300 and 301, these quantities are not totalled to avoid double counting. The Commission has not expanded the coverage of the schedules as proposed by some commenters. NGSA maintains that reporting should be by customer type, with MDQ levels, demand and commodity volumes, discount information, and base and surcharge revenues. AGD submits that revenues and volumes reporting should be reported by rate schedule by zone of delivery (not state), and should include with short-term firm transportation. APGA enthusiastically supports pages 312 and 313, especially transportation throughput as solely needed. It would add details on contracts of less than one year as well as contracts of one year and longer (revenues and volumes). DOE maintains that the Commission should require the pipelines to provide a menu of service categories;69 an additional field to denote type of customer, along with standardized customer numbers; mileage information; and totals by state and by type of service. \69\E.g., short-term firm transportation and released firm transportation. --------------------------------------------------------------------------- The Commission believes the above suggestions would be unduly burdensome in light of the limited use of the information for regulatory purposes. Revenues from Storing of Gas of Others (Account 489.4)--Pages 306 and 307 In the new Revenues from Storing of Gas of Others schedule, the pipeline would have to report its revenues and Dth of gas withdrawn from storage by rate schedule. The pipeline would have to report for both the current and previous year its revenues from transition costs and take-or-pay costs, revenues from GRI and ACA, other revenues,70 and total operating revenues, and the Dth withdrawn from storage. \70\Other revenues include reservation charges deliverability charges, injection and withdrawal charges, less revenues reflected in columns (b) through (e). --------------------------------------------------------------------------- The Commission believes that this schedule will provide the information needed with respect to unbundled storage to obtain a good description of the pipeline's activities in the unbundled environment. The Commission has deviated from the NOPR by requiring reporting by rate schedule rather than by rate schedule by customer as on the NOPR's proposed schedules. The Commission believes that reporting by rate schedule will provide the appropriate information needed for regulatory purposes without undue burden. INGAA contends that storage revenues are not tied to withdrawals and Columbia asks why storage injections as well as storage withdrawals are not included. The Commission is not tying the reporting of storage revenues by withdrawals. Rather, all revenues received for storage during the reporting year must be reported. The Commission has required Dth reporting by withdrawals because withdrawal completes the storage cycle and such information should be adequate for regulatory purposes. The Commission rejects Columbia's contention that small customers (less than 1 million Dth) should be combinedbecause this would limit the reporting of meaningful information. Residential and Commercial Space Heating Customers and Interruptible, Off-Peak, and Firm Sales to Distribution System Industrial Customers-- Page 305 The Commission is deleting this page because it is not needed for Commission regulatory purposes. INGAA supports deleting this page. But the APGA would retain it because it has vestigial value about changes in a pipeline's business. The Commission does not believe that vestigial value supports the burden of reporting this information. Other Gas Revenues (Account 495)--Page 308 The Commission is adopting new schedule ``Other Gas Revenues (Account 495)'' for the reporting of a variety of other gas revenues, such as revenues from dehydration and gains on settlements of imbalances. The Commission is not requiring the reporting of revenues from associated companies as proposed in the NOPR. The Commission is requiring the reporting of penalty revenues on the schedule and is requiring the separate reporting of revenues from cash-out penalties. The Commission has adopted a threshold of $250,000 for each transaction. This is lieu of the $1,000,000 threshold suggested by Columbia, which will exclude meaningful data. As suggested by INGAA and by Columbia, the pipelines need not report the customer names with respect to the transactions. NGSA maintains that base and surcharge revenues should be separately stated. The Commission sees no need for base and surcharge revenues for these transactions to be separately reported, and so will not adopt NGSA's suggestion. Sales of Natural Gas--Pages 306 Through 309 The Commission is deleting this schedule, entitled ``Field and Main Line Industrial Sales of Natural Gas,'' and is not adopting the sales of natural gas schedule proposed in the NOPR. The Commission is so acting because the proposed schedule would have released proprietary information (customer names as maintained by INGAA). Sales for Resale--Natural Gas (Account 483)--Pages 310 and 311 The Commission is deleting this schedule because the level of detail reported is not needed for Commission regulatory purposes. INGAA supports the deletion of these pages. Sales of Products Extracted From Natural Gas (Account 490)--Page 315 The Commission is deleting this schedule because the level of detail reported is not needed for Commission regulatory purposes. Revenues From Natural Gas Processed by Others (Account 491)--Page 315 The Commission is deleting this page, as suggested by INGAA, because the level of detail reported is not needed for Commission regulatory purposes. Gas Operations and Maintenance Expenses--Pages 317-325 No changes were proposed to this schedule. However, the Commission is adding instruction 2 that requires respondents provide in footnotes the source of the index used to determine the price of gas supplied by shippers as reflected on line 75 on page 319. In addition, the Commission is inserting on line 66 the heading ``D--Other Gas Supply Expense.'' Further, consistent with our discussion of the revision of page 322 of Form No. 2-A, the Commission will revise line 145 to read ``Total Maintenance (Total of lines 136 through 144)''. Last, the Commission, as suggested by Panhandle, is deleting the section [[Page 53042]] entitled ``Number of Gas Department Employees'', because it is irrelevant to the reporting of the distribution of salaries and wages. Exploration and Development Expenses (Accounts 795, 796, 798) (Except Abandoned Leases, Account 797)--Page 326 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports deletion of this schedule. Abandoned Leases (Account 797)--Page 326 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports deletion of this schedule. Gas Purchases (Accounts 800, 800.1, 803, 804, 804.1 805, 805.1)--Page 327 The Commission is deleting this schedule and is not adopting the NOPR's proposed Gas Receipts schedule. Those schedules are not needed for Commission regulatory purposes and needed information is reported elsewhere in Form No. 2 (pages 317 and 520 and 521). Exchange and Imbalance Transactions--Page 328 The Commission is revising this schedule differently from the revision proposed in the NOPR. This schedule (on one page only) will require details concerning gas quantities and related dollar amounts of net annual imbalances by zone and rate schedule. Unlike the NOPR proposal, the Commission is not requiring reporting by customer or transaction or by point of receipt or delivery. This will ease the burden on the pipelines and the schedule will still garner useful data. However, the Commission is retaining the threshold of 100,000 Dth for the grouping of minor transactions, rather than increasing the threshold to 1,000,000 Dth as proposed by INGAA, because the 100,000 Dth level provides more meaningful information. Gas Used In Utility Operations--Page 331 The Commission is striking ``Credit (Accounts 810, 811, 812)'' from the title, is replacing Mcf with Dth, and deleting part of Instruction 1 and all of instructions 2, 3 and 5 concerning the definition of natural gas and Mcf reporting. INGAA supports the above-described revisions. Transmission and Compression of Gas By Others (Account 858)--Pages 332 and 333 The Commission is replacing Mcf with Dth, deleting current columns (b)-(f), and requiring the reporting of Dth of gas delivered in new column (b). This will eliminate the reporting of the distance gas is transported and revenue information. The continuation page 333 is deleted. INGAA supports the above-describe revisions. Other Gas Supply Expenses (Account 813)--Page 334 The Commission is requiring that respondents report maintenance expenses, the revaluation of monthly encroachments recorded in Accounts 117.4, losses on settlements of imbalances and gas losses not associated with storage, separately. In addition, individual items of $250,000 or more are to be listed separately. The NOPR proposed a threshold of $25,000, but, as INGAA maintains, this would lead to the unnecessary reporting of detail. Miscellaneous General Expenses (Account 930.2) (Gas)--Page 335 The Commission is dividing Line No. 2 (Experimental and general research expenses) into (a) Gas Research Institute (GRI) expenses and (b) other expenses. In addition, the Commission is raising the thresholds from $5,000 to $250,000, rather than the $25,000 threshold proposed by the NOPR. INGAA supports the above-described changes, but would delete the requirement that the number of items grouped be shown because this instruction adds no value to the report. The Commission disagrees with the comment that reporting the number of items grouped adds no value to the report. This number puts the grouped item into perspective and facilitates analysis. Therefore, the instruction to report the number of items grouped will remain as part of line 4. Depreciation, Depletion, and Amortization of Gas Plant (Accounts 403, 404.1, 404.2, 404.3, 405) (Except Amortization of Acquisition Adjustment)--Pages 336 and 337 The Commission is deleting instruction 2 to report information called for in Section B every fifth year after 1974 and is inserting the words `` and amortizable'' in the first line of new instruction 2 after the word ``depreciable.'' INGAA supports the above-described revisions. It states that instruction No. 2 should be corrected by inserting ``Section B.'' The Commission has made that correction. Depreciation, Depletion, and Amortization of Gas Plant (Continued)-- Page 338 The Commission is revising the headings to column (b) to read ``Plant Base (thousands)'' and column (c) to read ``Applied Depreciation or Amortization Rates (Percent).'' INGAA supports this revision. Income From Utility Plant Leased to Others (Account 412 and 413)--Page 339 The Commission is deleting this schedule because the information will be reported on page 213. INGAA supports the deletion of this schedule. Particulars Concerning Certain Income Reductions and Interest Charges Accounts--Page 340 The Commission is raising the threshold for the grouping of items from $10,000 to $250,000, as opposed to the $25,000 threshold proposed by the NOPR. Regulatory Commission Expenses (Account 428)--Pages 350 and 351 The Commission is changing the account number reference in the headings to columns (e), (i) and (l) from 186 to 182.3, and replacing instruction 4 on page 351, which references Account No. 186, with ``4. Identify separately all annual charge adjustments (ACA).'' In addition, the Commission is raising the threshold for minor items from $25,000 to $250,000, as opposed to the $50,000 threshold proposed by the NOPR. Columbia would delete columns (e) through (l) because they contain redundant information that offer little benefit or useful information. The Commission disagrees with Columbia. The information reported in these columns enables the Commission staff to obtain a more complete picture of the amounts and types of regulatory expenses that have been incurred during the year, as well as information on the amounts amortized from prior years. Research, Development, and Demonstration Activities--Pages 352 and 353 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports the deletion of this schedule. [[Page 53043]] Distribution of Salaries and Wages--Page 354 The Commission proposed no change to this schedule. INGAA and Columbia maintain that his schedule should be deleted because the information reported is required only for NGA section (4) rate filings. The Commission is retaining this schedule because it provides useful information for regulatory purposes, including use in evaluating rate filings under NGA section 4(e). Charges for Outside Professional and Consultative Services--Page 357 The Commission is raising the threshold from $25,000 to $250,000, as suggested by INGAA and Panhandle, as opposed to the $50,000 threshold proposed by the NOPR, is deleting the requirement for the consultant's address, and is deleting other details about charges and contracts. The Commission is also adding columns (a) ``Description'' and (b) ``Amount (in dollars).'' INGAA would require only the consultant's name and related payment. Columbia would eliminate much of the information as it is in an NGA section 4(e) filing. The Commission believes it relevant for regulatory purposes to obtain the required information. If a respondent does not make such a filing, the Commission would not have this information. The APGA would retain the $25,000 threshold. The Commission believes the current threshold is too low in today's environment. Natural Gas Reserves and Land Acreage--Pages 500 and 501 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports the deletion of this schedule. Changes in Estimated Gas Reserves--Page 503 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports the deletion of this schedule. Changes in Estimated Hydrocarbon Reserves and Costs, and Net Realizable Value--Pages 504 and 505 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports the deletion of this schedule. Natural Gas Production and Gathering Statistics--Page 506 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports the deletion of this schedule. Products Extraction Operations--Natural Gas--Page 507 The Commission is deleting this schedule because, as INGAA observes, this information is similar to deleted pages 500-506. Compressor Stations--Pages 508 and 509 The Commission is replacing the reporting of number of employees in column (b) with a report of the number of compressor stations and the horsepower of each station and is redesignating the remaining columns. In addition, gas for compressor fuel would be reported by Dth rather than by Mcf. The Commission agrees with INGAA that reporting will be less burdensome and data will be more useful if pipelines report horsepower by compressor station, rather than by unit as proposed by the NOPR. AGD would require reporting certificated horsepower and available horsepower at the end of the period, if different. The Commission has not previously required the reporting of available horsepower in Form No. 2. If a pipeline cannot operate at its certificated horsepower, it should file to amend its certificated horsepower to whatever level it has currently available. Gas and Oil Wells--Page 510 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports the deletion of this schedule. Field and Storage Lines--Page 511 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports the deletion of this schedule. Gas Storage Projects--Pages 512 and 513 The Commission is not deleting page 512 or substantially revising page 513 as proposed in the NOPR because the Commission is deleting Form No. 8 with respect to storage. The Commission is retaining the information required by this schedule about storage operations for gas delivered to storage, gas withdrawn from storage with regard to respondent's gas, and gas belonging to others, as well as information about particular operations (page 513). INGAA supports the above-described revisions. AGD would require reporting by field, not in the aggregate, with a showing of actual withdrawal capacity when full and when top gas is depleted (first and last day of deliveries) and corresponding injection capability at the same points. The Commission believes that by retaining this schedule in most part, the industry will be provided with adequate information. The reporting requirement on this page has always been in the aggregate and not by field or by account and is not a new requirement. AGD's suggestions would require the company to report in such detail that it would be extremely labor-intensive. Therefore, the Commission will not adopt the suggestion. Transmission Lines--Page 514 DOE suggests standardizing the method for describing or identifying the various transmission lines so that shippers will be able to reconcile information from various sources to arrange more efficiently for transportation service. DOE also suggests that each line should agree with the Form No. 567 map information. The Commission concludes that DOE's proposals would be unduly burdensome for Form No. 2 reporting in that they serve no regulatory purpose. Liquefied Petroleum Gas Operations--Pages 516 and 517 The Commission is deleting this schedule because it is not needed for Commission regulatory purposes. INGAA supports the deletion of this schedule. Transmission System Peak Deliveries--Page 518 The Commission is replacing Mcf with Dth and is requiring the reporting of deliveries of gas to interstate pipelines, deliveries to others, and of total deliveries. The Commission also is deleting the information with respect to the second and third highest peak day deliveries and the section, Highest Month's System Deliveries. Single peak day and consecutive three-day peak deliveries will be reported by various services and activities. The differentiation between jurisdictional and non-jurisdictional deliveries will be eliminated as no longer pertinent with unbundling. The Commission is adding lines with respect to no-notice transportation and storage services. INGAA maintains that this amount of detail on peak day deliveries proposed by the NOPR is not justified. It submits that pipelines should report only single [[Page 53044]] peak and consecutive 3-day peak for total system deliveries. The Commission has reduced the reporting to firm, interruptible, and other to reduce the burden and retain adequate information for regulatory purposes. DOE proposes that short-term firm transportation and released firm transportation be reported because they merit monitoring as important alternatives to interruptible service. The Commission does not currently require this information to be reported in Form No. 2, and to do so would unduly increase the reporting burden on pipelines. In addition, the deliveries on peak days may not be representative of released and short-term transportation service on a pipeline. Auxiliary Peaking Facilities--Page 519 The Commission is replacing Mcf with Dth. INGAA supports this revision. Gas Account-Natural Gas--Page 520 The Commission is revising this schedule differently from the schedule proposed in the NOPR. The salient changes are the reporting of gas purchases and gas sales on single lines and the reporting of gas received and delivered according to the revisions to the Uniform System of Accounts adopted in this rule (e.g., Accounts 489.1-489.4). The revised schedule no longer requires the reporting of the information required by NOPR lines 7-13, as suggested by INGAA and Columbia. The Commission also is revising instruction 1 to exclude the reference to consideration of pressure bases in measuring Mcf of natural gas and is replacing Mcf with Dth in instruction 3 and column (c) on pages 520 and 521. INGAA recommends the inclusion of definitions for exchange gas received and delivered, and clarification that gathering sales and purchased volumes are not to be added to the totals. Columbia seeks clarification of the relationship between imbalances and other to pages 328 and 329. Exchange gas received or delivered should be reported in light of the Exchange Gas Transactions schedule, page 328. Gathering sales and purchased volumes should be added to totals because this is a balance sheet item for the year of activity and those volumes are needed to balance the gas account. Last, the lines for imbalances and other have been deleted. System Maps--Page 522 The Commission is clarifying the information to be shown on the maps and is eliminating the requirement that transmission lines be colored in red, if they are not otherwise clearly indicated. INGAA supports the above-described clarification and elimination. Panhandle would incorporate the System Flow Map from Form 567 into page 522 and eliminate Form 567 because the system flow Map provides a more detailed map. Columbia asks for clarification about incremental facilities. The Commission rejects Panhandle's request to substitute the System Flow Map because the Form No. 2 map provides useful information, such as geographical information, that is not shown on the System Flow Map. The Commission clarifies that only major incremental facilities should be shown on this map. Index--Pages 1-4 The Commission is revising the index to reflect the above changes. B. Revisions to Form No. 2-A At present, a Nonmajor natural gas company must submit Form No. 2- A. The respondent is required to submit designated pages reflecting data designed for Nonmajor natural gas companies in the Uniform Systems of Account. However, if the respondent maintains the ``Major'' designated accounts, it may substitute certain pages from Form No. 2. The Commission is requiring Nonmajor respondents to submit only Form No. 2 pages as their Form No. 2-A report. In addition, the Commission is replacing Mcf with Dth and revising the instructions, including CPA certification as discussed above for Form No. 2. A sample copy of the revised Form No. 2-A is attached as Appendix C. The revised Form No. 2-A will consist of instructions, identification, attestation, and list of schedules (pages i and ii and 1 and 2), the following pages from Form No. 2: 107, 110-122, 204-209, 212, 213, 219, 300, 301, 317-325, 520, 551, and the following pages from current Form No. 2-A as renumbered: 26 as 211, 16 as 232, 19 as 250, and 20 as 278. In addition, the Commission is revising the definition of Nonmajor as follows: ``Nonmajor means having annual gas sales or volume transactions exceeding 200,000 Dth in each of the three previous calendar years and not classified as `Major'.'' This comports with the changes to section 260.2 of the Commission's regulations to include the minimum filing threshold for filing Form No. 2-A and to state the minimum filing threshold on a dekatherm basis. INGAA supports the Commission's proposal to adopt, for Form No. 2-A reporting purposes, the use of Form No. 2 pages as proposed in the NOPR and the renumbering of Form No. 2-A pages. Freeport also agrees with the proposed change to 18 C.F.R. section 260.2 on who must file Form No. 2-A. INGAA submitted specific comments on the proposed Form No. 2-A pages. INGAA's comments for the proposed Form No. 2-A pages 110-111, 112-113, 114, 115-116, 120-121, 122-123, 212, 213, 300-301, 327 and 520-521 are identical to the comments it submitted for the proposed changes to the same Form No. 2 pages; therefore, there is no reason to repeat them here. For the reasons discussed in the changes to Form No. 2, the Commission will adopt, for those Form No. 2-A pages, the same changes that the Commission adopted in this final rule for Form No. 2. INGAA suggested the following revisions to the following proposed Form No. 2-A pages: Statement of Retained Earnings for the Year--Pages 118-119 INGAA agrees with the proposal to require reporting of current year and previous year data and to delete instruction 8. It suggests that, on NOPR page 118-a, line 38 (now 36) be corrected to read ``Balance-- End of year (Enter total of lines 1, 9, 15, 16, 22, 29, 36 and 37)''. The Commission agrees with INGAA's suggested change and will adopt it as modified, for line 36 page 118 of the Form No. 2-A. Gas Plant in Service--Pages 204-209 No changes were proposed to these pages. INGAA suggests that the pages be revised to indicate which lines are used for totals and that lines 114, 115 and 116 on page 209-a should be on page 209. The Commission agrees with INGAA's suggested change to indicate which lines are used for totals and will adopt the following modifications: (1) Line 5 will read ``TOTAL Intangible Plant''; (2) line 26 will read ``TOTAL Production and Gathering Plant''; (3) line 36 will read ``TOTAL Products Extraction Plant''; (4) line 37 will read ``TOTAL Natural Gas Production Plant''; (5) line 39 will read ``TOTAL Production Plant''; line 54 will read ``TOTAL Underground Storage Plant''; (6) line 65 will read ``TOTAL Other Storage Plant''; (7) line 75 will read ``TOTAL Base Load Liquefied Natural Gas, Terminating and Processing Plant''; (8) line 76 will read ``TOTAL Natural Gas Storage and Processing Plant''; (9) line 86 will read ``TOTAL Transmission Plant''; (10) line 102 will read ``TOTAL Distribution Plant''; (11) line 114 will read ``Subtotal''; (12) line 116 will read [[Page 53045]] ``TOTAL General Plant''; (13) line 117 will read ``Total (Accounts 101 and 106)''; (14) line 121 will read ``TOTAL Gas Plant in Service,'' and (15) various existing lines will be renumbered. With regard to INGAA's suggestion that lines 114-116 be moved to page 209, this problem will be solved when the Form No. 2-A is type-set for printing; accordingly these lines will actually appear on page 209 when the Form No. 2-A is printed for distribution. Gas Operation and Maintenance Expenses--Pages 320-325 No changes were proposed to these pages. INGAA suggests that the page 322 be revised to correct line 145 to read ``Total Maintenance (Enter Total of lines 136 through 144).'' The Commission agrees with INGAA's suggested change and will adopt it except for the Word ``Enter.'' In addition, the Commission has revised the instructions to the following pages. General Information on Plant and Operations--Page 211 The Commission has deleted instruction 3 which required the reporting of information related to the local distribution of natural or mixed gas at the retail level. Capital Stock Data--Page 250 The Commission has added a descriptive instruction and revised stylistically the existing instruction for this page. C. Revisions to Form No. 11 Natural gas pipelines are required to file with the Commission the FERC Form No. 11, which is a monthly statement setting forth certain volume, revenue, and expense data. The Commission is modifying Form No. 11 to accomplish three different purposes. First, the Commission is modifying Form No. 11 to reduce the reporting burden on the pipelines, since certain existing portions are no longer necessary. Second, Form No. 11 is being modified to reflect the reduced emphasis on sales service, and the greater emphasis on transportation and storage services. As explained in the NOPR, as a result of the restructuring of the interstate pipeline industry under Order No. 636, the pipeline's sales business is declining while the pipeline's transportation and storage business is increasing in relative importance. Much of Form No. 11 was geared towards the collection of sales-related data. Third, the Commission is modifying Form No. 11 to ensure that the data collected in the Form No. 11 and the Form No. 2, as revised, is more consistent. This consistency will improve the usefulness of the data collected by the Commission. In the NOPR, the Commission essentially proposed to: (a) Reduce the monthly reporting requirement to a semi-annual reporting of monthly data; (b) remove or consolidate certain portions of the Form No. 11; (c) collect the Form No. 11 data in the same general format as proposed in Form No. 2; and (d) make certain other miscellaneous changes throughout many parts of the Form. After reviewing the comments received on the Form No. 11 proposal, set forth below, the Commission is adopting a Form No. 11 that is significantly less burdensome in detail than that proposed in the NOPR.71 As discussed infra, the Commission is requiring that the simplified Form No. 11 monthly data be submitted quarterly, rather than semi-annually as proposed, or monthly, as it is currently filed. Thus, throughout the Form No. 11, we are changing the title of the Form No. 11 to ``Natural Gas Pipeline Company Quarterly Statement of Monthly Data.'' The Commission is also modifying Form No. 11 to substantially reduce the data collected by the form. For example, Form No. 11 will collect only data on volumes and revenues; we are eliminating the reporting of all expense data in the Form No. 11. \71\Revised Form No. 11 is attached as Appendix D. Appendix D is not being published in the Federal Register, but is available from the Commission's Public Reference Room and on the Commission's Gas Pipeline Data Bulletin Board System. --------------------------------------------------------------------------- 1. Comments KN suggests combining Form No. 11 with Form No. 2, while INGAA and CNG recommend eliminating Form No. 11. In support, INGAA and CNG argue the information is already collected in Form No. 2. Further, they argue that consolidating the monthly reports into two semi-annual reports does not reduce the reporting burden. INGAA states the annual industry reporting burden for a semi-annual Form No. 11 would be 6,600 hours, compared to the Commission's estimate of 920 hours. Finally, INGAA states that the semi-annual data would be filed too late to be used as industry indicators, and too incomplete to provide an adequate picture of pipeline operations or financial performance. Several commenters support the continuation of Form No. 11, but suggest changes to the proposed Form No. 11. Panhandle believes that the required level of preparatory effort would be reduced, without sacrificing the usefulness of the information, if the second semi- annual report was incorporated as part of the Form No. 2, and the information was compiled quarterly, rather than monthly. The Industrials oppose semi-annual filings, and urge the Commission to require monthly filing. They argue availability of this information on a monthly basis helps customers and others determine when and whether settlements on throughput or for interim rates are appropriate. NI-Gas, on the other hand, does not object to semi-annual filing, but urges continued reporting of monthly data (which is, in fact, what was proposed by the NOPR). NGSA recommends that the Form No. 11 reflect volumes and revenues by rate category used by the pipeline. Further, it would like revenues to be reported by rate schedule, month, and rate category, separately showing base rate revenue and revenue from each surcharge. DOE uses Form No. 11 data in several publications. It suggests that rate schedule information be enhanced with a description to indicate the different elements of service that are included. DOE suggests the following classifications: No-notice transportation Balancing Firm transportation Storage and transportation (firm) Storage and transportation (interruptible) Incremental Interruptible transportation Short-term transportation Released firm transportation Other The Industrials suggest a breakout by at least long-term firm (one- year or more), short-term firm (less than a year), and interruptible transportation; it states that the proposed requirement for reporting by rate schedule fails to capture short-term firm service. DOE also asserts the value of Form No. 11 data could be enhanced by the inclusion of common codes and standardization. The data in Form No. 11 should be easily accessible (and downloadable) on a friendly bulletin board system which provides access to the general user community. INGAA makes the following specific suggestions if the Commission chooses to retain Form No. 11:Make the reporting in Form No. 11 consistent with Form No. 2 by changing instructions to indicate that all storage service revenues should be reported on lines 15-17 and that withdrawal quantities related to those storage services also be included on those lines. [[Page 53046]] Remove language that indicates that injection and withdrawal revenues should be reported on lines 46 and 47. Eliminate requirements to provide breakouts of revenue and quantities for services to interstate pipelines. Correct the instruction for line 32 to refer to lines 30 and 31, not 22 and 23. Add an instruction for line 42 to require the reporting of the estimated total project cost of all of the projects that started construction during the reporting period that are estimated to individually cost at least $5,000,000. 2. Commission Ruling The Commission is sensitive to the concerns of the commenters that the proposed Form No. 11 filing requirement places a burden on the pipeline companies. Therefore, we have carefully reconsidered the need for the data in the Form No. 11. We will not accede to the pipelines' wish that the Form No. 11 be eliminated. We are adopting a requirement to file monthly data quarterly. However, we are substantially reducing the monthly data required by this form from the previous requirements and the requirements proposed in the NOPR. Proposed Parts III Income Data, IV Other Selected Data, and V Operation and Maintenance Expense, will be deleted. Part II Revenue Data is being retained. The information collected in Part II, Revenue Data, is the most fundamental information about the pipeline industry-- the amount of gas sold, transported, and stored. The Commission continues to need, and will make use of, this basic information to fulfill its responsibility to oversee the gas pipeline industry. Contrary to INGAA's assertion, the Form No. 11 and Form No. 2 data do differ. The Form No. 11 collects monthly data allowing aggregation of data for any 12-month period, while Form No. 2 collects data aggregated for a calendar year. The collection of monthly data will allow the Commission to follow developing trends on a pipeline's system. It will also permit observation of seasonal variation in throughput, something the Commission cannot do with the data filed in Form No. 2. This fundamental data makes it possible for the Commission to determine more accurately the effects of its policies and decisions on the pipeline industry. To make the data more timely, we will require the form to be submitted quarterly, rather than semi-annually, as proposed, and the data to be submitted within 45 days of the end of the calendar quarter. However, as noted, we will retain the requirement that monthly data be reported. In other words, monthly data will be reported quarterly. The request that data be filed monthly will be denied. The quarterly filing requirement ensures more accuracy in the data filed. It also balances the need for timely data against the burden of filing. Since the monthly character of the data is being retained, we will not combine Form No. 11 with Form No. 2. Several commenters ask that the data be reported under additional classifications or in more detail. The Commission will continue to require the data in Form No. 11 be reported on the same basis as in Form No. 2 to maintain consistency. DOE requests that we require the pipelines to list the nature of the service provided, e.g., no-notice transportation, firm transportation, balancing, etc. Many of the classifications requested can be determined by the rate schedule specified. The nature of the service provided under each rate schedule is reported in the tariff. The tariffs are available for downloading, together with the appropriate software, from the Commission's bulletin board system. The Commission will adopt the detailed revenue reporting requested by NGSA. The Form No. 2 separates revenues into a column for transition costs and take-or-pay, a column for GRI and ACA surcharges, and a column for other revenues (See Account No. 489). We adopt this structure for revenue reporting in Form No. 11. DOE's suggestion that the data be standardized has merit. The Commission wants the data from various sources to be interrelational. That is, the data from one source should be capable of being linked with data from another source. By providing for the linkage of data from different sources, the Commission can avoid duplicative reporting requirements. To enhance this capability, the instructions in the forms and reports will direct the respondent to report the rate schedule numbers the same way they are reported in all other submittals to the Commission. DOE also suggests the data be accessible and downloadable on a bulletin board system which provides access to the general user community. Since June 8, 1995, the Commission has made data filed electronically in the Form No. 11 available on its Gas Pipeline Data bulletin board (GPD) for download. The Commission will continue to disseminate the electronic Form No. 11 data in this manner. The specific changes in each section of the Form No. 11 are as follows: General Information and General Instructions General Information section I (Purpose) is revised to reflect the elimination of the collection of expense data as a purpose. General Information section II (Who Must Submit) is modified to exclude gas sold for resale from the calculation for determining which gas companies must submit the Form No. 11. It is also modified to change the requirement to comply to those gas companies whose gas transported or stored for a fee exceeded 50 million Dth in each of the three previous calendar years, rather than in only the previous calendar year, as the current Form No. 11 requires. General Information section III (When to Submit) is changed to require that the Form No. 11 be filed quarterly. This section also sets forth a reporting schedule. Each quarterly report is due 45 days after the end of the three-month period being reported. Currently, the monthly reports are due 40 days after the end of each month being reported. Finally, General Information section IV (What and Where to Submit) is changed to delete reference to the Commission's street address for the filing of the Form No. 11. General Instruction I is revised to require consistency between the data filed on Form No. 11, and the data filed with Form No. 2. It is the intent of the Commission to be able to compare the aggregation of twelve months of information submitted on the Form No. 11 with data filed on the Form No. 2. Comparisons with the Form No. 2 data may require aggregation of the Form No. 2 data as well. There is no change to General Instruction II, specifying the use of parentheses to indicate negative amounts. The Commission is adding a requirement to Instruction III to require that quantities in the Form No. 11 be reported in thousands of dekatherms. The change to dekatherms is consistent with the changes proposed to the Form No. 2. Revenues will continue to be reported in thousands of dollars, as currently required by instruction III. General Instruction IV, allowing for the use of footnotes in the Form No. 11, is modified to change the reference to the part number where the footnotes are listed from Part VI to Part III. General Instruction V, regarding estimated data, is removed. Since the average lag time between the month reported and the date the filing is made will be longer, the Commission anticipates that actual data will be readily available. Thus, estimated data [[Page 53047]] will not be necessary. General Instruction V is replaced with an instruction specifying that one Part II form must be reported for each month. Specific Instructions and Definitions The instruction for the item ``All'' is modified to specify that quantities must not be adjusted for discounts. We are adding specific instructions for items 7 through 12 and 15 through 17, to conform to the instructions contained in Form No. 2 for reporting transportation and storage services, and to clarify the reporting of storage revenues. In the NOPR, we proposed to make separate, specific instructions for items 15 through 17 for the reporting of storage revenues, which indicated that certain storage revenues were to be reported at those items, and other storage revenues were to be reported at items 46 and 47. In accordance with INGAA's suggestion, we are eliminating those specific instructions for items 15 through 17, and requiring all storage service revenues be reported at items 15 through 17, including the withdrawal quantities related to those storage services. In the NOPR, we proposed specific instructions for items 7 through 12 that required, among other things, that transportation delivered to a pipeline under a rate schedule be reported separately from transportation delivered to others under that rate schedule. INGAA asks us to eliminate this requirement to provide breakouts of revenue and quantities for services to interstate pipelines. A similar provision proposed in Form No. 2 is not being adopted. To retain consistency between the reporting of revenues in Form No. 2 and Form No. 11, we will not adopt the proposal in the NOPR. This action satisfies INGAA's request. Existing specific instructions for items 22, 24, 27 and 38 through 40 are deleted, since the Commission no longer proposes to collect information on these items, which are contained in Parts III and V, that are now being deleted. The remainder of INGAA's suggestions, regarding the Commission's proposed specific instruction for item 32, and the addition of an instruction for item 42 are no longer relevant given the elimination of the Form No. 11 reporting requirements in Parts III, IV, and V. All existing definitions in the Form relate to purchases or sales of natural gas. The Commission is simplifying the reporting of sales and purchase information; therefore, the definitions are removed as no longer necessary. Identification (Part I) and Revenue Data (Part II) Except for revising the instruction to read ``Period Reported'' instead of ``Month Being Reported,'' the Commission is leaving Part I intact. The Commission is modifying Part II, which relates primarily to sales service, to reflect the decreased emphasis on sales service, and increased emphasis on transportation and storage services subsequent to the implementation of Order No. 636. Specifically, Part II is modified to collect information for sales, transportation, gathering, storage and other revenue categories in the same way it is proposed to be collected in the Form No. 2, but on a monthly basis rather than annually. Income Data (Part III), Other Selected Data (Part IV), and Operation and Maintenance Expense (Part V) The Commission is eliminating Parts III, IV, and V of the Form No. 11. The information required to be reported under these Parts is no longer necessary for the Commission's regulatory review purposes. D. Other Revisions Section 260.1 requires that major natural gas companies, as defined in part 201 of the Commission's regulations, file with the Commission an annual report, designated as FERC Form No. 2. The Commission is modifying section 260.1 to reflect in the text of the regulations the new definition of ``major company'' (a natural gas company whose combined gas transported or stored for a fee exceeded 50 million Dth in each of the three previous calendar years). The Commission is also specifying in section 260.1 that newly established entities must use projected data to determine whether the Form No. 2 must be filed, and that the Form No. 2 must be filed electronically. In addition, the Commission is revising section 260.1 to delete reference to an effective date, and to remove references to reporting requirements pre- dating December 30, 1988. Section 260.2 requires that nonmajor natural gas companies file an annual report, designated as FERC Form No. 2-A. The Commission is modifying section 260.2 to specifically define who must file the Form No. 2-A. Section 260.2 is revised to state that those natural gas companies required to file the Form No. 2-A are companies not meeting the filing threshold for Form No. 2, but having total gas sales or volume transactions exceeding 200,000 Dth in each of the three previous calendar years. The Commission is also specifying in section 260.2 that newly established entities must use projected data to determine whether the Form No. 2-A must be filed, and that the Form No. 2-A must be filed electronically. In addition, the Commission is revising section 260.2 to delete reference to an effective date, and to remove references to reporting requirements pre-dating December 30, 1988. These latter changes mirror the changes set forth in section 260.1 governing the FERC Form No. 2. Section 260.3 requires that natural gas companies file with the Commission a monthly statement--the FERC Form No. 11--containing information concerning selected revenues, income statements, and other items, and details of operation and maintenance expenses. The Commission is modifying the title and paragraph (a) of section 260.3 to reflect the change of the Form No. 11 to a quarterly statement of monthly data, that no longer collects expense data. In paragraph (b), the Commission is redefining who must file the Form No. 11 (natural gas companies whose gas transported or stored for a fee exceeded 50 million Dth in the previous three calendar years), and is specifying that the form be filed electronically. Further, the Commission is revising paragraph (c) prescribing when to file the Form No. 11 to reflect the quarterly filing schedule set forth in the Form No. 11 itself. In addition, the Commission is removing references to dates that have long since passed, and references to reporting requirements pre-dating November 30, 1988. Section 260.4 requires that importers and exporters of natural gas file with the Commission an annual report, FPC Form No. 14. Section 260.11 requires natural gas companies operating an underground natural gas storage field to file with the Commission a monthly underground gas storage report, Form No. 8. In the NOPR, the Commission did not propose any substantive changes to these sections. Instead, the Commission sought comments on whether the collection of the information contained in these forms by other governmental or private sources is currently adequate, making the collection of the same information in these Commission forms unnecessary. INGAA, American Forest, KN, and ANR/CIG recommend the elimination of FPC Form No. 14. American Forest and INGAA note that DOE's Office of Fossil Energy collects periodic reports on export and import activity as part of its oversight responsibility. They state that these reports collect substantially the same information as required by Form No. 14. According to INGAA, the elimination of this form would reduce [[Page 53048]] the burden on respondents by about 1,100 hours per year. ANR/CIG concurs that this data is collected elsewhere. The Commission will eliminate the requirement for filing FPC Form No. 14 from its regulations. The Commission's primary need for natural gas import and export information is related to its administration of Presidential Permits for import and export facilities under Executive Order No. 10485. While we need certain capacity and usage information to authorize facilities and verify the approved capacity of such natural gas import and export facilities, the Commission does not generally need information on the purchasers or prices of imported and exported natural gas and LNG. Thus, the Commission expects that it will have adequate data on natural gas imports and exports through any continuing collection of import-export data that DOE/EIA may pursue, DOE/Fossil Energy's (FE) Quarterly Reports, or data requests in specific case processing or litigation.\72\ Although the DOE/FE Quarterly Reports and Form No. 14 have different data items, it is true, as INGAA and American Forest state, that most of the substantive information is duplicative. \72\To the extent DOE/EIA continues to require the Annual Report for Importers and Exporters it will have to pursue separate OMB clearance for this data collection on its own. --------------------------------------------------------------------------- The Commission's Staff will consult in more detail with DOE/EIA and DOE/FE on maintaining an ongoing, non-duplicative collection of import- export data by DOE, such as peak-day usage, differentiation of multiple operators at singularly named import-export points, and the BTU content of natural gas and LNG. Section 260.4, prescribing the Form No. 14, is deleted from the regulations. With respect to the Form No. 8, ANR/CIG, INGAA, KN, DOE, and El Paso support its elimination. They argue this information is collected elsewhere. Specifically, DOE notes that it collects monthly injection and withdrawal data from all companies operating storage fields, including those who file Form No. 8, in its ``Underground Gas Storage Report,'' Form EIA-191. DOE states that the Form EIA-191 is a more comprehensive form than the Form No. 8, and collects the data that the Commission requires to monitor jurisdictional companies. Thus, DOE maintains that the Commission would no longer need Form No. 8 if it used the data from Form EIA-191. However, DOE points out that, currently, the data submitted in Form EIA-191 are considered confidential. If the Commission agrees with DOE's proposal to use Form EIA-191, DOE states that it will submit Form EIA-191 to the Office of Management and Budget for clearance to remove the confidentiality requirements. DOE notes that a recent attempt to do so in 1991 did not succeed. However, DOE believes that pipelines' concerns voiced at the time may have since decreased with the implementation of Order No. 636, as many companies have provided copies of their Form EIA-191 filings to the trade press. DOE states that upon OMB's approval for the removal of the confidentiality requirements, EIA will continue to process the EIA- 191, and will make the data available to the Commission on a timely basis. INGAA concurs that there is no regulatory reason for both DOE and the Commission to spend taxpayer dollars for duplicate reporting. INGAA states that gas storage data is reported in the monthly Form EIA-191 and the semi-annual storage reports under existing sections 284.106(g) and 284.223(d)(5), and that weekly estimates of working gas in storage are available by region through the ``American Gas Storage Survey'' five days after the end of the reporting week. INGAA notes that elimination of Form No. 8 would reduce the industry reporting burden by 1,440 hours per year. El Paso also supports elimination of this form or, at least, elimination for those pipelines with facilities that are not operated as traditional underground storage facilities. For example, El Paso's Washington Ranch Storage Facility is operated exclusively as an adjunct to El Paso's transmission system for load balancing, line pack, and pressure control. El Paso argues that the Form No. 8 reporting requirements should not apply to this facility. The Commission will eliminate the requirement to file Form No. 8. One of the objectives of this rulemaking is to eliminate duplicative or unnecessary reporting requirements. DOE's proposal that the Commission use the information from Form EIA-191 furthers this goal. As a result of pipeline restructuring, the data from Form EIA-191 can typically be used to meet the Commission's requirements for storage data in lieu of the Form No. 8 information. Although we do not seek removal of the non- disclosure provisions from the Form EIA-191 data collection as a pre- condition to elimination of the Form No. 8, we endorse DOE's efforts to reach consensus with the Form EIA-191 respondent population on this issue. In the event that OMB does not approve DOE's request to remove the confidentiality provision from the Form EIA-191 data collection, we will not reinstate Form No. 8. For most purposes, aggregated data derived from Form EIA-191 should suffice. In the event specific pipeline storage data is required for a project or proceeding, and the Form EIA-191 data continues to be confidential, the Commission could obtain the company-specific Form EIA-191 data from DOE pursuant to the confidentiality provisions of this data collection. The Commission also reserves the right to seek whatever information is required through a data request in individual proceedings. Section 260.11, prescribing the Form No. 8, is deleted from the regulations. Section 260.9 requires every natural gas pipeline company to report to the Commission serious interruptions of service to any wholesale customer involving facilities operated under certificate authorization from the Commission. The Commission is modifying sections 260.9(b) and (e) to include facsimile transmission as an optional method for reporting interruptions of service. This recognizes advances in technology and current practice. Further, the Commission is modifying sections 260.9(b) and (c) to require that companies send telegrams, facsimile transmissions, or supplemental information to the Director, Division of Environmental and Engineering Review, Office of Pipeline Regulation, the successor to the Director, Division of Engineering, Market and Environmental Analysis, Office of Pipeline and Producer Regulation. The Commission is also deleting reference to the Commission's street address, and correcting the Commission's zipcode in section 260.9(b). Section 260.13 sets forth the requirements for the filing of the FERC Form No. 549-ST, Form of self-implementing transportation reports. The initial and subsequent reports currently filed by interstate and intrastate pipelines, Hinshaw companies, and local distribution companies undertaking transportation transactions under subparts B, C, or G of part 284 are required to be made on the FERC Form No. 549-ST. Because the Commission is eliminating the requirements of filing initial and subsequent reports for companies subject to the requirements of subparts B, C, and G of part 284, as further described below, the FERC Form No. 549-ST is no longer necessary. Accordingly, the Commission is removing section 260.13. Section 260.15 requires that natural gas companies making direct sales in [[Page 53049]] interstate commerce of natural gas to customers consuming such gas file a Report of Alternate Fuel Demand Due to Natural Gas Curtailment, FPC Form No. 69. As noted in the footnote to section 260.15, Form No. 69 was discontinued and replaced with Form No. EIA-50 by order issued June 23, 1978.\73\ The EIA Form No. 50 was eliminated in 1984 after the Office of Management and Budget (OMB) rejected the Energy Information Administration's (EIA) request for an extension of OMB approval of the data collection. Thus, it now appears that the footnote to 18 CFR 260.15 references a non-existent EIA form as a replacement for the Form No. 69. Since neither the Commission nor EIA has collected this data since 1984, and there has been no significant curtailment of natural gas in the nation for more than ten years, the Commission is removing section 260.15. \73\FERC Statutes and Regulations, Regulations Preambles, 1977-- 1981, para. 30,013 (1978). --------------------------------------------------------------------------- In addition, the Commission is changing all references in Part 260 from the ``FPC'' and the ``Federal Power Commission'' to the ``FERC,'' and ``Federal Energy Regulatory Commission,'' respectively. VII. Part 284 A. Introduction Under Part 284, the Commission is revising the reporting requirements, and/or certain non-reporting requirements, contained in Subparts A, B, C, E, G, J, and L. These subparts set forth general provisions and conditions (Subpart A), and govern the transportation of natural gas by interstate pipelines under section 311(a)(1) of the NGPA (Subpart B), the transportation of natural gas by intrastate pipelines under section 311(a)(2) of the NGPA (Subpart C), the assignment by any intrastate pipeline to any interstate pipeline or local distribution company of contractual rights to receive surplus natural gas under section 312 of the NGPA (Subpart E), the transportation of natural gas by interstate pipelines on behalf of others, and services by local distribution companies, under blanket certificates authorized by section 7(c) of the NGA (Subpart G), (General Provisions and Conditions), as well as the sale of natural gas under section 7(c) blanket certificates by interstate pipelines offering transportation service under subparts B or G (Subpart J), and by non-interstate pipeline sellers (Subpart L). There are six major categories of changes to the Part 284 provisions: (1) the removal of the initial full report, subsequent reports, annual report, and notification of termination, currently required under subparts B, G, and/or J; (2) the removal of the initial full report, subsequent reports, and notification of termination required under subpart C; (3) the refinement of the Commission's discount reporting requirement; (4) the addition of a new reporting requirement under subparts B and G, an electronic Index of Customers; (5) the elimination as obsolete of certain non-reporting provisions in subparts A, B, C, and G, setting forth interim measures related to the implementation of Order Nos. 436 and 636; and (6) other changes that either are grammatical in nature, remove references to deadlines that have long since passed or other outdated requirements, or reflect the use of current, more accurate, terminology. These revisions are discussed more fully below. B. Removal of Initial, Subsequent, Annual, and Termination Reports Under Subparts B, G, and J In light of all of the broad changes that are being required in this rule, and the changes to the industry brought about by Order No. 636, it is no longer necessary to require interstate pipelines to provide the detailed reporting set forth under the initial, subsequent, termination, and annual reports in sections 284.106 and 284.223. We have determined that the information included in these reports is no longer required for our regulatory review of the natural gas industry. Accordingly, the Commission is removing paragraphs (a), (b), (c), and (d) of section 284.106, and paragraph (d) of section 284.223, to delete the requirements that interstate pipelines file the initial full report, subsequent reports, notification of termination, and annual report. The Commission is also removing sections 284.106(e) and 284.223(b) relating to the fees accompanying the initial full report, and sections 284.106(f) and 284.223(c), prescribing the use of FERC Form No. 549-ST for the initial and subsequent reports, since they would no longer apply due to the discontinuance of the associated reporting requirements. However, the Commission will retain the requirement in section 284.106(a)(4) that an interstate pipeline file a statement with the Commission that the pipeline has provided notification of bypass of a local distribution company (LDC) to the LDC and the LDC's regulatory agency. The Commission will also retain the semi-annual storage reports currently required under sections 284.106(g) and 284.223(d)(5). Because sections 284.106 and 284.223 will require identical reporting requirements, the Commission is removing all of the filing requirements from section 284.223(d), and substituting a statement that all pipelines transporting gas under section 284.223 of Subpart G must comply with the reporting requirements specified under section 284.106 of Subpart B. There is no reason to specify the same exact reporting requirements twice in the regulations. In the NOPR, the Commission proposed to remove the annual sales report required under section 284.288 of Subpart J, applicable to pipelines that engage in sales under a blanket certificate and also offer interstate transportation under subparts B and G. The Commission proposed to remove this reporting requirement to eliminate duplicative reporting requirements, because most of the information was also being collected under the proposed Form No. 2. However, the Form No. 2 that is being adopted in this final rule no longer captures transaction- specific volume and revenue data that the section 284.288 sales report collects. Therefore, the Commission is retaining this sales report.74 \74\See Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation; and Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, III FERC Stats. & Regs. Preambles para. 30,939 at p. 30,443 (April 8, 1992) (Order No. 636), order on reh'g, III Stats. & Regs. Preambles para. 30,950 at p. 30,624 (August 3, 1992) (Order No. 636-A), for the Commission's rationale for collecting this information. --------------------------------------------------------------------------- These changes are the same changes proposed in the NOPR. Our proposed deletion of these reporting requirements received strong support by the commenters. INGAA, Texas Gas, KN, Columbia, and NI-Gas support the elimination of the initial, subsequent, termination, and annual reports under subparts B, G, and J without reservation. Other parties offered conditional support. American Paper supports the proposed modifications to subparts B and G in light of the other proposals made by the Commission in the NOPR, including the requirement that pipelines maintain and update an Index of Customers and file discount rate reports. Similarly, APGA supports the elimination of these reports provided that the Commission adopts section 154.1 requiring pipelines to file contracts with the Commission when they differ from the form of service agreement. Columbia and SoCal express support for the removal of related section 260.13 requiring the initial and subsequent reports to be reported on the FERC Form No. 549-ST. SoCal's support is contingent upon the [[Page 53050]] Commission's adoption of the proposed discount rate report. APGA, SoCal, and NI-Gas support the retention of the requirement that a pipeline file a statement with the Commission that it has provided notification of bypass of an LDC to the LDC and the regulatory agency. Only our proposal to retain the two semi-annual storage reports required under sections 284.106(g) and 284.223(d)(5) generated requests for a different treatment. Texas Gas recommends the elimination of the semi-annual storage reports in light of the requirement to include information concerning firm storage service in the Index of Customers. INGAA suggests that the two semi-annual storage reports be combined into one annual storage report. INGAA states that this would provide the Commission with the data it needs while reducing the burden on the pipelines. As noted above, the Commission is retaining the semi-annual storage reporting requirement. We will not adopt Texas Gas' request for elimination. The Index of Customers adopted in this rule will collect very limited information concerning firm storage service, and will not collect many of the data elements required by the semi-annual storage report. Nor will we adopt INGAA's proposal that the storage report be filed annually rather than semi-annually. The semi-annual nature of the reports derives from the timing of the reports. The reports are submitted so that the withdrawal season is reported separately from the injection season. This is an important distinction which the Commission does not wish to eliminate. The Commission recognizes that some parties may withdraw their support for the elimination of the initial, subsequent, termination and annual reports, now that we have substantially modified the discount report and Index of Customers that were proposed. However, the proposed elimination of these reports was not solely dependent on the collection of the information elsewhere. As stated supra, the information in these reports is no longer needed for the Commission to carry out its regulatory responsibility. C. Removal of Initial, Subsequent, and Termination Reports Under Subpart C The Commission is deleting certain of the reporting requirements for intrastate pipelines transporting gas under NGPA section 311 under Subpart C. The Commission is eliminating the initial full report, subsequent reports, and notification of termination currently required under section 284.126. The Commission no longer finds these reports useful for regulatory review. In the NOPR, the Commission invited the parties to comment on our proposed removal of these reports. In response, KN, Transok, Enogex, Texas Intrastates, and NI-Gas filed comments supporting the elimination of the initial, subsequent, and termination reports required in section 284.126. While the Commission is eliminating the annual reporting requirement for interstate pipelines, as described, supra, the Commission will continue to require intrastate pipelines to file the annual report currently required by section 284.126(c), as well as the semi-annual storage reports required under section 284.126(g), and the notification of bypass requirement currently included in the initial report, section 284.126(a)(6). INGAA suggests that the annual report be eliminated so that the requirements for intrastate reporting will mirror the requirements for interstate reporting. However, unlike the interstate pipelines, intrastate pipelines are not subject to the full force of the federal reporting requirements. Intrastate pipelines do not file Form No. 2, an Index of Customers, or general rate cases under section 4 of the NGA. Thus, fewer opportunities are available to the Commission and the public to obtain information about the intrastate pipelines' jurisdictional activities. The participation of the intrastate pipelines in the interstate market should be accompanied by accountability. Therefore, the Commission is continuing to require the intrastate pipelines to submit the annual report. The Commission, though, is revising the annual report (now section 284.126(b)), as proposed in the NOPR, to reflect the fact that the transportation transactions are no longer docketed, and to require the specification of whether the transportation service is firm or interruptible. Until recently, intrastate pipelines only provided interruptible transportation service. Since they are now performing firm transportation service, firm and interruptible transactions must be separately identified for accurate reporting. Transok and the Texas Intrastates ask that the filing date for the annual report be changed from March 1 to March 31 to make it easier to gather the necessary information, and consistent with the due date for FERC Form No. 2-A. We will grant this request for an extension of the filing date from March 1 to March 31. This will lessen the burden in submitting this information. The Texas Intrastates argue that the requirement to file semi- annual storage reports (new section 284.126(c)) should be removed. They state that the Commission has no certificate jurisdiction over NGPA section 311 storage transactions by intrastate pipelines, and that the storage reporting requirement is duplicative because information on storage volumes is reported in the annual transportation report. Transok, also, supports eliminating the semi-annual storage reports, adding that the information is incomplete and not necessarily useful to the Commission because non-jurisdictional intrastate activity is not reported. Transok states that the DOE receives a complete report of aggregated intrastate and interstate storage activity each month through the Monthly Underground Gas Storage Report, Form EIA-191. Transok further argues that, in its case, the request for price information is moot because the Commission has approved market-based pricing for Transok's section 311 storage services. Similarly, Equitable urges the Commission to exempt intrastate storage companies with market-based rates from the requirement to file semi-annual reports, since the reports require pricing information. Equitable maintains that where market-based rates are in effect, the Commission does not need pricing information to determine if the rates charged exceed allowed maximums, or the extent of discounting for future ratemaking purposes. Equitable states that in a competitive market, price transparency occurs, if at all, through market channels. The Commission will not eliminate the semi-annual storage report. Contrary to the Texas Intrastates' assertion, storage reporting is expressly excepted from the annual transportation report. This report, therefore, is not duplicative. Furthermore, the Form EIA-191 cannot be substituted for the semi-annual storage data. As the Commission stated in Order No. 636-A,75 the EIA does not collect data by individual customer, nor does it collect rate and revenue data. In addition, the pricing information for storage service subject to market-based pricing is not moot. Although the Commission does not have certificate jurisdiction over NGPA Section 311 intrastate storage service, Section 311 tasks the Commission with the responsibility to ensure rates and charges are fair and equitable.76 For the Commission to carry out this [[Page 53051]] responsibility, it is important for rates charged to be reported. It is even more critical for the Commission to review pricing when the Commission is relying on competition to regulate rates, rather than scrutinizing the underlying cost of service. Thus, we will not exempt intrastate storage companies charging market-based rates from the requirement to file semi-annual storage reports. \75\Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation; and Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, III Stats. & Regs. Preambles para. 30,950 at p. 30,581 (August 3, 1992) (Order No. 636-A). \76\15 U.S.C. 3372. --------------------------------------------------------------------------- Accordingly, the Commission is deleting from section 284.126 existing paragraphs (a) (initial full report); (b) (subsequent reports); (d) (notification of termination); (e) (filing fees); and (f) (reporting form).77 The notification of bypass in paragraph (a)(6) is now paragraph (a), the revised annual report is now paragraph (b), and the semi-annual storage report is paragraph (c). The only change we are making with respect to section 284.126 in this final rule from what was proposed in the NOPR, is the extension of the filing deadline of the annual report from March 1 to March 31. \77\Freeport notes that paragraph 106 of the regulation text does not list current paragraph (d) regarding notification of termination among those paragraphs to be removed, contrary to the stated intent of the preamble. This was simply an oversight of the Commission in the drafting of the regulations. Paragraph (d) of section 284.126 should be eliminated, and in the regulation text to this final rule, we are including paragraph (d) among those to be removed. --------------------------------------------------------------------------- Finally, the Commission is adopting an additional change proposed in the NOPR in relation to Subpart C. The Commission is revising the filing requirements under section 284.123(e) to require that the statement filed by an intrastate pipeline within 30 days after commencement of new service under subpart C, include the rate election made by the intrastate pipeline under section 284.123(b). D. Modification of Discount Reports 1. NOPR Proposal In the NOPR, the Commission proposed to combine the following two discount reporting requirements to avoid duplication. Section 284.7(d)(5)(iv) presently requires that all pipelines charging a discounted rate for transportation service under subparts B and G of Part 284 file, within 15 days after a billing period, a report with the Commission identifying the maximum rate or reservation fee, the rate or fee actually charged during the billing period, the shipper, and any affiliation between the shipper and the pipeline. Section 250.16(d) requires that pipelines transporting gas under subparts B or G that are affiliated with a gas marketing or brokering entity and conduct transportation transactions with such affiliate, also maintain a variety of more detailed information on the transportation discounts they provide to affiliate and non-affiliate shippers. For example, section 250.16(d) requires maintenance of information on quantities scheduled under the discount, while section 284.7(d)(5)(iv) does not require the filing of any quantity information. Thus, the more detailed information required by section 250.16 only has to be maintained and made available to the Commission upon request, while the limited information required under section 284.7(d)(5)(iv) must be filed with the Commission. Because the information required by section 284.7(d)(5)(iv) is also required by section 250.16(d), the Commission determined in the NOPR that these requirements were somewhat duplicative, and proposed to consolidate the two sections into one discount reporting requirement, new section 284.7(c)(6). The Commission proposed to eliminate the section 250.16(d) maintenance requirements, and expand the filing requirements under Part 284 to include most of the information previously maintained under section 250.16(d). Under this proposal, the major change from the existing section 284.7(d)(5)(iv) was the addition of a requirement for filing information on quantities of gas delivered for discounted interruptible service, and the contract demand for discounted firm service.78 The Commission stated in the NOPR that information on quantities shipped and contract demand would enable the Commission and the market to compare the extent of interruptible and firm discounting by the pipelines with the extent of the discounting of capacity release transactions under the capacity release program established by Order No. 636. The Commission proposed that the discount information under new section 284.7(c)(6) be filed electronically with the Commission. \78\For interruptible discounts, the Commission proposed to include the zone in which the quantities are delivered. The Commission stated that information on zones was not needed for firm service because the information was to be reported in the index of customers under section 284.106. --------------------------------------------------------------------------- 2. Comments The Commission received a few comments in support of its proposal, but many more comments in opposition to proposed section 284.7(c)(6), as summarized below. APGA believes that the proposed change to the discount reporting requirements will enhance the quality of data relating to pipeline discounts. The Registry also fully supports the modifications to the discount reporting requirements, and believes that respondents will be able to file the discount report using data that they already collect either to perform or monitor essential services. NI-Gas supports the proposed discount rate report but asks that the Commission require information on the duration of discounts and the applicable delivery points. NI-Gas asserts that discount information must continue to be available on a timely basis to interested parties so that: (a) all interested parties can monitor the operations of the market; and (b) releasing shippers have access to the same information with respect to pipeline sales of capacity as pipelines have with respect to capacity releases. NI-Gas believes that the additional information is necessary to achieve this parity. However, many of the commenters argue that the proposed modifications to the discount report will require pipelines to publicly divulge commercially sensitive information. Panhandle opposes the proposed reporting requirements on this basis. It argues that the Commission should ensure that the pipeline and its customers are not disadvantaged where there is a competitive alternative provided by a non-regulated entity. Panhandle states that shippers will be less inclined to deal with pipelines that are required to reveal sensitive data. As an alternative to the proposed requirement, Panhandle suggests providing for confidential periodic audits, and requiring pipelines to maintain information sets for a period of three years and to provide the information to the Commission on a confidential basis upon request. Tennessee, also, believes that pipelines will be harmed if they are required to reveal customer specific details of their transactions as proposed in the discount rate reports and Index of Customers. Tennessee argues that this level of detail has not previously been required and is not necessary in a more competitive environment. It states that other market participants are not required to divulge transactional information at this level of detail. In any case, Tennessee argues that this information can be produced on a case-specific basis in response to a complaint or in a rate case, and that this is the wrong time to expand the type and detail of transactional information. Consumers Power, NI-Gas, and AGA argue the proposed discount rate data coupled with other publicly available information, such as the proposed Index of Customers, will permit the derivation [[Page 53052]] of specific point-to-point contractual pricing information for firm capacity discounts. For this reason, they suggest the removal of the contract number from the discount rate report. ANR/CIG note the increase in competition occasioned by the Commission's issuance of Order Nos. 436 and 636. They state that the discount reporting requirements provide such a wealth of information that competitors can target pipelines' customers to offer them better deals. ANR/CIG argue that specific details of individual discounts disadvantage the customers who have negotiated those discounts. Therefore, ANR/CIG assert that discount information should be limited to the information currently required. INGAA argues the information the Commission proposes to collect is commercially sensitive and not necessary to meet the purpose of the discount reporting requirement--to ensure that discounts are provided on a non-discriminatory basis. INGAA asserts that the Commission did not explain in the NOPR why it is proposing to alter the purpose and method of providing the discount information, or why non-affiliate discount data is inadequate as currently filed. Texas Gas, while supporting the elimination of the duplicative discount reporting requirements, concurs with INGAA's position that certain items of information are inappropriate for public dissemination and unnecessary to fulfill the original purpose of the discount reporting requirements. INGAA adds that consideration of the data required to compare the extent of interruptible and firm discounting by pipelines with discounting in the capacity release market is better addressed in the Commission's rulemaking on capacity release. INGAA asserts that pipelines should be required to maintain, but not file, discount information, making the data available to the Commission upon request. Alternatively, if information on discount transactions must be filed, INGAA argues that the amount of information required must be reduced to no more than is currently reported. KN and MRT either adopt or support INGAA's comments with respect to the discount reports. Some commenters propose that the Commission require a less frequent reporting of the discount information and a lengthening of the filing deadline, which is 15 days after the close of the billing period. If information on discount transactions must be filed, INGAA supports an annual reporting period for the discount report, or the filing of the discount report no more frequently than each quarter, with the filing deadline 30 days after the last month of the quarter in which billing occurs. If pipelines must file monthly, INGAA states, the filing deadline should be extended to 30 days after the close of the billing period. Texas Gas agrees. Panhandle argues that if discount reporting remains a requirement, monthly discount activity should be compiled and submitted on a quarterly basis, 45 days following the last day of each quarter. Panhandle states that all of the data elements could be maintained on a monthly basis for a three-year period from the time of the discounting. 3. Commission Ruling In light of substantial opposition to the proposed changes, the Commission will not adopt the proposed modifications to the reporting requirements for discounted transactions outlined in the NOPR. The Commission will retain the separate, pre-existing requirements in sections 284.7 and 260.15(d), with some minor modifications. While this will involve some duplication, the existing requirements of section 284.7, together with the requirements in section 260.15(d), already provide the balance between public disclosure and confidentiality that the commenters seek. The changes to these sections proposed in the NOPR were not prompted by a need for more stringent reporting requirements to ensure discounts are offered on a non-discriminatory basis. Thus, the information available through, not only sections 284.7 and 250.16, but also through section 161.3, regarding affiliate discount transactions, continues to be sufficient for the market and the Commission to determine if any discriminatory activity is taking place.79 This is, and remains, the primary purpose of these sections of the regulations. \79\Under Standard H of the Standards of Conduct, section 161.3(h), pipelines transporting gas under subparts B or G of Part 284 or subpart A of Part 157 that are affiliated with a gas marketing or brokering entity and conduct transportation transactions with such affiliate are now required to post discount information concerning affiliate transactions on their EBBs, including the delivery points to which the discount applies. --------------------------------------------------------------------------- Our proposal to expand the discount reports to include information was designed to increase the usefulness of the discount reports by enabling the market and the Commission to compare the extent of discounting by pipelines with the extent of discounting in the capacity release market. However, we have determined that the benefits realized from the creation of another use for the discount reports are outweighed by the risk of harm to pipelines and LDCs that would stem from the release of this detailed information. The Commission is not modifying the existing regulations to adopt annual or quarterly discount reporting, nor lengthening the time of filing to 30 days after the close of the billing period. The primary purpose of the discount reports is to allow customers to monitor discounts to determine if the pipeline is discriminating. Such proposals would make it impossible for customers to monitor discrimination on a timely basis. Nor is the Commission adopting INGAA's suggestion that all of the discount data be maintained, but not filed. However, we are adopting INGAA's alternative recommendation that the data that is required to be filed be limited to the data currently required. The Commission is removing the discount information currently required in section 284.7(d)(5)(iv), and reinserting it in a new section 284.7(c)(6). In addition, section 284.7(c)(6) now specifies that the pipeline report ``the full legal name of the shipper being provided the discount,'' rather than merely ``the shipper,'' as the current regulation specifies. Further, the Commission adopts the proposal from the NOPR to require the data filed under section 284.7 to be submitted electronically. The Commission also is adding, as proposed in the NOPR, a provision specifying that the discount report does not apply to capacity releases at a discounted rate, except when the release is permanent. The discount report is designed to capture discounts granted by the pipelines. In a temporary capacity release, the releasing shipper is still obligated to the pipeline under its initial contract. Thus, even if the shipper obtaining released capacity pays a discounted rate, the pipeline has not agreed to the discount because the releasing shipper will owe the pipeline the maximum rate under its contract. In a permanent capacity release, however, the releasing shipper's contractual obligations end, and the replacement shipper enters into a new primary contract with the pipeline. Thus, if the pipeline offers a discount for a permanent capacity release, the pipeline is providing the discount and would have to report it. E. Establishment of Electronic Index of Customers 1. NOPR Proposal In the NOPR, the Commission proposed to require interstate pipelines [[Page 53053]] transporting gas under subparts B and G to provide an electronic Index of Customers80 through a downloadable file that is updated monthly, and restated in its entirety annually (proposed sections 284.106 and 284.223). As further discussed below, the Commission is retaining the requirement that pipelines maintain a downloadable electronic file containing an Index of Customers in the final rule. However, the Commission is adopting an Index of Customers that is greatly abbreviated from the Index that was proposed in the NOPR, and is quarterly, rather than monthly. \80\The Commission is using the term ``Index of Customers'' rather than ``Index of Purchasers,'' to reflect the use of that term in Docket No. RM95-3-000, revising part 154. ``Index of Customers'' more accurately captures the nature of the current natural gas market. --------------------------------------------------------------------------- The electronic Index of Customers proposed in the NOPR originated in the Electronic Bulletin Board (EBB) standardization proceeding in Docket No. RM93-4-000.81 As explained in the NOPR in this proceeding, the EBB Industry Working Groups in the EBB standardization proceeding, which developed the standards implemented by the Commission, failed to reach consensus on a proposal for an Index of Customers that would provide the market with information about capacity rights. However, several groups of participants in the process submitted proposals for consideration. \81\Standards For Electronic Bulletin Boards Required Under Part 284 of the Commission's Regulations, Order No. 563, 59 FR 516 (Jan. 5, 1994), III FERC Stats. & Regs. Preambles para. 30,988 (Dec. 23, 1993), order on reh'g, Order No. 563-A, 59 FR 23624 (May 6, 1994), III FERC Stats. & Regs. Preambles para. 30,994 (May 2, 1994), reh'g denied, Order No. 563-B, 68 FERC para. 61,002 (1994). --------------------------------------------------------------------------- In the NOPR, the Commission proposed to adopt an electronic Index of Customers containing the elements put forth by some of the EBB Working Group participants, as well as some additional elements. Specifically, the Commission proposed to include for each firm transportation and storage shipper: shipper's name; contract identifier; rate schedule; contract start date; contract end date; contract quantity; receipt points (and associated maximum daily quantities (MDQs)); delivery points (and associated MDQs); and conjunctive restrictions, if any; information on capacity held by rate zones to permit verification of reservation billing determinants; data elements applicable to storage service to capture the additional detail required to assess storage capacity; a unique customer identifier to permit the information in the Index of Customers to be tied to the electronic data interchange (EDI) information on capacity release;82 and an authorization code to delineate whether the information is for Part 284, Subpart B, Part 284, Subpart G, or Part 157 service. \82\Electronic Data Interchange (EDI) is a means by which computers exchange information over communication lines using standardized formats. For example, the capacity release data posted on a pipeline's electronic bulletin board is also available in downloadable files that conform to the standards for EDI promulgated by the American National Standards Institute (ANSI) Accredited Standards Committee (ASC). --------------------------------------------------------------------------- The Commission identified in the NOPR two functions of the Index of Customers. First, we stated that the Index would provide the Commission with the information that it requires for analyzing capacity held on pipelines (which was previously included in the initial and subsequent reports). Second, it would provide capacity information to the market, which would aid the capacity release system by enabling shippers to locate those holding capacity rights that the shippers may want to acquire. However, the Commission recognized in the NOPR that some commenters in the EBB proceeding objected to the inclusion of receipt and delivery points in an index of purchasers.83 Therefore, the Commission instructed commenters to address the relative burden or difficulty of including the receipt and delivery point information in the proposed Index of Customers, under the assumption that all of the other information proposed would be required. \83\These parties contended that the provision of such information would be burdensome and might disclose information that would place firm shippers at a competitive disadvantage with respect to future gas purchase decisions. See Order No. 636-A, III FERC Stats. & Regs. Preambles at 31,047-48. --------------------------------------------------------------------------- 2. Comments The Commission received widespread comment on the proposed Index of Customers. Some commenters fully support the Index of Customers as proposed.84 Other commenters support an Index of Customers, but suggest modifications or improvements.85 Many commenters oppose the adoption of any Index of Customers,86 but either suggest alternatives, or certain changes, to the proposed Index of Customers, if the Commission continues to require some type of Index. The main issues raised by the commenters are whether, and to what extent, the Commission should require an Index of Customers, given the alleged commercial sensitivity of the information and burden or cost in reporting the information, and specifically, whether receipt and delivery point information should be included in the Index. \84\Those commenters are: DOE, PMTG, PG&E, Registry, and Gaslantic. \85\Those commenters are APGA, NI-Gas, and Texas Gas. \86\Those commenters are: ANR/CIG, AGA, Consumers Power, INGAA, El Paso, CNG, Columbia, Columbia Distribution, Panhandle, and KN. --------------------------------------------------------------------------- a. Comments In Support. DOE, PMTG, and PG&E support the Index of Customers as proposed. They believe that the Index will contain critical baseline information about the rights of firm capacity holders necessary for markets to operate efficiently and effectively. PMTG notes it will be extremely beneficial to the capacity release market, particularly the receipt and delivery point information. PG&E supports the proposed Index of Customers as a vehicle for price discovery. It states that price discovery is critical to competition, and that LDCs need the opportunity to see the price and terms of the interstate pipelines' competing capacity on a real-time basis. Gaslantic and the Registry also support the Index of Customers as proposed. They argue that absent an Index of Customers, and given the elimination of the ST reports, the Commission, the market, and other regulators will have no window to the workings of the short-term firm transportation market. They maintain that this information is necessary for the market to ensure that short-term firm transportation transactions do not receive an unfair preference over released firm service or similar requests for the same service. The Registry states that short-term firm transportation, including gray market transactions and interruptible transportation markets, will be monitored through cross-correlating information contained in the proposed Index of Customers, Form Nos. 2, 2A, and 11, as well as the discount rate reports. The Registry argues that the point level MDQ information is crucial to the proper formation and functioning of the secondary market in capacity rights, a more efficient regulatory process, and a more effective day-to-day operating environment. The Registry states that data on points rights is essential for determining path-rights, segmentability, and relative flexibility among shippers, i.e., quantity of receipt and delivery point rights as compared to mainline rights. Absent the Index, the Registry argues that no electronically processible means exist to determine who to contact other than the pipeline, or what total amount of firm rights might be available. Without point rights information as a baseline, the Registry believes that the market is bereft of exactly the data which is needed to [[Page 53054]] identify transaction opportunities and pursue them. Furthermore, according to Registry, regional, LDC, and third-party- run exchanges, and market center developers, face nearly insurmountable information integrity hurdles, which are serious barriers to the entry of competing market centers and information service providers. Registry believes these hurdles can be avoided with the availability of capacity inventory information. Moreover, the Registry notes that one of the impediments to further integration of the national pipeline network is the inability of the pipelines to coordinate the simplest cross- pipeline transactions without extensive verbal and written communication. With minor changes to the pending EDI Nomination dataset and the addition of an electronic Index of Customers which includes points and point rights, this problem largely would be solved. Gaslantic agrees with Registry on the importance of point information. Gaslantic explains that pipelines confirm and nominate released capacity as interruptible capacity, unless scheduled from and to primary receipt and delivery points. Due to this, Gaslantic states that released capacity moving between points other than primary points is no more valuable to the replacement shipper than interruptible capacity. Similarly, Gaslantic states that the pipeline will not confirm or schedule capacity nominated from, or to, secondary or alternate points if there is no operationally available capacity at intervening interconnects. Gaslantic believes that eliminating these problems will strengthen the secondary market, and that the key is for buyers in the secondary market to be able to identify, and seek release of, specific primary capacity. It states that this is possible only if the primary capacity holders at each point are identifiable. Gaslantic states that the Index of Customers information is available now on various reports filed with the Commission. Gaslantic argues that with the elimination of these reports (specifically, the initial and subsequent reports), the short-term firm transportation sold by a pipeline would not be reported anywhere, since it is not reported on pipelines' EBBs, through EDI, or in tariff indices of purchasers. Thus, Gaslantic urges that the Commission adopt a comprehensive Index of Customers including the point information. Gaslantic states that it and other members of the EBB Working Group agreed to the reduction of these reports only on the condition that they were replaced with a comprehensive electronic Index of Customers that would contain the essential point rights information now contained in the paper reports. b. Comments In Opposition. Certain commenters, however, oppose the adoption of the proposed Index of Customers. Generally, they argue that the data the Commission wishes to be disclosed is commercially sensitive, would be burdensome and costly to provide, and would result in delays in the implementation of other higher priority electronic data items. Opposing comments also question the necessity of the data for efficient operation of the capacity release market. Consumers Power, ANR/CIG, and Panhandle argue that the information proposed as a part of the electronic Index of Customers is commercially sensitive and potentially damaging. According to ANR/CIG, by mandating open access to pipeline transportation services, and the unbundling of pipeline services, the Commission has introduced competition into natural gas markets. They argue that the Commission's regulations provide the pipelines' competitors with a wealth of information about the pipelines' business arrangements that these competitors can use to target pipeline customers and offer them deals that undercut those offered by the pipeline. ANR/CIG stress that pipelines do not have equivalent information on these competitors. They assert that the proposed regulations require the filing of information not previously required, and require that information be filed publicly, without adequate protection for non-public disclosure of commercially sensitive information. NI-Gas, Consumers Power, and Texas Gas argue that receipt and delivery point information should not be included in the Index of Customers because it is commercially sensitive data. NI-Gas states that knowledge of primary receipt points will allow parties to identify commercially sensitive information about the sources of a shipper's supply. Consumers Power argues that the release of such information would result in competitive detriment to pipelines, and that such detriment is not outweighed by the Commission's stated reasons for the Index. Texas Gas believes that some customers might object to the inclusion of the information, feeling that the increased accessibility to this information that posting on the EBB would provide may put them at a competitive disadvantage with certain suppliers. If the Commission insists on point data, Texas Gas argues it should be limited to receipt and delivery points where the shipper has reserved capacity on a primary basis. Panhandle, Columbia, Columbia Distribution, AGA, and El Paso object to the Index of Customers as burdensome. They argue that the implementation and maintenance of the Index of Customers will require significant financial commitments both in terms of human resources and computer costs. AGA points to the significant costs the pipelines would incur in changing their existing EBB computer screens and formats. AGA also argues the Commission's policy that data available through EDI datasets must also be available on the EBB will increase costs. AGA believes that it is questionable whether the benefits outweigh the costs. AGA is further concerned that the industry will be applying its resources to create an index for a capacity release market that is still evolving and may change significantly over the next several years. Columbia concurs, stating it is premature to impose significant information system burdens on pipelines until the capacity release program has been reviewed and modified. It adds that many of the proposed elements are superfluous to the purpose of providing a downloadable listing of customers with firm capacity that could be releasable. El Paso, NI-Gas, and Columbia specifically oppose the provision of receipt and delivery point data on the basis of the burden it imposes on pipelines. El Paso argues that providing MDQ by receipt and delivery point will be burdensome because this information is not always readily available. NI-Gas asserts that receipt points change far more often than delivery points, placing a heavier burden on the pipeline. Columbia quantifies the monthly burden of maintaining the Index of Customers as approximately 16 hours, if receipt point MDQ, delivery point MDQ, and conjunctive restrictions are required. If they are not required, Columbia estimates it will take only four hours per month to maintain. Thus, Columbia proposes that the Commission require contract quantity and rate schedule information in the aggregate. It states that aggregate data will provide the Commission with all necessary information for analyzing the capacity held on pipelines. Columbia believes that the choice to disclose the contract specific data requested in the proposed Index of Customers should rest with the capacity holder. AGA also challenges the Commission's assertion the information is necessary to facilitate the capacity [[Page 53055]] release market. AGA argues that such need is questionable since shippers are already under substantial economic pressure to release capacity. INGAA, too, argues that requiring pipelines to post underlying contract information is not only burdensome, but is simply unnecessary for the industry to carry on capacity trading. INGAA argues that information on capacity for the market is already available, and that the Commission can obtain pertinent information on contracts either by requiring pipelines to file an index in their tariffs, or via a less extensive electronic index. Similarly, Panhandle asserts that data requirements in the proposed rule are currently being provided as part of pipeline capacity release systems and thus to provide this information on all EBBs as part of the index would be duplicative in many instances. KN agrees. Texas Gas and AGA argue that requiring information on receipt and delivery points to be included in an Index of Customers is unnecessary. Texas Gas explains that with the implementation of flexible receipt and delivery point authority under Order No. 636, information concerning specific receipt and delivery points is not as meaningful or significant as it was when the regulations requiring the reporting of transportation transactions were first implemented. Texas Gas states that many pipelines already maintain updated information on their EBBs concerning their ``master receipt point lists,'' so that including such information in the Index of Customers would be unnecessary. El Paso, too, notes that receipt and delivery information is already available in the Operationally Available Capacity section of each pipeline's EBB. AGA states that the Commission did not establish in the NOPR a relevant need for this information. Like Texas Gas, AGA, also, believes that the creation of flexible receipt and delivery points for all Part 284 transportation service greatly decreases the need to know ownership of capacity at a particular point. Furthermore, adoption of the index of customers, according to the EBB Working Group, ANR/CIG, AGA, Consumers Power, and INGAA, will result in delays in implementation of other higher priority electronic communication data items. ANR/CIG and the EBB Working Group point out the EBB Working Group has identified eight higher priority natural gas transactions for development and implementation. INGAA and AGA question the value of the Index, citing a survey of 55 companies by the EBB Working Group, showing the index of purchasers as the lowest priority item in a list of 26 items to be standardized.\87\ INGAA and KN also note that the EBB Working Group was unable to reach consensus on the need for an Index of Customers. While supporting the concept of an Index of Customers, NI-Gas, also, questions whether this item should be a priority, given the other demands on pipeline programming abilities. \87\The 55 companies surveyed include pipelines, LDCs, producers, marketers, end-users, and information services providers. AGA attaches to its comments the survey results showing this ranking of standardization priorities. --------------------------------------------------------------------------- As an alternative to establishing an Index of Customers, AGA and Consumers Power believe the Commission should update the Index of Purchasers contained in existing section 154.41. AGA supports an Index of Purchasers that includes an alphabetical list of all firm transporters under the pipeline's tariff, the applicable rate schedules, and the maximum contract quantity (summed by rate schedule, if appropriate). Consumers Power adds the contract start date and end date to AGA's list. As is now the case, AGA proposes that the revised Index of Purchasers be included in the pipelines' tariffs. It states that since these tariffs are currently available from the Commission in electronic format, interested parties would be able to obtain the Index in electronic format directly from the Commission. ANR/CIG maintain that the data required in the Index of Customers can be provided to the Commission during a rate case, if necessary. INGAA argues that instead of imposing a mandatory requirement that pipelines post contract information on an electronic Index of Customers, the Commission should instead allow the market to develop the information it needs on its own. It states that the capacity release market has experienced rapid and widespread growth, and that a number of third-party information reporting systems have been developed, without the existence of a mandatory pipeline electronic contract reporting system. Those commenters opposing the proposed Index of Customers suggest modifications if the Commission adheres to the position an index is necessary. Some commenters make broad-based suggestions. Panhandle recommends that the same customer information rules apply to all participants to the extent practicable, so that one competitor class will not be afforded an arbitrary advantage over another by the disclosure of information that is not required to be publicly disclosed for regulatory purposes. KN suggests the information required on an electronic Index of Customers be limited to data useful to the industry. Other commenters opposed to the Index of Customers make specific recommendations regarding the content of an Index if one must be imposed. Columbia asserts the Index should be limited to the basic information required to identify shippers that have releasable capacity, the customer name, maximum contract quantity, and rate schedule. INGAA urges the Commission to reduce the amount of information to be included in the Index of Customers to the shipper's name, rate schedule under which service is performed, and the effective date of the contract. To that, Panhandle would add the execution date of the contract. However, it opposes public disclosure of the term of the contract as commercially sensitive. ANR/CIG, on the other hand, would add the termination date of the contract to the list. El Paso supports the more limited Index of Customers discussed by the Commission in Order No. 563-A, and noted supra. c. Miscellaneous Comments. Both those commenters supporting and opposing the concept of an index of customers suggest various minor modifications to the proposed electronic Index of Customers. To make the index more useful, DOE asserts that each customer's name should be accompanied by a standardized I.D. number for ease of identification. Similarly, the Industrials want to be able to correlate the information reported in Statement G with the information reported on the Index of Customers. Therefore, they urge the Commission to require consistent reporting of customer names between Statement G and the index of customers and the reporting of contract numbers on both. In addition, DOE suggests that receipt and delivery point information be accompanied by a standardized identification number (PI-GRID) such as the location number used in EDI datasets. While supporting the proposed Index of Customers, APGA suggests two modifications. APGA wants a pipeline to file an updated copy of the Index of Customers on paper when it files a general rate case. Further, APGA would like the Commission to consider making the Index of Customers available through its Central Issuance Posting System. Freeport seeks to be excluded from the requirement to establish an EBB to disseminate the Index of Customers. [[Page 53056]] Freeport states that the Commission expressly exempted it from having to implement an EBB during its restructuring proceedings. It argues that the reasons supporting that decision continue to apply here. Freeport asserts this new regulation should not apply to any interstate pipeline exempted from the Commission's EBB regulations under Order No. 636, or whose throughput during the past twelve months has been zero. 3. Commission Ruling The proposal to establish an electronic Index of Customers has been a highly contentious issue throughout both the EBB standardization proceeding and this rulemaking proceeding. In the NOPR, we proposed an extensive Index of Customers. In response, proponents of the proposed Index argue that the data included in the Index of Customers, particularly the receipt and delivery point data, is crucial for the efficient operation of the capacity release market; it will ease the integration of the national pipeline network by simplifying cross- pipeline transactions; it provides solutions to information integrity hurdles for exchanges and market center developers; and it will provide a window on short-term firm transactions. Opponents of the proposed Index argue just as strenuously that the data will be burdensome and costly to provide; it is commercially sensitive; it identifies sensitive data about a shipper's supply; it is duplicative since it is supplied on the pipeline's EBB; and it may not always be readily available. In keeping with the primary goal of this rulemaking proceeding to eliminate unnecessary regulations, and in light of the numerous complaints in the comments that much of the information is commercially sensitive, and that its disclosure would be harmful and burdensome, the Commission has reassessed its regulatory need for the information included in the proposed Index of Customers. We have attempted to distinguish between data that is absolutely necessary for the Commission's regulation of the industry, and data that may not be necessary for review purposes. The amount and type of information included in the proposed Index extends beyond that which the Commission needs to receive from all pipelines on a regular basis to regulate the natural gas industry today. For the Commission's purposes, only a list of a pipeline's firm shippers, the rate schedule numbers for the services for which the shippers are contracting, the effective and expiration dates of the contracts, and maximum daily contract quantities are necessary. Several commenters have argued that the contract expiration date and contract quantity should not be included in the Index. We believe that this information is necessary for our regulatory purposes. The information included in the Index being adopted represents fundamental data about the natural gas industry--namely, how much of the pipeline's capacity shippers have under firm contract. This information is basic to the Commission's understanding of events taking place in the industry. With this information, the Commission will remain apprised of, for example, trends in the industry, the willingness of shippers to hold firm capacity, the average length of time capacity remains under contract, and the proportion of capacity rolling over under evergreen provisions. Pipelines are beginning to deal with complex issues related to shippers' contracts coming up for renewal in the post-restructuring period.\88\ The lack of easily accessible data regarding customers' contract levels and contract terms could hamper the Commission's ability to assess the impact of this phenomenon on the industry. The Index will provide key data for this purpose. \88\For example, Transwestern Pipeline Co. recently filed a settlement in Docket No. RP95-271-000 to deal with the turn back of significant amounts of capacity by a key customer. --------------------------------------------------------------------------- Those commenters in favor of the proposed Index of Customers have not persuaded us that the Commission should require the pipelines to maintain a comprehensive list of capacity rights by receipt and delivery points to aid the secondary capacity market, or to assist third-party-run exchanges and market center developers. Their comments do not make clear what practical effect providing the proposed additional information would have on the secondary market. For example, there has been no evidence presented that the inefficiencies in the capacity release market would be removed if detailed information on the location of capacity rights were made public. However, AGA's comments stating that the capacity holders have incentives to market idle capacity are persuasive. Moreover, the Commission can require more detailed information on capacity rights to be produced in particular proceedings, as necessary. The Registry supports the proposed Index as a window on short-term firm transportation. While the Index adopted in this rule will provide information on short-term firm transportation, not all short-term firm contracts entered into on the pipeline's system will be reported, due to the decrease in the frequency of filing. However, the Index adopted will provide a snapshot profile of the pipeline's contracts on the first day of each quarter. This will enable the industry to follow trends in the proportion of capacity held under short-term firm contracts versus the proportion of capacity held under longer-term contracts. With respect to cross-pipeline issues, the industry is currently grappling with the best way to resolve these issues. Therefore, the Commission believes that it is premature to adopt a reporting standard to aid in resolution of such issues. Rather, the industry should be afforded time to attempt to reach a resolution. Therefore, while the Commission is retaining the requirement that pipelines file an electronic Index of Customers, the Commission is adopting only a limited Index of Customers. The Index will contain for all firm customers under contract as of the first day of the calendar quarter,89 the full legal name of the shipper, the rate schedule number for which service is contracted, the contract effective and expiration dates, and the contract quantities. The Commission is requiring the full legal name of the customer to be reported to help to ensure that the same customer name is reported regardless of the filing or form in which it is reported. We are also requiring that the rate schedule number be reported in the same format as it appears in other reports and filings with the Commission. \89\It is not necessary to require the posting of interruptible contracts in the Index of Customers. --------------------------------------------------------------------------- The Index must be posted on the pipeline's EBB, and filed electronically, once each calendar quarter. That is, on the first of each calendar quarter, the Index must be restated and reposted on the EBB to include all firm contracts in effect on that date, and filed with the Commission in electronic form. A paper copy of the Index is not required to be filed. When a pipeline has implemented the electronic Index of Customers, its obligation to provide for an Index of Customers in its tariff will cease. In addition, where a pipeline has received a waiver from establishing an EBB, it does not have to establish an EBB in order to implement an Index of Customers. In that case, pipelines, such as Freeport, must comply with the reporting requirements of section 154.111 instead. Several commenters argue for the information included in the Index to be filed in a rate case, or as part of the tariff, instead of in a separate Index of [[Page 53057]] Customers. Filing the data with the rate case would not be timely enough for the Commission's review purposes. It is true that filing the data as part of the tariff, either by updating section 154.41 or establishing a new index, would make it publicly available in an electronic format. However, in the past, the Commission has had difficulty extracting the Index of Customer data from the tariff for use in spreadsheets and databases due to the inconsistent way the data is presented, even from page to page within a single tariff. To make the data most useful, we are requiring that it be filed in a consistent format by all pipelines. The index will be maintained on each pipeline's EBB in a delimited ASCII format in a file which can be downloaded from the EBB. Similarly, APGA proposed that the Commission require pipelines to file an updated copy of the Index of Customers on paper when it files a general rate case. We will not adopt APGA's suggestion. The Index will now be updated quarterly, and it should be fairly simple for a paper copy of the index to be generated from the electronic data. We will, however, adopt APGA's proposal to make the Index of Customers available through the Commission's bulletin board system. A number of commenters express concern about the delay that providing an electronic Index of Customers may cause in implementing electronic data interchange (EDI) services which the industry has identified as being higher priority. Others are concerned with the costs involved. Still others, DOE for instance, support using EDI to transmit the Index. Since the Commission is proposing a substantial reduction in the data included in the Index of Customers, transmittal through EDI will not be necessary. As stated, the index will be available on the pipeline's EBB. Therefore, implementation of the index should cause no delay in the implementation of EDI services. As discussed in the electronic format section of this rule, Section IX, the industry will be working with the Commission staff to develop the data sets and other procedures necessary to provide for downloading of the Index of Customers on the EBB. Instructions for reporting the data elements listed in the regulations will need to be finalized. For example, appropriate file names and the presentation of dates still need to be determined. Thus, the final implementation of the Index of Customers by the industry and the Commission Staff will not occur until some time after the effective date of this rule. In the NOPR, the Commission proposed to require the pipelines to initially comply with the Index of Customers requirement within 180 days of the effective date of the final rule, in order to allow ample time for the industry and Staff to conclude their conferences, and for the pipelines to implement the resulting electronic elements of the Index of Customers. However, we will remove the requirement that the index be completed within 180 days of the effective date of this rule. The Commission would like the data to be provided as quickly as possible, but recognizes the competing demands on the pipelines' resources. We will require the pipelines to work out a flexible implementation schedule with staff, and to report back to the Commission for approval. In the intervening period between the effective date of the rule and the pipelines' implementation of the electronic Index of Customers under sections 284.106 and 284.223, pipelines providing transportation service under sections 284.106 or 284.223 will be required to comply with the Index of Customer requirements applicable to transportation and sales under Part 157, as set forth in sections 154.111(b) and (c). F. Removal of Obsolete Transitional Requirements Several sections in Part 284 were established by either Order No. 436 or Order No. 636 as interim measures to implement those orders, or to bridge the transition between the two orders. Some of these provisions contained action deadlines that have long since passed. The Commission is removing the following sections because they have become outdated due to subsequent events, and the current state of the regulatory environment. Section 284.7(b) provides for interim rates for part 284 transactions to be charged until new transportation rates are filed under section 284.7, which had to have been filed by July 1, 1986. This section has become obsolete, and therefore is no longer necessary. Section 284.10 provides an interim program for bundled sales customers to convert to firm transportation services. Since Order No. 636 has unbundled sales service, so that sales and transportation services are now separate services, there is no need for customers to convert from one to the other. This section is no longer applicable to the current regulatory framework. Section 284.11 sets forth environmental compliance requirements for any activity involving the construction of, or abandonment with removal of, certain facilities. Paragraph (d)(1) of section 284.11 requires the filing of a one-time report, by December 9, 1992, for any such activity costing more than $6.2 million that was commenced between July 14, 1992 and November 9, 1992. This provision is now meaningless because it required a one-time report, and the date for filing the report has passed. Thus, paragraph (d)(1) is deleted from the section. INGAA recommends the Commission change the filing deadline for the capacity report required under section 284.12 to May 1 to avoid conflict with financial reports due in April. Freeport requests modification of this provision in order not to require a report for any year whenever there has been no change from the last such report filed. The Commission will not change the deadline for filing the capacity report under section 284.12. The arguments made by INGAA for moving the deadline to May 1 are not persuasive. The filing date for the financial reports and the report due under section 284.12 have been in close proximity for some time. The respondents have been able to meet the April filing deadlines in the past, and there is no reason to assume they cannot meet the filing deadlines in the future. Nor will the Commission modify section 284.12 so that no capacity report is required when the capacity report remains the same from the last report filed. Rather than revise our regulations to provide for a situation that is likely to be the exception and not the rule, pipelines may, as always, seek waivers from this provision in these instances. INGAA and Texas Gas recommend the Commission remove the recordkeeping requirement in section 284.13. This section requires that within 30 days after commencing any subpart B or G transportation arrangement, the pipeline keep a log that includes the date of the request, the name of the person requesting transportation, and the volume of gas to be transported. INGAA and Texas Gas state that this information was based on the first-come, first-served capacity allocation procedure begun under Order No. 436, and is no longer relevant for today's capacity allocation method based on price. They further state that pipelines that use methods other than price to allocate capacity must comply with the capacity allocation requirements of Order No. 566. The Commission agrees with INGAA and Texas Gas. This information was primarily used to establish queues for the first-come, first-served allocation scheme under Order No. 436, and that allocation procedure was changed by Order Nos. 636 and 566. In addition, this recordkeeping [[Page 53058]] requirement largely duplicates the log keeping requirement for allocating capacity contained in section 250.16(c). Therefore, section 284.13 is eliminated from the regulations. Section 284.14--Provisions governing pipeline restructuring--was designed to implement the restructuring of pipelines' services under Order No. 636, and contains, among other things, the requirements for the compliance filings pipelines were required to make, and for the associated restructuring proceedings. The restructuring process is now complete; therefore this section is no longer necessary. Any pipeline who proposes to offer transportation service under subpart B or G of part 284 in the future will simply file to comply with the requirements of this part and Order No. 636. Sections 284.105 and 284.125, applicable to section 311 interstate and intrastate transportation, respectively, provided that transportation arrangements existing prior to Order No. 436 could continue in effect, under the same terms and conditions existing prior to Order No. 436 (with some exception), after the issuance of Order No. 436, for an interim period that would end, at the latest, on October 9, 1987. Thus, these transitional provisions only had effect for an interim period that is now over. Accordingly, we are eliminating sections 284.105 and 284.125. Section 284.122 governs transportation by intrastate pipelines under Section 311(a)(2) of the NGPA. The Commission is deleting paragraph (e) of section 284.122, which sets a January 31, 1992 expiration date for the authorization provided under that section for certain transportation. This transitional provision is no longer required. Similarly, section 284.123, governing the rates and charges for this section 311 transportation service, contains in subparagraph (e)(2) a transitional filing requirement deadline of February 1, 1985 for certain pre-existing transportation arrangements; thus, the Commission will remove section 284.123(e)(2). The Commission will also remove sections 284.223(e) (Transitional rule for transportation arrangements) and 284.223(f) (governing the conversion of transportation service under NGPA section 311 to NGA section 7(c) blanket transportation service). Section 284.223 authorizes an interstate pipeline to transport gas under a section 7 blanket certificate of public convenience and necessity for any shipper for any end use by that shipper or any other person. Section 284.223(e) was established as a transitional provision to permit transportation arrangements authorized under section 157.209(a)(1), which commenced before October 9, 1985, to qualify as transportation under section 284.223. Section 157.209(a)(1) permitted section 7 certificate holders under section 157.201 to transport natural gas only on behalf of a high-priority end user for a high-priority end use. Section 157.209(a)(1) was replaced by section 284.223, and was removed from the regulations effective November 18, 1985.90 Accordingly, the transitional rule contained section 284.223(e) applicable to transportation under section 157.209 is obsolete, and no longer necessary. Similarly, Section 284.223(f) is an interim measure that was designed to implement the addition of blanket transportation services. This section requires that all conversions be made prior to November 1, 1990. Consequently, sections 284.223(f) is also obsolete, and no longer necessary. \90\See 50 FR 42408 (October 18, 1995). --------------------------------------------------------------------------- Section 284.227 grants a certificate for intrastate pipelines in the coastal states for the transportation of federal offshore gas for use in that state. Paragraph (d) requires the intrastate pipeline converting from section 311 transportation service to service under this section to file a conversion report. This conversion report was a transitional requirement, and references the initial and subsequent reports that are being deleted by this rule. Accordingly, we are eliminating section 284.227(d). Section 284.402 of Subpart L, setting forth the authorization for blanket marketing certificates, provides in paragraph (c)(1) that the authorization for an ``affiliated marketer'' with respect to transactions involving affiliated pipelines becomes effective either when the affiliated pipeline receives its blanket sales certificate under Subpart J, a transportation-only affiliated pipeline's Order No. 636 compliance filing is approved, or when the Commission terminates the affiliated pipeline's RS proceeding. The Commission will delete the latter two conditions, since those occurrences have passed. G. Other Revisions The Commission is deleting most of Subpart D, governing certain sales under section 311 of the NGPA by intrastate pipelines. In Order No. 547,91 the Commission granted any person who is not an interstate pipeline 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. The certificate of limited jurisdiction does not subject the certificate holder to any other regulation under the Natural Gas Act by virtue of transactions under the certificate. Although the blanket certificate eliminates the need for Subpart D, the Commission will retain the basic authorization and rate provisions under Subpart D in sections 284.141, 284.142, and 284.144 for those persons who may wish to make sales under the NGPA instead of the blanket certificate under the Natural Gas Act. However, in recognition that an intrastate pipeline can also sell natural gas in an unbundled transaction under the blanket certificate, at negotiated rates, the Commission will retain a simplified version of section 284.144 governing rates and charges as part of the authorization provision set forth in section 284.142. The new rate rule within section 284.142, simplifies the current maximum sales rate rule to permit the gas commodity price negotiated in the contract, plus a fair and equitable transportation rate. \91\61 FERC para.61,281 (1992). --------------------------------------------------------------------------- The Commission is deleting Subpart E in its entirety, governing the assignment by any intrastate pipeline to any interstate pipeline or local distribution company of its contractual right to receive surplus natural gas at any first sale, without prior Commission approval. The Natural Gas Wellhead Decontrol Act of 1989 amended the definition of ``surplus natural gas'' in section 312 of the NGPA to mean ``any natural gas.'' Moreover, the only filings under Subpart E were made in 1979. Therefore, Subpart E is no longer necessary. The Commission is removing section 284.222, regarding transportation by interstate pipelines on behalf of other interstate pipelines. Since the Commission deleted the prior notice requirement in Order No. 537,92 which applied to transportation by interstate pipelines on behalf of shippers other than interstate pipelines under section 284.223, but did not apply to transactions under section 284.222, there is no longer any reason to distinguish between transportation under sections 284.222 and 284.223. Thus, the Commission will delete section 284.222, and apply section 284.223 to transportation by interstate [[Page 53059]] pipelines on behalf of other interstate pipelines, as well as transportation by interstate pipelines on behalf of non-interstate pipeline shippers. Therefore, the Commission is also modifying the title of section 284.223 to read ``Transportation by interstate pipelines on behalf of shippers.'' \92\Revisions to Regulations Governing Transportation under Section 311 of the Natural Gas Policy Act of 1978 and Blanket Transportation Certificates, 56 FERC para.61,415 (1991). --------------------------------------------------------------------------- The Commission is removing sections 284.225 and 284.226 concerning the transportation of gas released under the good faith negotiation procedures. Order No. 567,93 issued July 28, 1994, in Docket No. RM94-18-000, removed the good faith negotiation procedures under Section 270.201 as a result of the repeal of maximum lawful ceiling prices under the NGPA. \93\68 FERC para.61,135 (1994). --------------------------------------------------------------------------- Section 284.266 concerns the rates and charges for emergency transportation and sales service by interstate pipelines. Paragraph (b) of section 284.266 governs the determination of the emergency sales rate, and refers to the methodology a pipeline uses in designing its sales rates and its current purchased gas costs. This paragraph is no longer relevant in light of the changes brought about by Order No. 636. Order No. 636 unbundled transportation and sales services. All pipelines wishing to make unbundled sales, and holding a blanket certificate under subparts B or G of Part 284, were granted a blanket certificate authorizing firm and interruptible sales service with pre- granted abandonment.94 The rate for unbundled sales service is determined by the market.95 Similarly, the discussion in paragraph (c) of section 284.266, regarding the treatment of revenues, harks back to the time when transportation was the exception rather than the rule. Pipelines primarily sold natural gas bundled with transportation, calculating the price for the natural gas in their purchased gas adjustments. Since pipelines now offer transportation and sales services separately, with sales service provided at market-based prices, the crediting mechanism described in paragraph (c) has become an anachronism. Therefore, sections 284.266(b) and (c) are removed. \94\Order No. 636 at 30,437-38. \95\Id. --------------------------------------------------------------------------- In addition, the Commission is making a number of more minor, miscellaneous changes, such as deleting references to dates that have passed, updating the Commission's address, and changing provisions to conform with other changes that are being made in this rule. These modifications are set forth below. Section 284.2(b), concerning interest on refunds, contains a reference to section 154.102(c) for the interest formula. This reference must be changed to indicate the new provision in Part 154 where the interest formula now appears (section 154.501(d)). Section 284.4, specifying that all reports in Part 284 must indicate quantities of gas in MMBtu's, refers to Sec. 270.102, which has been removed, for the definition of MMBtu. The definition of MMBtu previously found at Sec. 270.102 must be incorporated in this section. The Commission is still requiring the reporting of quantities in MMBtu's, and the definition has not been changed. Therefore, this change does not constitute a modification from past requirements. The Commission is making a grammatical revision in section 284.8(b)(4)(iii). In section 284.102(e), governing the certifications interstate pipelines must obtain from shippers to be able to transport gas on behalf of an intrastate pipeline or local distribution company under section 311, the Commission is deleting reference to a January 3, 1992 deadline for tariff revisions establishing the certification requirement. The Commission is modifying paragraph (b)(1) of section 284.221, setting forth the general rules regarding the transportation by interstate pipelines on behalf of others under section 7(c) blanket certificates, to delete reference to an October 31, 1989 date no longer relevant, and a fee no longer collected. In sections 284.6(b) and 284.8(b)(5)(i), we are deleting reference to the specific street addresses of the Commission, many of which are former addresses, and replacing them with only the particular internal office name, the Commission's name, and ``Washington, D.C. 20426.'' In many provisions, the Commission is deleting reference to sections that have been eliminated by this rule, or by other prior rules. For example, in section 284.221(f)(2), we are eliminating reference to section 284.222, which is removed by this rule. Other conforming changes are set forth below. In light of the proposed elimination of Subpart E, the Commission is removing all references in section 284.224, governing certain transportation, sales and assignments by local distribution companies, to Subpart E, as well as to the word ``assignments'' in the section provisions and in the section heading. The Commission is retaining the blanket certificate and rate election procedures in section 284.224 that allow local distribution companies served by an interstate pipeline or Hinshaw pipeline to engage in sales and transportation of natural gas to the same extent as intrastate pipelines are authorized to engage in such activities under subparts C and D. The Commission is also removing the reference to assignment in section 284.3, which sets forth the NGA jurisdiction. Section 284.224(e)(5)(ii) requires the blanket certificate holder to file a copy of all contracts as a part of the initial full report under sections 284.126 and 284.148. Since the Commission is deleting in subparts C and D the requirement to file initial full reports, the Commission is also deleting section 284.224(e)(5)(ii). Furthermore, since the Commission is deleting the initial reports required in subparts C and D, the extension report in subpart D, and entire subpart E, which also required an initial report, the Commission is deleting section 381.404, which establishes the fee for initial or extension reports and refers to the removed sections. Section 284.269, concerning intrastate pipeline and LDC emergency sales rates, refers to removed section 284.144 for the calculation of the emergency sales rates. We are revising this section to refer, instead, to section 284.142. As a conforming change to our action in eliminating transitional provision 284.14, the Commission is deleting references to sections 284.14 in, and making modifications to, the following sections: 284.221(d), 284.284(b), 284.286(e), 284.287. Section 2.104(a), governing the procedures for the passthrough of pipeline take-or-pay buyout and buydown costs, refers to the grandfather provisions in sections 284.105 and 284.223. We are eliminating the reference to these sections, since we have deleted section 284.105 and the transitional provisions in paragraphs (e) and (f) of section 284.223. In Part 381, governing fees, section 381.404, concerning the fee for initial or extension reports for Title III transactions, references reports in sections 284.148(e), 284.165(d), and 284.126 that have been deleted. Therefore, section 381.404 is deleted, also. The Commission is revising section 385.2011, concerning electronic filing requirements, to update the reference to part 154 and to the Commission's address, and add the discount rate report as an electronic filing requirement. VIII. Part 157 In keeping with the goals of the NOPR, El Paso suggests that the Drilling Gas Report required by section 157.53(b) of the Commission's regulations can be [[Page 53060]] eliminated, especially now that pipelines are primarily transporters of natural gas. Section 157.53 exempts from the certificate requirements of section 7(c) of the NGA, the construction and operation of facilities necessary to render direct natural gas service for use in the drilling of gas or oil wells, or for use in the testing and purging of new natural gas pipeline facilities, as long as a drilling gas report describing such operations is filed annually. The Commission agrees with El Paso, in part. Facilities necessary to render direct natural gas service for use in the drilling of gas or oil wells may be constructed and operated under other procedures short of a full certificate filing. For example, since pipelines generally have a reduced merchant role, many of the facilities of this type will be built on behalf of natural gas producers. These facilities would be eligible for a blanket certificate under subpart F of section 157. References to these transactions will be removed from this section. We will retain this section for facilities built to purge and test new natural gas pipeline facilities since these facilities will otherwise generally require full certificate proceedings. IX. Electronic Filing Requirements A. Introduction Currently, the Commission requires pipelines to file the Form No. 2, Form No. 2-A, and Form No. 11 electronically. The pipelines file the electronic data on the following media: diskette, 9-track magnetic tape, and 18-track cartridge. The tapes and cartridges are used with the mainframe computer. However, the majority of pipelines file their data on diskette. The present filing requirements call for the data to be submitted in an ASCII flat file format.96 A flat file is composed of data arranged in records or rows with no delimiters. Each data item is assigned a position in the row to distinguish it from other data in the row. This data structure was adopted primarily because it was well-suited for use on mainframe computers. In the NOPR, the Commission expressed the desire to adopt filing requirements which are better suited for use on a personal computer. In this rule, the Commission is requiring that the Form Nos. 2, 2A, 11, and the discount rate reports be filed both on paper and electronically. The Index of Customers will be posted on the pipelines' EBB's, and filed electronically only; no paper copy of the Index of Customers will be required. \96\ASCII, or ``American Standard Code for Information Interchange,'' conveys only letters, punctuation, and certain symbols. It does not convey how the document should be formatted or what fonts to use. A delimited ASCII file is created by keypunching a series of symbols using commas, tab, or some other symbol to designate the space at the end of a word or number (thus, ``tab delimited,'' ``comma delimited,'' etc.) --------------------------------------------------------------------------- In the NOPR, the Commission acknowledged that the changes to the regulations and forms that it was proposing in that NOPR, and in the companion NOPR in Docket No. RM95-3-000, would necessitate modifications to the electronic formats for the affected filings and forms. Thus, to ensure the widest possible input, the Commission directed its staff to convene a technical conference to obtain the participation of the industry and other users of the filed information in designing the electronic filing requirements. On April 4, 1995, the Commission staff held the technical conference to address the electronic filing requirements associated with the proposed rules. Many issues were discussed at the conference, such as whether to require the data to be saved in files in a standard format, such as ASCII, or to allow pipelines to submit electronic data in the format of the applications software they employ;97 whether the appropriate method for transmitting data to the Commission is via diskette, or telecommunications; whether the Commission or the pipelines should disseminate the electronic data, and how dissemination should be accomplished (i.e., on diskette, or via the EBB); and the standardization of data elements. \97\Applications software means proprietary software, such as Lotus, Quattro Pro, Excel, or WordPerfect. --------------------------------------------------------------------------- As a result of oral comments made at the conference, and written comments submitted in this rulemaking, the Commission is able to make a number of decisions related to the electronic filing requirements in this rule. However, other issues still will need to be resolved jointly with the industry. Therefore, the Commission is directing staff to convene a further technical conference, and to work with the industry, as needed, to resolve the outstanding electronic filing issues in both this rule and the Docket No. RM95-3-000 rule. This conference is to be held as soon as possible after the issuance of these rules. The various electronic filing issues raised at the conference, and the comments on those issues, are addressed below. B. Format For Electronic Filings Commenters generally support a change to the current means of filing forms electronically. The Registry identifies three main forms in which data can be delivered electronically, and which allow for consistent presentation and unambiguous cross-correlation: Applications software, such as Lotus, which are best for financial, performance, and other one-to-one reporting subject areas; Comma-delimited ASCII formats, which allow for all PC- based spreadsheet and database software to import the data set forth in this format; and Relational data structures such as electronic data interchange (EDI),98 which are best for one-to-many relationships and reporting areas. \98\Electronic Data Interchange (EDI) is a means by which computers exchange information over communication lines using standardized formats. For example, the capacity release data posted on a pipeline's electronic bulletin board is also available in downloadable files that conform to the standards for EDI promulgated by the American National Standards Institute (ANSI) Accredited Standards Committee (ASC). --------------------------------------------------------------------------- INGAA notes that at the April 4 conference on electronic filings, pipelines recommended that the electronic filing format for most reports in this rulemaking should be platform independent (in other words, able to be used with any hardware), with delimited ASCII formats for numeric files, and Rich Text Format (RTF) for text. Williston Basin and Panhandle support this preference, voiced at the conference, for tab-delimited or comma-delimited ASCII files for electronic filing of numeric data fields. Williston Basin believes that the Commission should eliminate the current flat, non-delimited ASCII submission format, because it is a time consuming and inefficient process. Williston Basin states that tab-delimited formats for numeric submissions would be more efficient, and that these formats are readily producible from all of the current generations of personal computer operating systems and applications software packages.99 \99\Williston Basin is not opposed to submitting electronic data in the application software it uses, provided that numerical data not include formulas and links, and the native application format(s) supported by the Commission is producible from its application software. --------------------------------------------------------------------------- Panhandle asserts that the number of software applications and computer platforms used by applicants, regulatory agencies, and intervenors, and the various releases of such applications used by the participants, calls for the adoption of a ``common denominator'' approach for data transfer, such as delimited ASCII, rather than a particular software application or applications. Panhandle adds that delimited ASCII formats permit columnar data fields to [[Page 53061]] be imported and exported into, and out of, most off-the-shelf software. For text only files, Panhandle and Williston Basin support the RTF recommendation, which permits word files to contain text enhancements, such as underscoring. The Registry adds that text files, which can be read by word processors, are very useful for scanning text, such as direct testimony, tariffs, and descriptions. RTF can be read by AMI-PRO by Lotus, Word by Microsoft, and Wordperfect by Novell. The format retains most of the bold, indentation, tabbing, and paging formats, which can be imported into any of the three applications with a minimum effort for conversion and reformatting. A related issue to electronic filing formats is whether the Commission should develop form-fill software to assist the pipelines to prepare the filings. In the NOPR, the Commission noted its intention to use user-friendly form-fill software. Williston Basin responded in support of a form-fill software approach to preparation of the Form No. 2, if the software package is appropriately designed and tested prior to implementation. A critical requirement for Williston Basin would be data import capabilities allowing the form-fill software to receive data from its software packages. The companion rule in Docket No. RM95-3-000 adopts the use of tab- delimited ASCII for most numeric data, with limited use of spreadsheets for the rate case data. The Commission is adopting a tab-delimited ASCII format for the numeric data submitted electronically in this rulemaking, as well. The Commission is adopting this standard in light of the substantial support it enjoys. The Commission is not adopting in this rule a format for the text data that is filed electronically. RTF for text data enjoys substantial support. The nature of RTF is discussed at greater length in the companion rulemaking. However, the Commission has certain concerns that we wish to have addressed before adopting RTF for text. Thus, the companion rule directs staff to establish a conference to explore further the efficacy of RTF for text data. At the conference, the participants should address alternatives to RTF, if any, and the concerns that: (1) the data be error-free when translated; (2) translation be available in the most popular word processing programs; and (3) RTF text be usable in databases. In light of the industry's support for independence from a particular platform or software, the Commission will not prepare form- fill software for the use of the industry. The data layouts will be determined and edit specifications will be provided as a result of the conference; however, no software for form-fill, edit-checking, or printing will be provided. The industry is free to develop whatever software best meets its needs, and the filing requirements set forth by the Commission. C. Data Requirements The Registry recommends that the collection of information across various reports and filings encourage correlation and comparison. In particular, the Registry notes that: Time periods should be consistent and cross-comparable; Units of measurement should be consistent, and only one energy and volume unit should be employed; Geographic zones (i.e., county and states) should be equated to economic (i.e., rate) zones; Services (firm, interruptible, etc.) should be equated to rate schedules; and Identifiers such as DUNS numbers of customers/contract parties should be consistent. The Registry also suggests that respondents should be required to adhere to the following standards and practices: Standard naming conventions, page numbering, and ordering of fields/contents of spreadsheets; Provision of both values-only, and formulas and values, versions of data files; and Provision of both an edit-enabled and a password locked, edit-protected version of each of the values-only and formulas-only files; there should be no hidden cells.100 \100\The Registry also makes certain recommendations for the electronic filing requirements for rate case data. The Commission is addressing this issue in the companion rule in Docket No. RM95-3- 000. --------------------------------------------------------------------------- The Commission wishes to encourage consistent reporting among different electronic forms and filings. Where possible, the conference participants should come to agreement on standards for reporting common data elements, such as dates. The participants must also explore at the conference what measures would be appropriate for establishing the security of the data, such as locking the file with a password, as suggested by Registry. Further, the participants must discuss certain other general issues, such as those raised by Registry, i.e., file naming conventions, page numbering, ordering of fields/contents, appropriate diskette size and labelling of the diskettes. In addition, other issues common to electronic filing need to be addressed, such as, treatment of footnotes, format for dates, and what the industry considers to be text suitable for RTF. Since we are adopting a tab- delimited ASCII format for numeric files, the Commission is not requiring any of the reports subject to this final rule to be filed in a spreadsheet form. Therefore, the suggestion by Registry that a values-only version and a values and formulas version of the spreadsheet data be submitted is not an issue. The Registry recommends adding a number of data elements to the electronic version of the forms and/or filings. The Commission is requiring that the electronic filing be a faithful representation of the data requirements set forth in the form or filing. The electronic filing requirements will not be expanded to include data not specified in the paper version of the form or enumerated in the regulations. For example, where the rate schedule number is reported, it should not be construed as also requiring the type of service to be reported, unless specifically stated in the form or regulations. D. Submission and Dissemination of Electronic Data With respect to the submission, or filing, of the electronic data, INGAA states that, at a minimum, pipelines would prefer to file on a diskette, but are willing to investigate communication of data through CD-ROM or telecommunications. INGAA views EDI applications for certain reports as an option on a voluntary basis, where it can be shown to be cost effective. In contrast, Williston Basin supports the use of telecommunications medium for the submission of electronically filed data. While Williston Basin prefers telecommunications submission, if physical formats are used for submission, Williston Basin supports CD-ROM as an alternative to diskettes. Current electronic filings are commonly submitted on diskette, as noted above. Filing on diskette continues to enjoy substantial support in the comments. Thus, the standard means of submitting data to the Commission will be by diskette. However, the Commission will also permit submission on CD-ROM.101 \101\Technical specifications for CD-ROM submission will appear in the electronic filing instructions for each individual form or filing. --------------------------------------------------------------------------- The Commission does not currently permit the filing of electronic data through telecommunications. The Commission is not yet prepared to accept data through telecommunications. Before adopting [[Page 53062]] filing by telecommunications, the Commission would need to put the proper hardware and software in place, and work out other issues. For example, section 385.2005 requires filings with the Commission to be signed. Signatures are difficult to reproduce electronically.102 Such issues can be addressed at the conference to be convened by staff. Therefore, the Commission will not adopt submission by telecommunications until all of the issues are resolved. \102\In the past, the Commission received purchased gas adjustment (PGA) schedules in electronic form only. The diskette, tape, or tape cartridge containing the PGA schedules was accompanied by a letter of transmittal. The signature on the letter of transmittal met the requirements of section 385.2005. --------------------------------------------------------------------------- With respect to the dissemination of the electronically filed data, INGAA and Williston Basin support the goal of increased use of electronic dissemination of reported data by the Commission, and the elimination of hardcopy dissemination whenever practical. Panhandle, too, supports the industry preference that the Commission be the primary disseminator of filed information. However, Williston Basin and INGAA urge the Commission to put procedures in place to ensure the integrity of the electronic filing, and the security of any confidential data. AGD suggests that the Commission require pipelines to post their Form No. 2 filings, (including backup information) on their EBBs. The Registry suggests that the Form No. 2 data be made available to the public in hardcopy printout of the electronic version, and in compressed files on 3.5'' 1.44 MB disks, in edit-protected mode in the comma-delimited format in which it was filed. It states that such Form No. 2 data should be available for the price of reproduction, plus a handling charge. The Registry also suggests that the diskette should contain the record layout and description, so that users can import the company-supplied data, and know how the fields correlate to the Form No. 2 data with which they are familiar. In addition, the Registry recommends that the uncompressed file names should appear on the label or sleeve wrapper of the diskette. The Registry suggests that the market monitoring information, such as the Index of Customers and the discount rate reports, be made available to the public in the following forms: Via EDI formatted downloads from the pipeline's EBB or VAN, for which the pipeline has agreed to pay its portion of the charges associated with using such means of request and delivery; Via hard copy printout of a translated EDI file available from the Commission; and Via EDI formatted files on 3.5'' 1.44 MB disks in write- protected mode available from the Commission, with a batch file which prompts the user for sender and receiver IDs for the IS and GS levels which, once supplied, enables the user to translate the file with their EDI translator. Conversely, Williston Basin states that although it may support EDI for the transmission of certain frequent filings, it believes EDI would not be a cost-effective option based on the frequency and nature of the data being submitted. It is the Commission's intention to disseminate all electronically filed data to the extent the file size is practical for downloading. Dissemination would be accomplished through the Commission's Gas Pipeline Data bulletin board system. Files on the bulletin board system are currently compressed for faster downloading. The data layouts for each electronic filing are currently made available through this system. This practice will continue. Since the Form No. 2 will be available on the Commission's bulletin board for all companies, we will not require the pipelines to keep a copy of Form No. 2 on the pipeline's own bulletin board. Given the reduction in the number of data elements to be submitted in the Index of Customers and the discount rate reports, the Commission does not believe EDI is necessary for transmission of the data. Further, a delimited ASCII file would be easier to manipulate for many members of the public using the Commission's bulletin board. Therefore, the Commission will not adopt EDI for the Index of Customers or discount rate data. E. Finalization of Electronic Requirements and Procedural Considerations Williston Basin, Panhandle, INGAA, and AGA urge the Commission to postpone finalization of electronic requirements until such time as a final order is issued, and sufficient time has been allowed beyond issuance to develop appropriate procedures, formats, and software. Panhandle notes that pipeline and commercial software developers would need time to develop, test, and place into production, the systems that generate the reports required by the rule. In addition, Panhandle states that it will be necessary to map data points for the new reporting requirements. Panhandle is concerned that sufficient time be allotted for the development, testing, and implementation of the applications that will be used for generating electronic versions of filed reports. In the same vein, AGA urges the Commission to consider designing the software to operate on local area networks. The Registry recommends that FERC set additional schedules and a procedural process, including another informal technical conference, to handle the technical aspects of data layout, content, and format. The Registry suggests that, at the conference, the Commission should establish three working groups, their chairs, their agendas, and their individual jurisdiction. The Registry proposes a rate case working group dealing with spreadsheets, file naming, formats, and data protection; a Form No. 2 working group dealing with data field naming and record layout for the comma-delimited filing format; and a EDI, market monitoring, and market confidence working group dealing with EDI formats associated with the Index of Customers and discount reports. The Registry further proposes a detailed procedural process and timetable for resolution of the issues. The Registry also urges the Commission to adopt a flexible implementation and compliance schedule for the Index of Customers. Specifically, it proposes that the Commission should set beginning and end dates for compliance with the electronic index (for example six months), and that the pipelines submit first, second, and third choices for the month in which they wish to complete implementation. The Commission would then select a schedule of compliance for the pipelines based on these choices, using a first-come, first-served principle. In view of the need for sufficient time to implement the new requirements, INGAA suggests the changes to Form Nos. 2, 2-A, and 11 should be effective on the January 1st that falls at least 180 days after publication of the final rule in the Federal Register. Contrary to what was stated in the NOPR, this rule does not finalize all of the electronic filing requirements. As desired by the commenters, the Commission is allowing adequate time subsequent to the issuance of this rule for the technical aspects of the electronic filing requirements to be finalized. As we have stated, we are convening another joint informal technical conference in the two companion rulemaking proceedings for this purpose. The Commission staff will convene the conference as soon as [[Page 53063]] possible after the issuance of the rules. The procedures to be subsequently followed will be discussed, and if possible, established, at that conference. The Commission discusses the appropriate filing date for the revised Form No. 2 elsewhere in this rule. The revised Form No. 2 cannot be filed electronically until all of the electronic filing instructions have been finalized. We are not requiring that pipelines file the revised Form Nos. 2 and 2-A, either in paper or electronically, until April 1997. Thus, there should be more than adequate time to establish and put into place the new electronic filing requirements prior to the filing of the revised Form Nos. 2 and 2-A. The Form Nos. 2 and 2-A for the calendar year 1995, filed in 1996, must be filed under the old filing requirements, including the old electronic filing requirements. Given the reduction in the scope of the Form No. 11 and the Index of Customers, and the elimination of the changes to the discount rate report, the Commission does not anticipate a lengthy delay in implementing the electronic filing requirements for those reports. We anticipate that the electronic filing requirements will be finalized prior to the first filing of the Form No. 11. If not, the pipeline must file only the paper copy of the revised Form No. 11. In any event, a final schedule for the implementation of the electronic filing requirements must be worked out among the participants of the conference. X. Environmental Analysis The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.103 The Commission has categorically excluded certain actions from these requirements as not having a significant effect on the human environment.104 The action taken here is procedural in nature and therefore falls within the categorical exclusions provided in the Commission's regulations.105 Therefore, neither an environmental impact statement, nor an environmental assessment is necessary, and will not be prepared in this rulemaking. \103\Order No. 486, Regulations Implementing the National Environmental Policy Act, 52 FR 47897 (Dec. 17, 1987), FERC Statutes and Regulations, Regulations Preambles 1986-1990 para.30,783 (1987). \104\18 CFR 380.4. \105\See 18 CFR 380.4(a)(2)(ii). --------------------------------------------------------------------------- XI. Reporting Flexibility Certification The Regulatory Flexibility Act (RFA)106 generally requires the Commission to describe the impact that a final rule will have on small entities or to certify that the rule will not have a significant economic impact on a substantial number of small entities. An analysis is not required if a final rule will not have such an impact.107 Most gas companies to whom the final rule applies do not fall within the definition of a ``small entity.''108 Consequently, pursuant to section 605(b) of the RFA, the Commission certifies that the final rule will not have a significant impact on a substantial number of small entities. \106\5 U.S.C. 601-612. \107\5 U.S.C. 605(b). \108\Section 601(c) of the RFA defines a ``small entity'' as a small business, a small not-for-profit enterprise, or a small governmental jurisdiction. A ``small business'' is defined by reference to section 3 of the Small Business Act as an enterprise which is ``independently owned and operated and which is not dominant in its field of operation.'' 15 U.S.C. 632(a). --------------------------------------------------------------------------- XII. Information Collection Statement The Office of Management and Budget's (OMB) regulations109 require that OMB approve certain information and recordkeeping requirements imposed by an agency. The information collection requirements in this final rule are contained in the following: \109\5 CFR 1320.13. --------------------------------------------------------------------------- FERC Form No. 2 ``Annual Report of Major Natural Gas Companies'' (1902-0028); FERC Form No. 2-A, ``Annual Report of Nonmajor Natural Gas Companies'' (1902-0030); FERC Form No. 11, ``Natural Gas Pipeline Company Monthly Statement'' (1902-0032); FERC-549, ``Gas Pipeline Rates: Natural Gas Policy Act Title III Transactions'' (1902-0086); FERC-549B, ``Gas Pipeline Rates: Capacity Release Information'' (1902-0169); FERC-576, ``Reports on Pipeline Systems Service Interruptions'' (1902-0004); FERC Form No. 8, ``Underground Gas Storage Report'' (1902-0026); and FERC Form No. 14, ``Annual Report for Importers and Exporters of Natural Gas'' (1902-0027). By this rule, the Commission is modernizing its regulations to reflect the current regulatory environment that it instituted with Order No. 636 and the restructuring of the natural gas industry. Specifically, the Commission is revising its regulations to focus on transportation services instead of pipeline sales activities. The revised filing requirements will improve the internal support of a pipeline's filing, reduce the filing burden for all parties, and facilitate pipeline reporting requirements. The Commission's Office of Pipeline Regulation uses the data in rate proceedings to review rate and tariff changes by natural gas companies for the transportation of gas and for general industry oversight under the Natural Gas Act. The Commission's Office of Economic Policy also uses this data in its analysis of interstate natural gas pipelines. The Commission is submitting to the Office of Management and Budget a notification of these collections of information. Under the 1995 Recordkeeping Reduction Act, each of the forms being revised or retained in this rule will carry the following notice: ``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.'' Interested persons may obtain information on these reporting requirements by contacting the Federal Energy Regulatory Commission, Washington, DC 20426 [Attention: Michael Miller, Information Services Division, (202) 208-1415]. Comments on the requirements of this rule can be sent to the Office of Information and Regulatory Affairs of OMB, Washington, D.C. 20503, (Attention: Desk Officer for Federal Energy Regulatory Commission) FAX: (202) 395-5167. XIII. Effective Date and Transition Provisions This Final Rule is effective November 13, 1995 except for the changes to the Uniform System of Accounts and Form Nos. 2, 2-A, and 11, which will be effective January 1, 1996. The NOPR proposed that the changes to the Uniform System of Accounts and Form Nos. 2 and 2-A be made effective January 1, 1995. The remainder of the proposed rule, including changes to Form No. 11, was proposed to be effective 30 days after publication in the Federal Register. Numerous commenters suggested that the effective dates for these changes be delayed and implemented on a prospective basis. INGAA, ANR, MRT, and El Paso suggest that the effective date for the parts of the final rule that make changes to the Uniform System of Accounts and Form Nos. 2 and 2-A should be the January 1 that falls at least 180 days after publication of the final rule in the Federal Register. Other commenters suggest other prospective effective dates: (1) January 1 at least 90 days subsequent to issuance of the final [[Page 53064]] rule;\110\ January 1 following the year of issuance of the final rule;\111\ and (3) January 1, 1996.\112\ \110\AGA. \111\Consumers Power. \112\KN. --------------------------------------------------------------------------- Panhandle suggests that, prior to the issuance of the final rule on changes in the storage accounting requirements, the Commission conduct a field test of the final proposed storage accounting guidelines with several interstate pipelines for two or three months to thoroughly evaluate the associated benefits and costs so that necessary revisions can be made. Panhandle also suggests that a technical conference would be helpful. AGA and Consumers Power suggest that all other revisions and changes not be effective until 90 days after issuance of the final rule. MRT seeks clarification that the remaining changes are to take effect only after publication of the final rule in the Federal Register and not after publication of the NOPR. In response to the comments filed, as stated above, the Commission is moving the effective date for the changes to the Uniform System of Accounts and Form Nos. 2 and 2-A to January 1, 1996. In addition, to ensure a seamless transition to the new Form No. 11 filing requirement, the Commission will make the changes to Form No. 11 effective January 1, 1996. All other changes adopted in the final rule will become effective 30 days after the final rule is published in the Federal Register.\113\ The Commission believes that 30 days is an appropriate time period. \113\In response to Texas Intrastates, this includes the NGPA Section 311 material. --------------------------------------------------------------------------- The Commission believes the January 1, 1996 effective date for the revisions to the Uniform System of Accounts and Form Nos. 2, 2-A, and 11 will provide adequate time for pipelines to adapt to the requirements of the final rule and to make the necessary modifications to their recordkeeping systems. Since the Commission is permitting use of the fixed asset and the inventory methods of accounting for system gas and has simplified our accounting requirements for encroachments and replacements of system gas under the fixed asset model, the Commission sees no need to conduct a field test or to hold a technical conference on our new storage accounting requirements. A number of commenters raise a variety of implementation issues resulting from the adoption of changes to Uniform System of Accounts and Form Nos. 2 and 2-A in the final rule. INGAA, Panhandle, and ANR ask the Commission to waive the requirement to report prior year comparative data for the first year of operation under the new requirements. They argue that they need sufficient time to modify pipeline electronic formats and various accounting and reporting systems. AGA suggests that the comparative data requirement for the Statement of Retained Earnings and Statement of Cash Flows should be delayed for one year to avoid restating the prior year and that sufficient time should be provided to modify electronic hardware (local area networks). Consumers Power suggests that the Commission consider adopting transition provisions, which delay the comparative data requirement, so that prior data would not have to be restated. Since the Commission has postponed the effective date of the changes to the accounting and Form Nos. 2 and 2-A reporting requirements, pipelines will not have to recompute or restate amounts related to 1995 transactions. In response to concerns raised by commenters about the need to restate prior year's account balances, the Commission will not require such a restatement for FERC accounting and Form Nos. 2 and 2-A reporting purposes. To do so, would result in retroactive application of the accounting and Form Nos. 2 and 2-A rule changes contained in the final rule and would be inconsistent with the accounting and Forms Nos. 2 and 2-A reporting requirements in effect through December 31, 1995. Rather than waiving the reporting of comparative data or adopting transitional reporting pages, the Commission will permit pipelines to use the previous data (1995) on the Form No. 2 or Form No. 2-A reports for the 1996 reporting year filed in 1997. The pipelines must footnote the place in the report where the previous year's data is reported for the item.\114\ However, no amounts need to be reported for the previous year on schedules 302-307. \114\For example, the footnote should indicate in which Account No. 489 subaccount the 1995 total for revenues from the transportation of gas of others is reported. --------------------------------------------------------------------------- List of Subjects 18 CFR Part 2 Administrative practice and procedure, Electric power, Natural gas, Pipelines, Reporting and recordkeeping requirements. 18 CFR Part 157 Administrative practice and procedure, Natural gas, Reporting and recordkeeping requirements. 18 CFR Part 158 Administrative practice and procedure, Natural gas, Reporting and recordkeeping requirements, Uniform System of Accounts. 18 CFR Part 201 Natural gas, Reporting and recordkeeping requirements, Uniform System of Accounts. 18 CFR Part 250 Natural gas, Reporting and recordkeeping requirements. 18 CFR Part 260 Natural gas, Reporting and recordkeeping requirements. 18 CFR Part 284 Continental shelf, Natural gas, Reporting and recordkeeping requirements. 18 CFR Part 381 Electric power plants, Electric utilities, Natural gas Reporting and recordkeeping requirements. 18 CFR Part 385 Administrative practice and procedure, Electric power, Penalties, Pipelines, Reporting and recordkeeping requirements. By the Commission. Lois D. Cashell, Secretary. In consideration of the foregoing, the Commission is amending Parts 2, 157, 158, 201, 250, 260, 284, 381, and 385, Chapter I, Title 18, Code of Federal Regulations, as set forth below. PART 2--GENERAL POLICY AND INTERPRETATIONS 1. The authority citation for part 2 continues to read as follows: Authority: 15 U.S.C. 717-717w, 3301-3432; 16 U.S.C. 791a-825r, 2601-2645; 42 U.S.C. 4321-4361, 7101-7352. Sec. 2.104 [Amended] 2. In Sec. 2.104(a), the words ``(other than under the grandfather provisions of Sec. 284.105 or Sec. 284.223)'' are removed. PART 157--APPLICATIONS FOR CERTIFICATES OF PUBLIC CONVENIENCE AND NECESSITY AND FOR ORDERS PERMITTING AND APPROVING ABANDONMENT UNDER SECTION 7 OF THE NATURAL GAS ACT 3. The authority citation for part 157 continues to read as follows: Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7101-7352. [[Page 53065]] Sec. 157.53 [Amended] 4. In Sec. 157.53, the words ``Drilling of gas or oil wells and testing'' are removed from the section heading and the word ``Testing'' is added in their place, the words ``drilling of gas or oil wells or for the use in the'' are removed from paragraph (a), and the words ``well or the'' are removed from paragraph (b). PART 158--ACCOUNTS, RECORDS, AND MEMORANDA 5. The authority citation for part 158 is revised to read as follows: Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7102-7352. 6. Section 158.10 is revised to read as follows: Sec. 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. 7. Section 158.11 is revised to read as follows: Sec. 158.11 Report of certification. Each natural gas company not classified as Class C or Class D prior to January 1, 1984 shall file with the Commission a letter or report of the independent accountant certifying approval, together with the original and each copy of the filing of the applicable Annual Report, Form No. 2 or Form No. 2-A, covering the subjects and in the format prescribed in the General Instructions of the applicable Annual Report. The letter or report shall also set forth which, if any, of the examined schedules do not conform to the Commission's requirements and shall describe the discrepancies that exist. The Commission shall not be bound by the certification of compliance made by an independent accountant pursuant to this paragraph. 8. In section 158.12, the words ``The Commission will not recognize any certified public accountant or public accountant through December 31, 1975, who is not in fact independent. Beginning January 1, 1976, and each year thereafter, the'' are removed and the word ``The'' is added in their place. PART 201--UNIFORM SYSTEM OF ACCOUNTS PRESCRIBED FOR NATURAL GAS COMPANIES SUBJECT TO THE PROVISIONS OF THE NATURAL GAS ACT 9. The authority citation for Part 201 continues to read as follows: Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7101-7352, 7651-7651o. 10. In Part 201, Definitions, Definitions 13, 15, 16, 32B, 38, and 39 are amended by removing the words ``in the case of Major natural gas companies,'' and Definition 29 is amended by removing the words ``(Major natural gas companies).'' 11. In Part 201, General Instructions, paragraph 1 is revised to read as follows: General Instructions 1. Applicability. Each natural gas company must apply the system of accounts prescribed by the Commission. * * * * * 12. In Part 201, General Instructions, paragraphs 8, 12, 14, 15, and 16, the words ``(Major natural gas companies)'' are removed at the end of each heading, and in the heading for paragraph 21, the words ``(Nonmajor natural gas companies)'' are removed. 13. In Part 201, Gas Plant Instructions, paragraph 1, the words ``Classification of utilities (Major natural gas companies)'' are removed from the heading and the words ``Classification of gas plant at the effective date of the system of accounts'' are added in their place. 14. In Part 201, Gas Plant Instructions, paragraph 3, introductory text, the words ``For Major natural gas companies'' are removed and the words ``A. The'' are added in their place; the words ``(Major and Nonmajor Natural Gas Companies)'' are removed from paragraphs 3A.(17) and 3A.(19), and paragraph 3B. is removed. 15. In Part 201, Gas Plant Instructions, paragraph 4C., the words ``For Major natural gas companies, the'' are removed and the word ``The'' is added in their place. 16. In Part 201, Gas Plant Instructions, paragraph 6A., the words ``(For Nonmajor companies, account 404, Amortization of Limited-Term Gas Plant)'' are removed. 17. In Part 201, Gas Plant Instructions, paragraphs 7C. and 7E., the words ``or in the case of Major companies,'' are removed. 18. In Part 201, Gas Plant Instructions, paragraph 7D., the words ``In the case of Major companies, a parcel,'' are removed and the words ``A parcel'' are added in their place. 19. In Part 201, Gas Plant Instructions, paragraph 7G., the words ``in the case of Major companies,'' are removed. 20. In Part 201, Gas Plant Instructions, paragraph 7H., the words ``(For Major companies, see,'' are removed and the word ``(See'' is added in its place, and the last two sentences of the parenthetical are removed and the words ``, and account 797, Abandonment, leases'' are added in their place. 21. In Part 201, Gas Plant Instructions, paragraph 8G., the words ``(Major natural gas companies)'' are removed at the end of Items 2, 6, 11, 12, 18, 19, 22, 28, 29, 32, 35, 36, 39, 40, 41, 42, 44, 45, 47, 49, 52, 53, 55, 58, 60, 61, 62, 64, 65, 66, and 67. 18. In Part 201, Gas Plant Instructions, paragraph 10E., the words ``or in the case of Major companies,'' immediately following the words ``Gas Plant Held for Future Use'' are removed. 22. In Part 201, Gas Plant Instructions, paragraph 10F., the words ``(account 110, Accumulated Provision for Depreciation, Depletion and Amortization of Gas Utility Plant, in the case of Nonmajor companies)'' and the words ``(account 110 for Nonmajor companies)'' are removed. 23. In Part 201, Gas Plant Instructions, paragraph 10G., the words ``In the case of Major companies, the accounting for'' are removed and the words ``The accounting for'' are added in their place. 24. In Part 201, Gas Plant Instructions, paragraph 11C, the words ``In the case of Major companies, each utility'' are removed and the words ``Each utility'' are added in their place. 25. In Part 201, Gas Plant Instructions, paragraph 12, the words ``(105.1, Production Properties Held for Future Use, in the case of Major companies)'' are removed and the words ``105.1, Production Properties held for Future Use,'' are added in their place, and the words ``(Major Companies)'' in the note are removed. 26. In Part 201, Gas Plant Instructions, paragraph 14, the words ``(Major natural gas companies)'' are removed at the end of the heading. 27. In Part 201, Gas Plant Instructions, paragraph 15A., the words ``(account 180, Other Deferred Debits, in the case [[Page 53066]] of Nonmajor companies)'' are removed from paragraph A.(1), the words ``(the amounts recorded in account 186 shall be cleared to the appropriate plant accounts, in the case of Nonmajor companies)'' are removed from paragraph A.(2), and the words ``(Account 180 in the case of Nonmajor companies)'' are removed from paragraph A.(3). 28. In Part 201, Gas Plant Instructions, paragraph 16 is removed. 29. In Part 201, Operating Expense Instructions, paragraph 1, the words ``(Major natural gas companies)'' at the end of the heading are removed. 30. In Part 201, Balance Sheet Chart of Accounts, and Balance Sheet Accounts, the words ``(Major only)'' at the end of the headings of Accounts 103, 105.1, 106, 108, 111, 115, 117, 123, 123.1, 125, 126, 128, 131 through 135, 151 through 153, 155, 156, 163, 164.3, 166, 167, 171 through 173, 183.1, 183.2, 184, 185, 188, 202, 203, 205 through 210, 216.1, 222, 238 through 241 are removed. 31. In Part 201, Balance Sheet Chart of Accounts, and Balance Sheet Accounts, Accounts 103.1, 110, 117, 129, 130, and 218 are removed, and in Balance Sheet Chart of Accounts, Accounts 117.1 through 117.4 and their respective titles are added to read as follows: Balance Sheet Chart of Accounts * * * * * 117.1 Gas stored-Base gas. 117.2 System balancing gas. 117.3 Gas stored in reservoirs and pipelines-noncurrent. 117.4 Gas owed to system gas. * * * * * 32. In Part 201, Balance Sheet Accounts, Account 116, paragraph A, the words ``For major companies, see'' are removed, and the word ``See'' is added in their place. 33. In Part 201, Balance Sheet Accounts, Account 117 is removed, and new Special Instructions and Accounts 117.1, 117.2, 117.3, and 117.4 are added to read as follows: Balance Sheet Accounts * * * * * Special Instructions to Accounts 117.1, 117.2 and 117.3 The investment in and use of system gas included in Account 117.1, Gas Stored--Base Gas, and Account 117.2, System Balancing Gas, may be accounted for using either the ``fixed asset'' method or an ``inventory'' method as set forth below. The cost of stored gas included in Account 117.3 must be accounted for using an inventory method. (a) Inventory Method--Gas stored during the year must be priced at cost according to generally accepted methods of cost determination consistently applied from year to year. Transmission expenses for facilities of the utility used in moving the gas to the storage area and expenses of storage facilities cannot be included in the inventory of gas except as may be authorized or directed by the Commission. Withdrawals of gas must be priced using the first-in-first-out, last-in-first-out, or weighted average cost method, provided the method adopted by the utility is used consistently from year to year and appropriate inventory records are maintained. Approval of the Commission must be obtained for any other pricing method, or change in the pricing method adopted by the utility. (b) Fixed Asset Method--The cost of system gas designated by the Commission as available for transmission load balancing and other uses associated with maintaining efficient transmission operations must be determined from the book balances on the date of adoption of the ``fixed asset'' method. If at the date of adoption, the actual volumes are less than the maximum volumes authorized by the Commission, the deficient volumes are to be priced at the current market price with an equal amount being credited to Account 117.4. Withdrawals that encroach upon the designated volumes must be priced at an amount equal to the current market price of gas available to the utility. Account 808.1, Gas withdrawn from storage--debit, must be charged with such amount and Account 117.4, Gas owed to system gas, credited. For the purpose of these instructions, current market price is the delivered spot price of gas in the utility's supply area, as published in a recognized industry journal. The publication used must be the same one identified in the utility's tariff for use in its cash-out provision, if it has one. If the utility does not have a cash-out provision, it must use one publication consistently and identify the publication in its records. When replacement of the gas is made, the amount carried in Account 117.4 for such volumes must be cleared and Account 808.2, Gas delivered to storage--credit. Any difference between the utility's cost of replacement gas volumes and the amount cleared from Account 117.4 must be recognized as a gain in Account 495, Other gas revenues, or as a loss in Account 813, Other gas supply expenses, with contra entries to Account 808.2. Gas owned by the utility and injected into its system will be deemed to satisfy any encroachment on system gas first before any other use. 117.1 Gas stored-base gas. This account is to include the cost of recoverable gas volumes that are necessary, in addition to those volumes for which cost are properly includable in Account 101, Gas plant in service, to maintain pressure and deliverability requirements for each storage facility. Nonrecoverable gas volumes used for this purpose are to be recorded in Account 352.3, Nonrecoverable natural gas. For utilities using the fixed asset method of accounting, the cost of base gas applicable to each gas storage facility shall not be changed from the amount initially recorded except to reflect changes in volumes designated as base gas. If an inventory method is used to account for gas included herein, the utility may, at its election, price withdrawals in accordance with the instructions to Account 117.4. 117.2 System balancing gas. This account is to be used to record the cost of system gas designated as available for transmission load balancing (including no- notice transportation) and other uses associated with maintaining efficient transmission operations other than gas properly recordable in Account 117.1 or the plant accounts. Detailed records must be kept separately identifying volumes and unit prices of system gas held in underground storage facilities and held in pipelines. For utilities using fixed asset accounting, the cost initially recorded herein cannot be changed except for adjustments to volumes designated as system gas. Encroachments upon system gas must be accounted for in accordance with the instructions to Account 117.4, Gas owed to system gas. 117.3 Gas stored in reservoirs and pipelines--noncurrent. This account is to include the cost of stored gas owned by the utility and available for sale or other purposes. Gas included in this account must be accounted for using an inventory method in accordance with the Special Instructions to Accounts 117.1, 117.2, and 117.3 above. 117.4 Gas owed to system gas. This account is to be used to record encroachments of system gas under the fixed asset method. This account may also be used to record encroachments of base gas for utilities electing to use an inventory method of accounting for system gas. Utilities may revolve [[Page 53067]] cumulative net imbalances, net all transactions, and record one monthly entry with one month-end price for valuation purposes. * * * * * 34. In Part 201, Balance Sheet Accounts, Account 154, the words ``For Nonmajor utilities, this account shall include the cost of fuel on hand and unapplied materials and supplies (except meters and house regulators). For both Major and Nonmajor utilities, it'' are removed from the introductory text of paragraph A and the words ``This account'' are added in their place, paragraph C and Note B are removed, Note A is redesignated Note, and the words ``they may be charged to a stores expense clearing account (account 163, Stores Expenses Undistributed, in the case of Major Utilities), and distributed therefrom to the appropriate accounts'' in redesignated Note are removed and the words ``they shall be charged to account 163, Stores expenses Undistributed'' are added in their place. 35. In Part 201, Balance Sheet Accounts, Account 164.1 is revised to read as follows: Balance Sheet Accounts * * * * * 164.1 Gas stored--current. This account shall be debited with such amounts as are credited to Account 117.2, System balancing gas, (for utilities using an inventory method of accounting for system gas) and Account 117.3, Gas Stored in Reservoirs and Pipelines-Noncurrent, to reflect classification for balance sheet purposes of such portion of the inventory of gas stored as represents a current asset according to conventional rules for classification of current assets. Note: It shall not be considered conformity to conventional rules of current asset classification if the amount included in this account exceeds an amount equal to the cost of estimated withdrawals of gas from storage within the 24-month period from date of the balance sheet, or if the amount represents a volume of gas which, in fact, could not be withdrawn from storage without impairing pressure levels needed for normal operating purposes. * * * * * 36. In Part 201, Balance Sheet Accounts, Accounts 164.2, paragraph D and 164.3, paragraph D, the words ``Mcf'' and ``Mcf (or Btu),'' respectively, are removed, and the words ``Dth'' are added in their place. 37. In Part 201, Balance Sheet Accounts, Account 174, the current text is designated paragraph A, and a paragraph B is added to read as follows: Balance Sheet Accounts * * * * * 174 Miscellaneous current and accrued assets. * * * * * B. The utility is to include in a separate subaccount amounts receivable for gas in unbalanced transactions where gas is delivered to another party in exchange, load balancing, or no-notice transportation transactions. (See Account 806.) If the amount receivable is settled by other than gas, Account 495, Other Gas Revenues must be credited or Account 813, Other Gas Supply Expenses, charged for the difference between the amount of the consideration received and the recorded amount of the receivable settled. Records are to be maintained so that there is readily available for each party entering gas exchange, load balancing, or no-notice transportation transactions, the quantity and cost of gas delivered, and the amount and basis of consideration received, if other than gas. * * * * * 38. In Part 201, Balance Sheet Accounts, Account 186, the words ``For Major companies, this account shall'' are removed from paragraph A, and the words ``This account shall'' are added in their place, paragraph B is removed, paragraph C is redesignated as paragraph B, and all the words in parenthesis in redesignated paragraph B are removed. 39. In Part 201, Balance Sheet Accounts, in the Note following Account 204, the words ``(For Nonmajor companies, account 211, Miscellaneous Paid-In Capital)'' are removed. 40. In Part 201, Balance Sheet Accounts, Account 211, the words ``(In the case of Nonmajor companies, this account shall be kept so as to show the source of the credits includible herein)'' are removed, the ITEMS section and Note B are removed, Note A is redesignated Note, and the words ``(Major companies)'' are removed from the heading of redesignated Note. 41. In Part 201, Balance Sheet Accounts, Account 242 is revised to read as follows: Balance Sheet Accounts * * * * * 242 Miscellaneous current and accrued liabilities. A. This account shall include the amount of all other current and accrued liabilities not provided for elsewhere appropriately designated and supported as to show the nature of each liability. B. The utility is to include in a separate subaccount amounts payable for gas in unbalanced transactions where gas is received from another party in exchange, load balancing, or no-notice transportation transactions. (See Account 806.) If the amount payable is settled by other than gas, Account 495, Other Gas Revenues, must be credited or Account 813, Other gas supply expenses, charged for the difference between the amount of the consideration paid and the recorded amount of the payable settled. Records are to be maintained so that there is readily available for each party entering gas exchange, load balancing, or no-notice transportation transactions, the quantity and cost of gas received and the amount and basis of consideration paid if other than gas. * * * * * 42. In Part 201, Gas Plant Chart of Accounts and Gas Plant Accounts, the words ``(Major only)'' at the end of each title of Accounts 363, 363.1 through 363.4, and 364.1 through 364.8 are removed. 43. In Part 201, Gas Plant Accounts, Accounts 302, paragraph C, and 303, paragraph B, the words ``(For Nonmajor Companies; account 110, Accumulated Provisions for Depreciation, Depletion and Amortization of Gas Utility Plant)'' following the words ``Gas Utility Plant'' are removed. 44. In Part 201, Gas Plant Accounts, Account 352.3, paragraph B is revised to read as follows: Gas Plant Accounts * * * * * 352.3 Nonrecoverable natural gas. * * * * * B. Such nonrecoverable gas shall be priced at cost according to generally accepted methods of cost determination consistently applied. (See the Special Instructions to Accounts 117.1, 117.2, and 117.3. * * * * * 45. In Part 201, Income Chart of Accounts and Income Accounts, Accounts 403, 404.1, 404.2, 404.3, and 418.1, the words ``(Major only)'' are removed from the end of the headings. 46. In Part 201, Income Chart of Accounts, Accounts 403.1 and 404 are removed. 47. In Part 201, Income Accounts, Accounts 421.1 and 421.2, the words ``(Major only)'' are removed. 48. In Part 201, Operating Revenue Chart of Accounts, Account 489 and its respective title is removed, and Accounts 489.1 through 489.4 and their respective titles are added to read as follows: [[Page 53068]] Operating Revenue Chart of Accounts * * * * * 489.1 Revenues from transportation of gas of others through gathering facilities. 489.2 Revenues from transportation of gas of others through transmission facilities. 489.3 Revenues from transportation of gas of others through distribution facilities. 489.4 Revenues from storing gas of others. * * * * * 49. In Part 201, Operating Revenue Chart of Accounts and Operating Revenue Accounts, Account 482, the words ``(Major only)'' are removed at the end of the headings. 50. In Part 201, Operating Revenue Accounts, Account 481, paragraph C, the words ``(Major companies)'' are removed from the introductory text, and the word ``Mcf'' is removed and the word ``Dth'' is added in its place each time it appears. 51. In Part 201, Operating Revenue Accounts, Account 488, Item 3, the words ``For Major Companies, see,'' are removed and the word ``See'' is added in its place. 52. In Part 201, Operating Revenue Accounts, Account 489 is removed, and new Accounts 489.1, 489.2, 489.3, and 489.4 are added to read as follows: Operating Revenue Accounts * * * * * 489.1 Revenues from transportation of gas of others through gathering facilities. This account includes revenues from transporting gas for other companies through the gathering facilities of the utility. 489.2 Revenues from transportation of gas of others through transmission facilities. This account includes revenues from transporting gas for other companies through the transmission facilities of the utility. 489.3 Revenues from transportation of gas of others through distribution facilities. This account includes revenues from transporting gas for other companies through the distribution facilities of the utility. 489.4 Revenues from storing gas of others. This account includes revenues from storing gas for other companies. * * * * * 53. In Part 201, Operating Revenue Accounts, Account 491, paragraph B is revised to read as follows: Operating Revenue Accounts * * * * * 491 Revenues from natural gas processed by others. * * * * * B. The records supporting this account must be maintained so that full information concerning determination of the revenues will be readily available concerning each processor of gas of the utility, including as applicable (a) The Dth of gas delivered to such other party for processing, (b) the Dth of gas received back from the processor, (c) the field, general production area , or other source of the gas processed, (d) Dth of gas used for processing fuel, etc., which is chargeable to the utility, (e) total gallons of each product recovered by the processor and the utility's share thereof, (f) the revenues accruing to the utility, and (g) the basis of determination of the revenues accruing to the utility. Such records shall be maintained even though no revenues are derived from the processor. 54. In Part 201, Operating Revenue Accounts, Account 495 is revised to read as follows: Operating Revenue Accounts * * * * * 495 Other gas revenues. This account includes revenues derived from gas operations not includible in any of the foregoing accounts. Items 1. Commission on sale or distribution of gas of others when sold under rates filed by such others. 2. Compensation for minor or incidental services provided for others such as customer billing, engineering, etc. 3. Profit or loss on sale of material and supplies not ordinarily purchased for resale and not handled through merchandising and jobbing accounts. 4. Sales of steam, water, or electricity, including sales or transfers to other departments of the utility. 5. Miscellaneous royalties received. 6. Revenues from dehydration and other processing of gas of others, except products extraction where products are received as compensation and sales of such are includible in account 490, Sales of Products Extracted From Natural Gas, and except compression of gas of others, revenues from which are includible in accounts 489.1, 489.2, or 489.3, Revenues from Transportation of Gas of Others. 7. Include in a separate subaccount, revenues in payment for rights and/or benefits received from others which are realized through research, development, and demonstration ventures. 8. Include in a separate subaccount, gains on settlements of imbalance receivables and payables (See Accounts 174 and 242) and gains on replacement of encroachment volumes (See Account 117.4). Records must be maintained and readily available to support the gains included in this account. 9. Include in a separate subaccount revenues from penalties earned pursuant to tariff provisions, including penalties associated with cash-out settlements. * * * * * 55. In Part 201, Operation and Maintenance Expense Chart of Accounts and Operation and Maintenance Expense Accounts, the words ``(Major only)'' are removed at the end of each title of Accounts 700 through 708, 711 through 724, 725 through 729, 730, 732 through 735, 740 through 742, 751 through 754, 756, 757, 761, 762, 765 through 769, 770 through 775, 777 through 791, 800, 801 through 804.1, 806, 809.1, 809.2, 810, 815 through 822, 824, 830, 831, 833 through 837, 840 through 847.8, 851 through 853, 854 through 857, 859, 861, 862, 865 through 867, 871 through 873, 875 through 877, 880, 885 through 892, 894, 901, 905, 907 through 913, and 916. 56. In Part 201, Operation and Maintenance Expense Chart of Accounts and Operation and Maintenance Expense Accounts, Accounts 724.1, 729.1, 737, 743, 769.1, 792, 799, 812.1, 827, 838, 839, 853.1, 857.1, 868, 880.1, 892.1, 895, 906, 917, and 933 are removed, and Account 935 is redesignated Account 932. 57. In Part 201, Operation and Maintenance Expense Accounts, Account 710, the words ``A. For Major companies, this'' are removed from paragraph A, and the word ``This'' is added in its place, and paragraph B and the Items section are removed. 58. In Part 201, Operation and Maintenance Expense Accounts, Account 731A and 731B, the words ``(for Nonmajor companies, account 154, Plant Materials and Operating Supplies)'' are removed. 59. In Part 201, Operation and Maintenance Expense Accounts, Account 750, the words ``For Major companies, this'' in paragraph A are removed and the word ``This'' is added in their place, and in paragraph B, under Items, the words ``(Major and Nonmajor)'' in the heading ``Items (Major and Nonmajor)'' and the heading ``Nonmajor Only'' and Items 5 through 21 are removed. 60. In Part 201, Operation and Maintenance Expense Accounts, Account 755, the words ``stations (including in the case of Major companies, applicable amounts of fuel stock expenses)'' in paragraph A are removed and the words ``stations, including applicable amounts of fuel stock expenses'' are added in their place, the words ``For Major companies, respective'' in paragraph B are removed [[Page 53069]] and the word ``Respective'' is added in their place, Note B is removed, Note A is redesignated Note, and the words ``(Major Companies)'' is removed from redesignated Note. 61. In Part 201, Operation and Maintenance Expense Accounts, Account 759, the words ``(Major companies only)'' in the introductory text are removed, the headings ``Major only'' and ``(Nonmajor companies):'' in the Items section are removed, and Items 1 through 18 following Item 5 are removed. 62. In Part 201, Operation and Maintenance Expense Accounts, Account 776, the words ``in the case of Major companies,'' the words ``(Major only)'' following the heading ``Items'', and the Note at the end of the account are removed. 63. In Part 201, Operation and Maintenance Expense Accounts, Account 795, Note, the words ``(in the case of Nonmajor Companies, account 105, Gas Plant Held for Future Use)'' are removed. 64. In Part 201, Operation and Maintenance Expense Accounts, Account 796, Note A, the words ``(in the case of Nonmajor companies, General Instruction 21, Gas Well Records)'' following the words ``Each Plant'' are removed. 65. In Part 201, Operation and Maintenance Expense Accounts, Account 797, paragraph A, the words ``For Major companies, this'' are removed, the word ``This'' is added in their place, and the sentence following the word ``productive.'' is removed, and in paragraph B, the words ``(Major only)'' are removed. 66. In Part 201, Operation and Maintenance Expense Accounts, Account 798, the words ``for Major companies,'' and the words ``for ``Nonmajor companies, see account 186, Miscellaneous Deferred Debits'' are removed. 67. In Part 201, Operation and Maintenance Expense Accounts, Account 805, a new paragraph C is added to read as follows: Operation and Maintenance Expense Accounts * * * * * 805 Other gas purchases. * * * * * C. Utilities recognizing revenue for shipper-supplied gas must include the current market price of such gas in this account. Current market price is the delivered spot price of gas in the utility's supply area, as published in a recognized industry journal. The publication used must be the same one identified in the pipeline's tariff for use in its cash-out provision, if it has one. If it has no cash-out provision, the utility must use one publication consistently. Contra entries to those recorded herein must be made to the appropriate transportation revenue account (Account 489.1 through Account 489.4). Records are to be maintained and readily available that include the name of shipper, quantity of gas, and the publication and price used to value shipper-supplied gas. * * * * * 68. In Part 201, Operation and Maintenance Expense Accounts, Account 806 is revised to read as follows: Operation and Maintenance Expense Accounts * * * * * 806 Exchange gas. A. This account includes debits or credits for the cost of gas in unbalanced transactions where gas is received from or delivered to another party in exchange, load balancing, or no-notice transportation transactions. The costs are to be determined from the current market price of gas at the time gas is tendered for transportation. (See the Special Instructions to Accounts 117.1, 117.2, and 117.3 for the definition of the current market price of gas.) Contra entries to those in this account are to be made to Account 174, Miscellaneous Current and Accrued Assets, for gas receivable and to Account 242, Miscellaneous Current and Accrued Liabilities, for gas deliverable under such transactions. Such entries must be reversed and appropriate contra entries made to this account when gas is received or delivered in satisfaction of the amounts receivable or deliverable. B. Records must be maintained so that there is readily available for each party entering gas exchange, load balancing, or no-notice transportation transactions, the quantity and cost of gas delivered and received. * * * * * 69. In Part 201, Operation and Maintenance Expense Accounts, Account 807, paragraph D, the words ``(Major companies'') are removed. 70. In part 201, Operation and Maintenance Expense Accounts, paragraph A of Accounts 808.1 and 808.2 are revised to read as follows: Operation and Maintenance Expense Accounts * * * * * 808.1 Gas withdrawn from storage-debit. A. This account shall include debits for the cost of gas withdrawn from storage during the year. Contra credits for entries to this account shall be made to Account 117.3, Gas Stored in Reservoirs and Pipelines-Noncurrent, or Account 117.4, Gas Owed to System Gas, or Account 164.2, Liquefied Natural Gas Stored, as appropriate. (See the Special Instructions to Accounts 117.1, 117.2, and 117.3). * * * * * 808.2 Gas delivered to storage-credit A. This account shall include credits for the cost of gas delivered to storage during the year. Contra debits for entries to this account shall be made to Account 117.3, Gas Stored in Reservoirs and Pipelines- Noncurrent, Account 117.4, Gas Owed to System Gas, or Account 164.2, Liquefied Natural Gas Stored, as appropriate. (See the Special Instructions to Accounts 117.1, 117.2, and 117.3). * * * * * 71. In Part 201, Operation and Maintenance Expense Accounts, Account 813, the current text is designated paragraph A, and the existing concluding text is added to the end of newly designated paragraph A, the words ``, in the case of Major companies,'' are removed from redesignated paragraph A, and a new paragraph B is added to read as follows: Operation and Maintenance Expense Accounts * * * * * 813 Other gas supply expenses. * * * * * B. Include in separate subaccounts: (1) losses on settlements of imbalance receivables and payables (See Account 174 and 242) and losses on replacement of encroachment volumes (See the Special Instructions to Accounts 117.1, 117.2 and 117.3); (2) revaluations of storage encroachments; and (3) system gas losses not associated with storage. Appropriate records must be maintained and readily available that include the amount of losses and associated volumes in Dth. 72. In Part 201, Operation and Maintenance Expense Accounts, Account 814, paragraph B and the Items (Nonmajor only) section are removed, and in paragraph A, the designation ``A.'' and the words ``For Major companies, this'' are removed and the word ``This'' is added in their place. 73. In Part 201, Operation and Maintenance Expense Accounts, Account 823, the words ``For Major [[Page 53070]] companies, see'' are removed and the word ``See'' is added in their place. 74. In Part 201, Operation and Maintenance Expense Accounts, Account 845.6B, the words ``Mcf or Dth, as appropriate,'' are removed and the word ``Dth'' is added in their place. 75. In Part 201, Operation and Maintenance Expense Accounts, Account 850, paragraph B and the Items (Nonmajor only) section are removed, and in paragraph A, the designation ``A.'' and the words ``For Major companies, this'' are removed and the word ``This'' is added in their place. 76. In Part 201, Operation and Maintenance Expense Accounts, Accounts 853.1B and 854B, the word ``Mcf'' is removed and the word ``Dth'' is added in its place. 77. In Part 201, Operation and Maintenance Expense Accounts, Account 858, paragraph B, the word ``Mcf'' is removed and the word ``Dth'' is added in its place each time it appears. 78. In Part 201, Operation and Maintenance Expense Accounts, Account 870, the words ``(Major only)'' are removed, and the words ``For Major companies, see'' are removed, and in their place the word ``See'' is added. 79. In Part 201, Operation and Maintenance Expense Accounts, Account 874, Items, the words ``(Major only)'' in the heading ``Labor (Major only)'' are removed, the heading ``Labor (Nonmajor only):'' and Items 1 through 3 under that heading are removed, the words ``(Major and Nonmajor):'' in the heading ``Materials and Expenses (Major and Nonmajor)'' are removed, and the words ``(Major only)'' are removed from Items 2, and 8 through 12 under that heading. 80. In Part 201, Operation and Maintenance Expense Accounts, Account 878, Items, the words ``(Major only)'' are removed at the end of each Item 1 through 12 and 20. 81. In Part 201, Operation and Maintenance Expense Accounts, Account 879, Items, the words ``(Major only)'' are removed at the end of Items 1, 2, 4, 5, 6, 9, and 11 through 13. 82. In Part 201, Operation and Maintenance Expense Accounts, Account 902, Items, Items 13 and 14 are removed, and a new Item 13 is added to read as follows: Operation and Maintenance Expense Accounts * * * * * 902 Meter reading expenses. * * * * * 13. Transportation, meals and incidental expenses. * * * * * 83. In Part 201, Operation and Maintenance Expense Accounts, Account 903, the words ``(Major only)'' at the end of Item 26 are removed, and Items 31 and 32 are removed. 84. In Part 201, Operation and Maintenance Expense Accounts, Account 924, the words ``For Major companies, it'' are removed from paragraph A and the word ``It'' is added in their place, the words ``(stores expenses in the case of Nonmajor companies)'' are removed from paragraph (1) of Note B, in paragraph (2) of Note B, the words ``For Major companies, transportation'' are removed and the word ``Transportation'' is added in their place, and the words ``For Nonmajor companies, transportation and garage equipment, to account 933, Transportation expenses.'' are removed, and the words ``(Major only)'' are removed from the title of Note C. 85. In Part 201, Operation and Maintenance Expense Accounts, Account 925, paragraph A, the words ``For Major Companies, it'' are removed and the word ``It'' is added in their place. 86. In Part 201, Operation and Maintenance Expense Accounts, Account 926, paragraph D, the words ``For Major companies, records'' are removed and the word ``Records'' is added in their place. 87. In Part 201, Operation and Maintenance Expense Accounts, Account 930.2, Item 4, the words ``For Major Companies, research'' are removed and the word ``Research'' is added in its place, and the words ``For Nonmajor companies, experimental and general research work for the industry.'' are removed. 88. In Part 201, Operation and Maintenance Expense Accounts, Account 935 is redesignated Account 932, and redesignated Account 932 is amended by removing the words ``For Nonmajor companies, include also other general equipment accounts (not including transportation equipment).'' in paragraph A, revising paragraph B after the words ``the following accounts:'', and adding the Note to read as follows: Operation and Maintenance Expense Accounts * * * * * 932 Maintenance of general plant. * * * * * B. * * * Manufactured Gas Production, accounts 708, 742 Natural Gas Production and Gathering, account 769 Natural Gas Production Extraction, account 791 Underground Storage, account 837 Local Storage, account 846.2 Transmission Expenses, account 867 Distribution Expenses, account 894 Merchandising and Jobbing, account 416 Garage, Shops, etc.--appropriate clearing account, if used. Note: Maintenance of plant included in other general plant equipment accounts shall be included herein unless charged to clearing accounts or to a particular functional maintenance expense indicated by the use of the equipment. PART 250--FORMS 89. The authority citation for part 250 continues to read as follows: Authority: 15 U.S.C. 717--717w, 3301--3432; 42 U.S.C. 7101-7352. 90. Section 250.2 is revised to read as follows: Sec. 250.2 Form of proposed cancellation of tariff or part thereof (see Sec. 154.602 of this chapter). When cancelling an entire tariff or an entire rate schedule, the notice of cancellation as set forth below must be filed as a revised tariff sheet superseding the first tariff sheet in the sequence of tariff sheets containing the tariff or part of the tariff being cancelled. When cancelling an individual tariff sheet, the tariff sheet should be designated as reserved for future use. CANCELLATION OF ENTIRE TARIFF Notice is hereby given that effective ____________________ (date) FERC Gas Tariff of ____________________ (Name of Company) is to be cancelled. CANCELLATION OF RATE SCHEDULE Notice is hereby given that effective ____________________ (date) Rate Schedule ____________________ constituting ____________________ Sheet(s) No.(s) ____________________ of the FERC Gas Tariff of ____________________ (Name of Company) is to be cancelled. 91. Section 250.3 is revised to read as follows: Sec. 250.3 Form of proposed cancellation or termination of contract or part thereof (see Sec. 154.602 of this chapter). Notice is hereby given that effective the __________ day of ____________________, ______, the contract with ____________________, (Name of customer or customers) dated ____________________ and relating to service under rate schedules(s) ____________________ (Here identify the rate schedule(s), giving sheet numbers in the Tariff) is to be ____________________ (Specify whether [[Page 53071]] it automatically terminates by its terms or is to be canceled by action of the parties) ---------------------------------------------------------------------- (Name of natural-gas company filing notice) By--------------------------------------------------------------------- ---------------------------------------------------------------------- (Title) Dated------------------------------------------------------------------ 92. Section 250.4 is revised to read as follows: Sec. 250.4 Form of certificate of adoption (see Sec. 154.603 of this chapter). The------------------------------------------------------------------ (Exact name of company or person) ---------------------------------------------------------------------- (Address) effective-------------------------------------------------------------- (Effective date of adoption) hereby adopts, ratifies, and makes its own, in every respect, the Tariff and contracts listed below, which have heretofore been filed with the Federal Energy Regulatory Commission by ---------------------------------------------------------------------- (Exact name of predecessor) ---------------------------------------------------------------------- (Here identify the Tariff and contracts adopted.) ---------------------------------------------------------------------- (Name of successor) By--------------------------------------------------------------------- (Title) Dated------------------------------------------------------------------ Secs. 250.5, 250.7, 250.8, 250.9, 250.10, 250.12, and 250.14 [Removed and reserved] 93. Sections 250.5, 250.7, 250.8, 250.9, 250.10, 250.12, and 250.14 are removed and reserved. 94. In Sec. 250.16, the words ``941 North Capitol Street, NE.,'' are removed from paragraphs(c)(3) and (d)(2), and paragraph (d)(1) is revised to read as follows: Sec. 250.16 Format of compliance plan for transportation services and affiliate transactions. * * * * * (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. * * * * * PART 260--STATEMENTS AND REPORTS (SCHEDULES) 95. The authority citation for part 260 continues to read as follows: Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7101-7352. 96. In Sec. 260.1, paragraph (a) is amended by adding a heading, and by removing the words ``for the reporting year 1980 and thereafter'', and paragraph (b) is revised to read as follows: Sec. 260.1 FERC Form No. 2, Annual report for Major natural gas companies. (a) Prescription. * * * (b) Filing requirements. Each natural gas company, as defined in 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 exceeded 50 million Dth in each of the three previous calendar years) must prepare and file with the Commission, on or before April 30 following the close of each calendar year, FERC Form No. 2. Newly established entities must use projected data to determine whether FERC Form No. 2 must be filed. The form must be filed electronically as indicated in the general instructions set out in that form. The format for the electronic filing can be obtained at the Federal Energy Regulatory Commission, Division of Information Services, Public Reference and Files Maintenance Branch, Washington, D.C. 20426. One copy of the report must be retained by the respondent in its files. The conformed copies may be by any legible means of reproduction. 97. In Sec. 260.2, paragraph (a) is amended by removing the words ``for the year 1980 and each year thereafter'', and paragraph (b) is revised to read as follows: Sec. 260.2 FERC Form No. 2-A, Annual report for Nonmajor natural gas companies. * * * * * (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, on or before March 31 following the close of each calendar year, FERC Form No. 2-A. Newly established entities must use projected data to determine whether FERC Form No. 2-A must be filed. The form must be filed electronically as indicated in the general instructions set out in that form. The format for the electronic filing can be obtained at the Federal Energy Regulatory Commission, Division of Information Services, Public Reference and Files Maintenance Branch, Washington, D.C. 20426. 98. Section 260.3 is revised to read as follows: Sec. 260.3 FERC Form No. 11, Natural gas pipeline company quarterly statement of monthly data. (a) This form, which is applicable to natural gas companies designated herein, is designed to obtain on a quarterly basis monthly information concerning selected revenues and associated quantities. (b)(1) Who must file. Each natural gas company, as defined in the Natural Gas Act, whose gas transported or stored for a fee exceeded 50 million Dth in each of the three previous calendar years, must prepare and file with the Commission FERC Form No. 11. The form must be filed electronically. The format for the electronic filing can be obtained at the Federal Energy Regulatory Commission, Division of Information Services, Public Reference and Files Maintenance Branch, Washington, D.C. 20426. (2) When to file. The reports must be filed quarterly on February 14 for data for the three months ending December 31, on May 15 for data for the three months ending March 31, on August 14 for data for the three months ending June 30, and on November 14 for data for the three months ending September 30. Each report must be signed by the person authorized to sign such report, but is not required to be filed under oath. Sec. 260.4 [Removed and reserved] 99. Section 260.4 is removed and reserved. 100. In Sec. 260.9, the introductory text of paragraph (b), and paragraphs (c) and (e) are revised to read as follows: Sec. 260.9 Report by natural gas pipeline companies on service interruptions occurring on the pipeline system. * * * * * (b) Natural gas pipeline companies must report such interruptions to service by any electronic means, including facsimile transmission or telegraph, to the Director, Division of Environmental and Engineering Review, Office of Pipeline Regulation, Federal Energy Regulatory Commission, Washington, DC 20426 (FAX: (202) 208-2853), at the earliest feasible time [[Page 53072]] following such interruption to service, and must state briefly: * * * * * (c) If so directed by the Commission or the Director, Division of Environmental and Engineering Review, the company must provide any supplemental information so as to provide a full report of the circumstances surrounding the occurrence. * * * * * (e) Copies of the telegraphic or facsimile report on interruption of service must be sent to the State commission in those States where service has been or might be affected. Secs. 260.11, 260.13, and 260.15 [Removed and reserved] 101. Sections 260.11, 260.13, and 260.15 are removed and reserved. PART 284--CERTAIN SALES AND TRANSPORTATION OF NATURAL GAS UNDER THE NATURAL GAS POLICY ACT OF 1978 AND RELATED AUTHORITIES 102. The authority citation for part 284 continues to read as follows: Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7201-7352; 43 U.S.C. 1331-1356. Subpart A--General Provisions and Conditions 103. In Sec. 284.2, paragraph (b) is revised to read as follows: Sec. 284.2 Refunds and interest. * * * * * (b) Interest. All refunds made pursuant to this section must include interest at an amount determined in accordance with Sec. 154.501(d) of this chapter. Sec. 284.3 [Amended] 104. In Sec. 284.3(a), the words ``, sale or assignment'' are removed and the words ``or sale'' are added in their place. 105. Section 284.4 is revised to read as follows: Sec. 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). 106. In Sec. 284.6, paragraph (b) is revised to read as follows: Sec. 284.6 Rate interpretations. * * * * * (b) Address. Requests for interpretations should be addressed to: FERC Part 284 Interpretations, Office of General Counsel, Federal Energy Regulatory Commission, Washington, DC 20426. 107. In Sec. 284.7, paragraph (b) is removed, paragraphs (c) and (d) are redesignated (b) and (c), respectively, redesignated paragraph (c)(5)(iv) is removed, and a new paragraph (c)(6) is added to read as follows: Sec. 284.7 Rates. * * * * * (c) Rate design. * * * (6) Discount reports. (i) A pipeline that provides either firm or interruptible transportation service at a discounted rate must file within 15 days of the close of the billing period a report containing the following information: (A) the full legal name of the shipper being provided the discount; (B) any corporate affiliation between the transporting pipeline and the shipper; (C) the maximum rate or fee; and (D) the rate or fee actually charged during the billing period. (ii) The requirements of this section do not apply to discounts relating to the release of capacity under Sec. 284.243, unless the release is permanent. (iii) The discount report information must be provided in electronic format according to specifications that can be obtained at the Federal Energy Regulatory Commission, Division of Information Services, Public Reference and Files Maintenance Branch, Washington, DC 20426. Sec. 284.8 [Amended] 108. In Sec. 284.8, paragraph (b)(4)(iii), the word ``of'' is added after the word ``purging'' and before the word ``information'' and in paragraph (b)(5)(i), the words ``941 North Capitol Street NE.,'' are removed. Sec. 284.10 [Removed and reserved] 109. Section 284.10 is removed and reserved. Sec. 284.11 [Amended] 110. In Sec. 284.11, paragraph (d)(1) is removed and the heading and paragraph designation for paragraph (d)(2) are removed. Secs. 284.13 and 284.14 [Removed and reserved] 111. Sections 284.13 and 284.14 are removed and reserved. Subpart B--Certain Transportation by Interstate Pipelines 112. Section 284.102(e) is revised to read as follows: Sec. 284.102 Transportation by interstate pipelines. * * * * * (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. Sec. 284.105 [Removed and reserved] 113. Section 284.105 is removed and reserved. 114. In Sec. 284.106, paragraph (a) is revised, paragraphs (b) through (f) are removed, paragraph (g) is redesignated as paragraph (b), the introductory text of redesignated paragraph (b) is revised, and a new paragraph (c) is added to read as follows: Sec. 284.106 Reporting requirements. (a) Notice of bypass. An interstate pipeline that provides transportation (except storage) under Sec. 284.102 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 [[Page 53073]] proposed transportation prior to commencement. (b) Semi-annual storage report. Within 30 days of the end of each complete storage injection and withdrawal season, the interstate pipeline must file with the Commission a report of storage activity provided under the authority of either Sec. 284.102 or Sec. 284.223, as applicable. The report must be signed under oath by a senior official, consist of an original and five conformed copies, and contain a summary of storage injection and withdrawal activities to include the following: * * * * * (c) Index of customers. (1) Each calendar quarter, subsequent to the initial implementation of this provision, an interstate pipeline must provide for electronic dissemination of an index of all its firm transportation and storage customers under contract as of the first day of the calendar quarter. Electronic dissemination will be by placing a file, adhering to the requirements set forth by the Commission, on the pipeline's electronic bulletin board in a format which can be downloaded from the electronic bulletin board. The pipeline must also submit the electronic file to the Commission. (2) Until an interstate pipeline is in compliance with the reporting requirements of this paragraph, the pipeline must comply with the index of customer requirements applicable to transportation and sales under Part 157, set forth under Sec. 154.111 (b) and (c) of this chapter. (3) For each customer receiving firm transportation or storage service, the index must include the information listed below: (i) the full legal name of the customer; (ii) the rate schedule number of the service being provided; (iii) the contract effective date; (iv) the contract expiration date; (v) for transportation service, maximum daily contract quantity (specify unit of measurement); (vi) for storage service, maximum storage quantity (specify unit of measurement). (4) The information included in the quarterly index must be available on the electronic bulletin board until the next quarterly index is established. The electronic files must be archived for at least three years. (5) The requirements of this section do not apply to contracts which relate solely to the release of capacity under Sec. 284.243, unless the release is permanent. (6) The requirements for the electronic index can be obtained at the Federal Energy Regulatory Commission, Division of Information Services, Public Reference and Files Maintenance Branch, Washington, DC 20426. Subpart C--Certain Transportation by Intrastate Pipelines Sec. 284.122 [Amended] 115. In Sec. 284.122, paragraph (e) is removed. 116. In Sec. 284.123, paragraph (e) is revised to read as follows: Sec. 284.123 Rates and charges. * * * * * (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 describes how the pipeline will engage in these transportation arrangements, including operating conditions, such as, quality standards and financial viability of the shipper. The statement must also include the rate election made by the intrastate pipeline pursuant to paragraph (b) of this section. If the pipeline changes its operations 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. Sec. 284.125 [Removed and reserved] 117. Section 284.125 is removed and reserved. 118. In Sec. 284.126, paragraph (a) is revised, paragraphs (b), (e), and (f) are removed, paragraphs (c) and (g) are redesignated (b), and (c), respectively, and redesignated paragraph (b) is revised to read as follows: Sec. 284.126 Reporting requirements. (a) Notice of bypass. An intrastate pipeline that provides transportation (except storage) under Sec. 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) Annual report. Not later than March 31 of each year, each intrastate pipeline must file an annual report with the Commission and the appropriate state regulatory agency that contains, for each transportation service (except storage) provided during the preceding calendar year under Sec. 284.122, the following information: (1) The name of the shipper receiving the transportation service; (2) The type of service performed (i.e., firm or interruptible); (3) Total volumes transported for the shipper. If it is firm service, the report should separately state reservation and usage quantities; and (4) Total revenues received for the shipper. If it is firm service, the report should separately state reservation and usage revenues. * * * * * Subpart D--Certain Sales by Intrastate Pipelines 119. Section 284.142 is revised to read as follows: Sec. 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 Sec. 284.123. Secs. 284.143 through 284.148 [Removed and reserved] 120. Sections 284.143 through 284.148 are removed and reserved. Subpart E--Assignment of Contractual Rights to Receive Surplus Natural Gas Subpart E--[Removed and reserved] 121. Subpart E is removed and reserved. Subpart G--Blanket Certificates Authorizing Certain Transportation by Interstate Pipelines on Behalf of Others and Services by Local Distribution Companies 122. In Sec. 284.221, the introductory text of paragraph (b)(1) is revised, in paragraph (d)(1), the words ``Sec. 284.14(e), and'' are removed, and in paragraph (f)(2), the words ``Sec. 284.222 or'' are removed, to read as follows: Sec. 284.221 General rule; transportation by interstate pipelines on behalf of others. * * * * * (b) Application procedure. (1) An application for a blanket certificate under this section must be filed electronically. The format for the electronic application filing can be obtained at the Federal Energy Regulatory Commission, Division of [[Page 53074]] Information Services, Public Reference and Files Maintenance Branch, Washington, D.C. 20426, and must include: * * * * * Sec. 284.222 [Removed and reserved] 123. Section 284.222 is removed and reserved. 124. In Sec. 284.223, the section heading is revised, paragraphs (b) through (f) are removed, and a new paragraph (b) is added to read as follows: Sec. 284.223 Transportation by interstate pipelines on behalf of shippers. * * * * * (b) Reporting requirements. Any interstate pipeline transporting gas under this section must comply with each of the reporting requirements specified in Sec. 284.106. 113. In Sec. 284.224, the heading, paragraphs (b)(3), (c) introductory text, (d)(1), (e)(1), and (g) are revised, paragraph (e)(5)(i) is redesignated as paragraph (e)(5), and paragraph (e)(5)(ii) is removed to read as follows: Sec. 284.224 Certain transportation and sales by local distribution companies. * * * * * (b) Blanket certificate-- * * * (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 Sec. 381.207 of this chapter or a petition for waiver pursuant to Sec. 381.106 of this chapter, and shall state: * * * * * (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. * * * * * (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. * * * * * (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. * * * * * Secs. 284.225 and 284.226 [Removed and reserved] 125. Sections 284.225 and 284.226 are removed and reserved. Sec. 284.227 [Amended] 126. In Sec. 284.227, paragraph (d) is removed, and paragraphs (e), (f), and (g) are redesignated (d), (e), and (f). Subpart I--Emergency Natural Gas Sale, Transportation, and Exchange Transactions Sec. 284.266 [Amended] 127. In Sec. 284.266, paragraphs (b) and (c) are removed, and paragraph (d) is redesignated (b). Sec. 284.269 [Amended] 128. In Sec. 284.269, the number ``Sec. 284.144'' is removed, and the number ``Sec. 284.142'' is added in its place. Subpart J--Blanket Certificates Authorizing Certain Natural Gas Sales by Interstate Pipelines Sec. 284.284 [Amended] 129. In Sec. 284.284(b), the words ``, except as adjusted in Secs. 284.14 (d) and (e)'' are removed. 130. In Sec. 284.286, paragraph (e) is revised to read as follows: Sec. 284.286 Standards of conduct for unbundled sales service. * * * * * (e) A pipeline that provides unbundled sales service under Sec. 284.284 must have tariff provisions on file with the Commission indicating how the pipeline is complying with the standards of this section. 131. Section 284.287 is revised to read as follows: Sec. 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 Sec. 284.284 will be effective on the effective date (as approved by the Commission) of the tariff sheets implementing service under that certificate. Subpart L--Certain Sales for Resale by Non-interstate Pipelines 132. In Sec. 284.402, paragraph (c)(1) is revised, and in the first sentence of paragraph (c)(2), the word ``criteria'' is removed, and the word ``criterion'' is added in its place, to read as follows: Sec. 284.402 Blanket marketing certificates. * * * * * (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 Sec. 284.284. * * * * * PART 381--FEES 133. The authority citation for part 381 continues to read as follows: Authority: 15 U.S.C. 717-717w; 16 U.S.C. 791-828c, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352; 49 U.S.C. 60502; 49 App. U.S.C. 1- 85. Sec. 381.404 [Removed and reserved] 134. Section 381.404 is removed and reserved. PART 385--RULES OF PRACTICE AND PROCEDURE 135. The authority citation for part 385 continues to read as follows: Authority: 5 U.S.C. 551-557; 15 U.S.C. 717-717z, 3301-3432; 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352; 49 U.S.C. 60502; 49 U.S.C. 1-85. 136. In Sec. 385.2011, paragraphs (b), (c)(4), and (d) are revised to read as follows: Sec. 385.2011 Procedures for filing on electronic media (Rule 2011). * * * * * (b) These procedures also apply to: (1) Material submitted electronically pursuant to Sec. 154.4 of this chapter. (2) Certificate and abandonment applications filed under Subparts A, E, and F of Part 157 of this chapter. (3) Blanket certificate applications filed under Subpart G of Part 284 of this chapter. (4) Discount rate reports filed pursuant to Sec. 284.7 of this chapter. (c) What to file. * * * (4) The formats for the electronic filing and the paper copy can be obtained at the Federal Energy Regulatory Commission, Public Reference and Files Maintenance [[Page 53075]] Branch, Division of Information Services, Washington, DC 20426. * * * * * (d)(1) Where to file. The electronic media, the paper copies, and accompanying cover letter must be submitted to: Office of the Secretary, Federal Energy Regulatory Commission, Washington, DC 20426. (2) EDI data submissions must be made as indicated in the electronic filing instructions and formats for the particular form or filing, and the paper copies and accompanying cover letter must be submitted to: Office of the Secretary, Federal Energy Regulatory Commission, Washington, DC 20426. Note: This Appendix will not be published in the Code of Federal Regulations. Appendix A--Parties Filing Comments on the Notice of Proposed Rulemaking Docket No. RM95-4-000 ------------------------------------------------------------------------ Commenter Abbreviation ------------------------------------------------------------------------ American Forest & Paper Association American Forest. American Gas Association........... AGA. American Public Gas Association.... APGA. ANR Pipeline Company and Colorado ANR. Interstate Gas Company. Associated Gas Distributors........ AGD. Association of Texas Intrastate Texas Intrastates. Natural Gas Pipelines. CNG Transmission Corporation....... CNG. Columbia Gas Distribution Companies Columbia Distribution. Columbia Gas Transmission Columbia. Corporation and Columbia Gulf Transmission Company. Consumers Power Company and Consumers Power. Michigan Gas Storage Company. Electronic Bulletin Board Working EBB Working Group. Group. El Paso Natural Gas Company........ El Paso. Enogex, Inc........................ Enogex. Freeport Interstate Pipeline Freeport. Company. Gaslantic Corporation.............. Gaslantic. Great Lakes Gas Transmission Great Lakes. Limited Partnership. Independent Petroleum Association IPAA. of America. Interstate Natural Gas Association INGAA. of America. KN Energy, Inc..................... KN. Kern River Gas Transmission Company Kern River. Midwest Gas Services, Inc.......... Midwest. Mississippi River Transmission MRT. Corporation and NorAm Gas Transmission Company. Missouri Public Service Commission. Missouri. National Fuel Gas Supply National Fuel. Corporation. National Registry of Capacity Registry. Rights. Natural Gas Supply Association..... NGSA. Northern Illinois Gas Company...... NI-Gas. Panhandle Eastern Pipeline Company, Panhandle. Trunkline Gas Company, Texas Eastern Transmission Corporation, and Algonquin Gas Transmission Company. Pacific Gas and Electric Company... PG&E. Process Gas Consumers Group, Industrials. American Iron and Steel Institute, and Georgia Industrial Group. Producer-Marketer Transportation PMTG. Group. Southern California Gas Company.... SoCal. Tennessee Gas Pipeline Company, Tennessee. Midwestern Gas Transmission Company, and East Tennessee Natural Gas Company. Texas Gas Transmission Corporation. Texas Gas. Transcontinental Gas Pipe Line Transco. Corporation. Transok, Inc....................... Transok. United States Department of Energy. DOE. Williston Basin Interstate Pipeline Williston. Company. Williams Natural Gas Company....... Williams. ------------------------------------------------------------------------ [FR Doc. 95-24722 Filed 10-10-95; 8:45 am] BILLING CODE 6717-01-P