[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]



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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.

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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.
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    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.
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    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.
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    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.
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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.
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    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.

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                                     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)
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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
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      Total.....................         422,635         484,459         -61,824             981          430.8 
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\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.
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    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.
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    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.
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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.
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    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.
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    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.
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    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).
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    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