# Revisions to Uniform System of Accounts, Forms, Statements, and Reporting Requirements for Natural Gas Companies

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URL: https://www.frixlaw.com/law-library/documents/fr%3A95-24722

## Record

- **Collection:** Federal Register
- **Document type:** Rule
- **Published:** October 11, 1995
- **Citation:** 60 FR 53019

## Text

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.

----------------------------------------------------------------------------------------------------------------
Estimated Estimated Net change in Estimated No. Estimated
Affected data collection (RM95-4- annual burden annual burden annual burden of filings/yr burden hrs per
000) hrs (rule) hrs (current) hrs (rule) filing (rule)
----------------------------------------------------------------------------------------------------------------
FERC-2.......................... 68,310 113,850 -45,540 46 1,485.0
FERC-549........................ 14795 14,045 -13,250 1590 168.8
FERC-549 (B).................... 350,308 349,060 1,248 17546 641.6
FERC-576........................ 12 36 -24 12 1.0
FERC-11......................... 600 3,420 -2,820 200 3.0
FERC-2A......................... 2,610 2,610 0 87 30.0
FERC-818........................ 0 1,296 -1,296 0 0
FERC-1418....................... 0 142 -142 0 0
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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 (

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A95-24722. Public record. Not legal advice.