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

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Parts 2, 157, 158, 201, 250, 260, 284, 381, and 385

[Docket No. RM95-4-000; Order No. 581

Revisions to Uniform System of Accounts, Forms, Statements, and

Reporting Requirements for Natural Gas Companies

Issued: September 28, 1995.

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule.

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SUMMARY: The Federal Energy Regulatory Commission is amending its

Uniform System of Accounts, its forms, and its reports and statements

for natural gas companies. The amendments reflect the current

regulatory environment of unbundled pipeline sales for resale at

market-based prices and open-access transportation of natural gas. The

Commission seeks to simplify and streamline its requirements to reduce

the burden of respondents.

[[Page 53020]]

EFFECTIVE DATE: The final rule is effective November 13, 1995, except

for the changes to the Uniform System of Accounts (Part 201).

FOR FURTHER INFORMATION CONTACT: Jeffrey A. Braunstein, Office of the

General Counsel, Federal Energy Regulatory Commission, 825 North

Capitol Street, NE., Washington, DC 20426, (202) 208-2114.

SUPPLEMENTARY INFORMATION: In addition to publishing the full text of

this document, excluding Appendices B (FERC Form No. 2), C (FERC Form

No. 2-A), and D (FERC Form No. 11), in the Federal Register, the

Commission also provides all interested persons an opportunity to

inspect or copy the contents of this document during normal business

hours in Room 3104, 941 North Capitol Street, NE., Washington, DC

20426.

The Commission Issuance Posting System (CIPS), an electronic

bulletin board service, provides access to the texts of formal

documents issued by the Commission. CIPS is available at no charge to

the user and may be accessed using a personal computer with a modem by

dialing (800) 856-3920. To access CIPS, set your communications

software to 19200, 14400, 12000, 9600, 7200, 4800, 2400 or 1200bps,

full duplex, no parity, 8 data bits, and 1 stop bit. The full text of

this document will be available on CIPS in ASCII and WordPerfect 5.1

format. The complete text on diskette in Wordperfect format may also be

purchased from the Commission's copy contractor, La Dorn Systems

Corporation, also located in Room 3104, 941 North Capitol Street, NE.,

Washington, DC 20426.

I. Introduction

The Federal Energy Regulatory Commission (Commission) hereby amends

its Uniform System of Accounts,1 its forms, and its reports and

statements for natural gas companies.2 This Final Rule is a

companion to the Commission's Final Rule ``Filing Requirements for

Interstate Natural Gas Company Rate Schedules and Tariffs'', which

amends Part 154 of the Commission's regulations and is issued

contemporaneously with this rule. The Commission has received 41

comments on the Notice of Proposed Rulemaking (NOPR)3 in this

docket from the commenters listed in Appendix A.4

\1\Section 8 of the Natural Gas Act (NGA), 15 U.S.C. 717g

(1988), authorizes the Commission to prescribe rules and regulations

concerning accounts, records and memoranda as necessary or

appropriate for purposes of administering the NGA. The Commission

may prescribe a system of accounts for jurisdictional companies and,

after notice and opportunity for hearing, may determine the accounts

in which particular outlays and receipts will be entered, charged,

or credited.

\2\Section 10 of the NGA, 15 U.S.C. 717i (1988), authorizes the

Commission to prescribe rules and regulations concerning annual and

other periodic or special reports, as necessary or appropriate for

purposes of administering the NGA. The Commission may prescribe the

manner and form in which such reports are to be made, and require

from natural gas companies specific answers to all questions on

which the Commission may need information. The reports must be made

under oath unless the Commission otherwise specifies.

\3\Revisions to Uniform System of Accounts, Forms, Statements,

and Reporting Requirements for Natural Gas Pipelines, 60 FR 3141

(January 13, 1995), IV FERC Stats. & Regs. Proposed Regulations

para. 32,512 (December 16, 1994).

\4\Appendix A also sets forth the names by which the commenters

are referred to herein.

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In brief, the Commission, in this rule, addresses the Uniform

System of Accounts' treatment of gas in underground storage reservoirs

and in pipelines,5 revenues6 and gas supply expenses,7

eliminates all accounts for Nonmajor respondents and redesignates

accounts used only by Major respondents for use by all respondents. The

Commission also changes or eliminates various forms, reports, and

statements. This includes changes to, and deletions from, FERC Form No.

2 (Form No. 2), Annual report of Major natural gas companies, and FERC

Form No. 2-A (Form No. 2-A), Annual report of Nonmajor natural gas

companies, and FERC Form No. 11 (Form No. 11), Natural gas pipeline

company monthly statement.8

\5\The Commission amends Account 117, Account 164.1, and other

accounts that refer to Account 117.

\6\The Commission amends Account 489 and Account 495.

\7\The Commission amends Account 806, Account 813, and Account

823.

\8\Form No. 2 consists of approximately 162 non-consecutively

numbered pages and a four-page index. See 18 CFR 260.1. The current

version bears OMB approval No. 1902-0028. Form No. 2-A consists of

approximately 22 consecutively numbered pages, 1-22, and 32 non-

consecutively numbered substitute pages from the Form No. 2 that may

be used in lieu of the comparable pages in the first section. See 18

CFR 260.2. The current version bears OMB approval No. 1902-0030.

Form No. 11 consists of approximately 4 consecutively numbered

pages, 1-4. See 18 CFR 260.3. The current version bears OMB approval

No. 1902-0032.

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The Commission is making the changes in order to create forms,

reports, and statements that reflect the current regulatory environment

of unbundled pipeline sales for resale at market-based prices and open-

access transportation of natural gas. In doing that, the Commission

seeks to simplify and streamline its requirements to reduce the burden

on respondents. Hence, the Commission is eliminating reporting

requirements (as well as a few non-reporting requirements) that are

outdated or nonessential in light of current regulation, or are

duplicative of other reporting requirements. At the same time, the

revisions, especially of Form No. 2, will provide financial, rate, and

statistical information on transactions that is more useful than what

is currently available to regulatory agencies and other users of the

financial statements and reports of natural gas companies. The

Commission believes the changes to Form No. 2 are needed because the

characteristics of certain balance sheet and income statement items for

the restructured industry are different from what they were when the

current accounting regulations were adopted. In addition, the

Commission has significantly increased the thresholds for the reporting

of various information.

In Part III-A of this rule, the Commission will address the changes

to the Uniform System of Accounts with respect to storage gas. In Part

III-B the Commission will address other revisions to the Uniform System

of Accounts. In Part IV, the Commission will discuss the changes to

Part 158 of the Commission's regulations with respect to the

certification of compliance with the accounting regulations. In Part V,

the Commission will discuss the changes to Part 250 of the Commission's

regulations, ``Approved Forms, Natural Gas Act.'' In Part VI, the

Commission will discuss the changes to Part 260 of the Commission's

regulations, ``Statements and Reports (Schedules).'' That discussion

will include the changes to Forms No. 2,9 No. 2-A,10 and Form

No. 11.11 In Part VII, the Commission will discuss the changes to

Part 284 of the Commission's regulations, ``Certain Sales and

Transportation of Natural Gas Under the Natural Gas Policy Act of 1978

and Related Authorities.''

\9\Appendix B consists of the revised Form No. 2. Appendix B is

not being published in the Federal Register, but is available from

the Commission's Public Reference Room.

\10\Appendix C consists of the revised Form No. 2-A. Appendix C

is not being published in the Federal Register, but is available

from the Commission's Public Reference Room.

\11\Appendix D consists of the revised Form No. 11. Appendix D

is not being published in the Federal Register, but is available

from the Commission's Public Reference Room.

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In the NOPR, the Commission stated that the changes to these

regulations and forms and to the regulations in the companion rule

titled, ``Filing Requirements for Interstate Natural Gas Company Rate

Schedules and Tariffs,'' will necessitate modifications to the

electronic formats for the affected filings and forms. The Commission

will discuss electronic filings in Part IX below.

[[Page 53021]]

The changes to the Uniform System of Accounts and Form Nos. 2, 2-A,

and 11 in this rule will be effective January 1, 1996.12 The

remainder of the rule will be effective 30 days after publication in

the Federal Register.

\12\That is, the pipelines must comply with the revised Uniform

System of Accounts starting January 1, 1996, and they must report

1996 information on the FERC Form Nos. 2 and 2-A filed in 1997. The

Form No. 2 filed in 1996 will be the current Form No. 2 and will

report for the year 1995.

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II. Public Reporting Burden

The subject final rule establishes new reporting requirements,

modifies existing reporting requirements, and eliminates those

requirements that are now obsolete. In addition, the final rule

reflects many of the changes suggested by industry comments filed in

response to Commission's Notice of Proposed Rulemaking. This

simplification and streamlining of Commission reporting requirements

has reduced the burden on pipelines. The collective reduction in

reporting burden is estimated to be 61,824 hours annually.

The final rule will affect eight of the Commission's existing data

collections. It is expected to reduce or eliminate the current

reporting burden associated with the following six information

collections:

FERC Form No. 2 ``Annual Report of Major Natural Gas Companies''

(1902-0028) (FERC-2);

FERC Form No. 11, ``Natural Gas Pipeline Company Monthly Statement

(1902-0032) (FERC-11);

FERC-549, ``Gas Pipeline Rates: Natural Gas Policy Act Title III

Transactions'' (1902-0086) (FERC-549);

FERC-576, ``Reports on Pipeline Systems Service Interruptions''

(1902-0004) (FERC-576);

FERC Form No. 8, ``Underground Gas Storage Report'' (1902-0026)

(FERC-8); and

FERC Form No. 14, ``Annual Report for Importers and Exporters of

Natural Gas'' (1902-0027) (FERC-14)

The FERC Form Nos. 8 and 14 will be eliminated entirely as a result of

this rule. One of the affected data collections--FERC Form No. 2-A,

``Annual Report of Nonmajor Natural Gas Companies'' (1902-0030) (FERC-

2A)--will have no substantive change in its current reporting

burden.13 Only one of the data collections will have a slight

increase in burden. The burden associated with FERC-549B, ``Gas

Pipeline Rates: Capacity Release Information'' (1902-0169) (FERC-549B)

will increase as a result of the institution of the Index of Customers.

\13\No net change in the reporting burden is expected because of

offsetting increases and decreases within the data collection.

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The aggregate annual reporting burden as a result of the final rule

for all affected data collections is estimated to total 437,835 hours

based on an expected 981 filings per year. The summary table below

shows the impact/reduction on each affected data collection. The

Commission's estimates of public reporting burden for the data

collections include the time for reviewing instructions, searching

existing data sources, gathering and maintaining the data needed, and

completing and reviewing the collection of information.

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Estimated Estimated Net change in Estimated No. Estimated

Affected data collection (RM95-4- annual burden annual burden annual burden of filings/yr burden hrs per

000) hrs (rule) hrs (current) hrs (rule) filing (rule)

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FERC-2.......................... 68,310 113,850 -45,540 46 1,485.0

FERC-549........................ 14795 14,045 -13,250 1590 168.8

FERC-549 (B).................... 350,308 349,060 1,248 17546 641.6

FERC-576........................ 12 36 -24 12 1.0

FERC-11......................... 600 3,420 -2,820 200 3.0

FERC-2A......................... 2,610 2,610 0 87 30.0

FERC-818........................ 0 1,296 -1,296 0 0

FERC-1418....................... 0 142 -142 0 0

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

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\14\Comprised of 750 hours for transportation filings and 45 hours for sales filings.

\15\Comprised of 75 transportation filings and 15 sales filings.

\16\The weighted average of 10.0 hours per transportation filing and 3.0 hours per sales filing.

\17\Includes 468 Index of Customer filings.

\18\This data collection is discontinued by the subject rule.

With respect to the gas companies filing FERC Form No. 2, the

Commission believes that there will be a total reporting burden

decrease of 45,540 hours, or approximately 990 hours per respondent

each year due to the elimination of about 34 schedules and significant

increases in the thresholds for the reporting of information on other

schedules. There will be some additional information required, but

there should be a minimal burden increase as a result, because much of

the information is already collected by the industry in other contexts.

The Commission estimates that the existing public reporting burden

for the other filing requirements under the rule will also be

decreased. With respect to FERC Form No. 11, the quarterly Form No. 11

will contain monthly details of data required annually on an aggregate

basis in FERC Form No. 2. The filing of FERC Form No. 11, quarterly

rather than monthly, will reduce the number of reports from 600 to 200.

In addition, data are primarily required by rate schedule or Uniform

System of Accounts entries. These consistencies in reporting will

simplify the filing burden. The revised reporting schedule will reduce

the existing reporting burden by a total of 2820 hours, or

approximately 56 hours per respondent each year.

The elimination of initial, subsequent, termination, and annual

reports, FERC-549, for interstate pipelines, and the retention of only

the annual transportation reports for intrastate pipelines and the

annual sales reports for interstate pipelines, will reduce the

reporting burden by a total of 13,250 hours. The Commission estimates

that the annual report for the 75 remaining intrastate respondents will

require an average of 10 hours to complete. The annual sales report for

the 15 interstate respondents requires an average of 3 hours to

complete.

The Index of Customers requirement will add approximately 1,248

hours to the total burden under FERC-549B. In

[[Page 53022]]

its Notice of Proposed Rulemaking, the Commission estimated that this

requirement would add 11,700 hours to the reporting burden for FERC-

549B. However, the Commission has deleted the paper filing requirement,

and required that the index be filed electronically with the Commission

and be available through a pipeline's electronic bulletin board. It is

now estimated that the Index of Customers will take approximately 4

hours for each quarterly update for the 78 pipeline respondents.

Allowing reporting of service interruptions in FERC-576 by any

electronic means, including facsimile or telegraph, will expedite the

notice process, and reduce the burden to one hour per response from

three hours. This report is required only in the event of an

interruption to normal service lasting three hours or longer.

The elimination of the FERC Form Nos. 8 and 14 will reduce industry

reporting burden by 1,296 and 142 hours, respectively.

A copy of this rule is being provided to OMB. Interested persons

may send comments regarding these burden estimates, or any other aspect

of these collections of information, including suggestions for further

reductions of burden, to the Federal Energy Regulatory Commission,

Washington, D.C. 20426 [Attention: Michael Miller, Information Services

Division, (202) 208-1415, FAX: (202) 208-2425]. Comments on the

requirements of this final rule may also be sent to the Office of

Information and Regulatory Affairs of OMB, Washington, D.C. 20503

[Attention: Desk Officer for Federal Energy Regulatory Commission,

(202) 395-3087, FAX: (202) 395-5167].

III. Revisions to Uniform System of Accounts (Part 201)

A. Storage Accounting

1. The NOPR

In the NOPR, the Commission proposed to require that the maximum

designated gas volumes maintained for system balancing purposes,19

including those needed for no-notice transportation service, and

recoverable base gas volumes be accounted for as a fixed asset rather

than as inventory held for sale, which is the current practice.20

Collectively these volumes are referred to as ``system gas''.

\19\System balancing, as used here, refers to those situations

where the pipeline provides gas from its own source of supply in

order to meet deficiencies caused by a shipper tendering less

volumes to the pipeline at the receipt point than it takes from the

system at the delivery point. The term can also be used to refer to

situations where the shipper tenders more volumes than it takes from

the system.

\20\The Commission is not changing the accounting requirements

for initial line pack, LNG heel, and non-recoverable base gas. The

cost of this gas will continue to be recorded in the utility plant

accounts.

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Under the fixed asset model, system gas would be accounted for as a

noncurrent asset or permanent investment. In contrast, under the

inventory model, system gas would be accounted for as inventory. The

two models differ in how the pipeline's investment in gas is valued and

in how gains and losses on balancing transactions are measured and

recognized.21

\21\See the NOPR at pps. 32,999-33,001 for a full discussion of

the differences between the fixed asset and inventory models.

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To implement the fixed asset accounting model for system gas, the

NOPR proposed that Account 117, Gas Stored Underground--Noncurrent, be

replaced by new accounts Account 117.1, Gas Stored--Base Gas, Account

117.2, System Balancing Gas, Account 117.3, Gas Stored in Reservoirs

and Pipelines--Noncurrent, and Account 117.4, Gas Owed to System Gas.

2. Comments on Mandating the Fixed Asset Model

The fixed asset approach is supported in whole or in part by

Columbia, ANR, Enron, Tennessee, Texas Gas, KN, NGSA, and NI-Gas. It is

opposed by Panhandle, Transco, and AGD.

INGAA and other commenters22 maintain that the pipelines

should be able to choose either the fixed asset or inventory model.

INGAA submits that this flexibility is justified for two reasons.

First, it argues that adoption of the fixed asset model will not ensure

uniformity in accounting for storage because that model is not uniform

among non-pipeline storage owners and operators, such as independent

storage operators and local distribution companies. Second, INGAA

contends that flexibility would prevent a number of distortions which

will arise from pipelines converting from the inventory method to the

fixed asset model. Third, INGAA asserts that the change from the

inventory to the fixed asset model could increase state ad valorem

taxes and could be considered a change in accounting by the IRS,

causing it to rescind permission to use the LIFO inventory method for

income tax purposes.

\22\ANR, Kern River, Transco, Enron, Tennessee, KN, Williston,

and Consumers Power.

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3. The Treatment of System Gas

As stated above, there is support for both the fixed asset model

and the inventory model as the appropriate approach for accounting for

investments in system gas. Upon review of the comments, the Commission

concludes that valid arguments can be made in support of either

approach. Accordingly, the Commission will permit pipelines to adopt

either the fixed asset model or the inventory model to account for

system gas.23

\23\The Commission is not setting forth the arguments for and

against the models in light of the decision not to mandate a

particular model.

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Each pipeline must inform the Commission of the method it adopts

for accounting for system gaswhen it files its Form No. 2 in 1997. The

method adopted by each pipeline must be used consistently from year to

year and appropriate records must be maintained. The pipeline must

obtain Commission approval for any change in method. The Commission

will not permit a pipeline to adopt one method for determining its

rates and another method for accounting purposes. For example, if a

pipeline elects the fixed asset model for accounting purposes, it must

derive its rates via that model in its first full rate proceeding

subsequent to its accounting decision. Similarly, if a pipeline uses

the fixed asset model in developing its rates, it must use the same

method for accounting purposes.

4. The Rule

a. Investment in System Gas. To implement this rule, the Commission

is revising its accounting regulations to allow pipelines two

alternative methods of accounting for all pipeline investment in system

gas. Under those regulations, pipelines may continue to account for

their gas using a consistently applied inventory method, or pipelines

may adopt the ``fixed asset'' method. As noted above, the Commission is

not changing the accounting requirements for initial line pack, LNG

heel, and non-recoverable base gas. The cost of this gas will continue

to be recorded in the utility plant accounts. The Commission is

replacing Account 117, Gas Stored Underground-Noncurrent with four new

accounts: Account 117.1, Gas Stored--Base Gas, Account 117.2, System

Balancing Gas, Account 117.3, Gas Stored in Reservoirs and Pipelines-

Noncurrent, and Account 117.4, Gas Owed to System Gas.

Account 117.1 will include the cost of recoverable gas volumes that

are necessary to maintain pressure and deliverability requirements for

the storage facility. Nonrecoverable gas volumes used for this purpose

will continue to be recorded in Account 352.3, Nonrecoverable Natural

Gas.

[[Page 53023]]

Account 117.2 will be used to record a pipeline's investment in any

additional system gas volumes, including gas stored in pipelines above

initial line pack, designated as maximum system gas needed for load

balancing, no notice transportation, and other operational purposes.

Account 117.3 will be used to record the cost of noncurrent company-

owned stored gas not includable in Accounts 117.1 or 117.2.

Account 117.4 will primarily be used by pipelines that account for

system gas using the fixed asset model. Account 117.4 will reflect

encroachments upon system gas that result from transportation

imbalances, no-notice transportation, and other operational needs. It

may also be used to reflect encroachments on volumes recorded in

Account 117.1 for pipelines using an inventory method.

The initial investment cost to be recorded in Account 117.1 and

117.2 is to be determined from the book balances in Account 117 on the

date of adoption of the new accounts. If there is no Commission

approved method to the contrary, volumes in Account 117.1 and Account

117.2 are to be priced at their historical cost consistent with the

inventory method previously in use.24 If at the date of adoption,

a pipeline's volumes in storage are less than the maximum volume

authorized by the Commission for operational purposes, the deficient

volumes are to be priced at the then current market price25 with

an equal amount being credited to Account 117.4.

\24\The cost of any volumes of base or system gas actually in

storage that has previously been charged to expense should be

carried in the accounts at zero cost.

\25\Current market price is the delivered spot price of gas as

published in a recognized industry journal. The publication used

must be the same one identified in the pipeline's tariff for use in

its cash-out provision, if it has one. If the pipeline does not have

a cash-out provision, the pipeline must use a publication

representative of the cost of gas in its supply area, use the same

publication consistently, and identify the publication in its

records.

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b. Use of System Gas. (1) Fixed Asset Method. Under the fixed asset

method the Commission is adopting in this rule, future encroachments

upon system gas are to be credited to Account 117.4 at the then current

market price of gas with a corresponding charge to Account 808.1, Gas

Withdrawn From Storage- Debit. If the volumes are used to meet

transportation imbalances, Account 806, Exchange Gas, will be credited

and Account 174, Miscellaneous Current and Accrued Assets, will be

debited for the same amount and simultaneously with the entries to

system gas.

Pipelines will be required to maintain records supporting Account

117.4 of monthly encroachment volumes and unit prices unless the

pipeline revalues its total encroachment balance monthly. If a pipeline

revalues the balance in Account 117.4, it should charge or credit a

separate subaccount of Account 813, Other Gas Supply Expenses, with the

amount of the revaluation. To the extent that there are corresponding

changes in the value of imbalance receivables or payables, the pipeline

should make an appropriate adjustment to Account 174, Miscellaneous

Current and Accrued Assets or Account 242, Miscellaneous Current and

Accrued Liabilities, with contra-entries to Account 813.

If a customer responsible for an owed-to-system gas balance meets

his responsibility for repayment by delivering gas in-kind, the

recorded balance for such customer in Account 174 will be reversed and

Account 806 will be debited. The amount recorded in Account 117.4 for

such volumes must be cleared and Account 808.2, Gas Delivered to

Storage--Credit, credited.

If the customer responsible for an owed-to-system gas balance meets

his responsibility through a cash-out provision, similar accounting

will be followed. To recognize settlement of the receivable, the

pipeline will reverse the recorded amount in Account 174. Any

difference between the cash-out settlement amount and the recorded

receivable will be recognized as a gain in Account 495 or a loss in

Account 813, as appropriate.

When the pipeline replaces the gas, any difference between the cost

of the gas and the amount cleared from Account 117.4 will result in a

gain or loss. The pipeline should record the gain or loss in Account

495, Other Gas Revenues, or Account 813 as appropriate with contra

entries to Account 808.2.

In instances in which a pipeline's tariff requires that gains and

losses on system balancing transactions are to be passed along to

customers, pipelines should record the gains or losses directly in

Account 254, Other Regulatory Liabilities, or Account 182.3, Other

Regulatory Assets, as appropriate.

(2) Inventory Method. Under the inventory method, withdrawals of

system gas are to be credited to Account 117.2, at the inventory cost

of gas\26\ with a corresponding charge to Account 808.1, Gas Withdrawn

From Storage-Debit. If the volumes are used to meet transportation

imbalances, Account 806, Exchange Gas, will be credited and Account

174, Miscellaneous Current and Accrued Assets, will be debited for the

same amount and simultaneously with the entries to system gas.

\26\Withdrawals of gas may be priced according to the first-in-

first-out, last-in-first-out, or weighted average cost method, in

connection with which ``the fixed asset method'' may be employed

provided the method adopted by the utility is used consistently from

year to year and the inventory records are maintained in accordance

therewith.

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The pipeline must also account for withdrawals of gas from Account

117.1 under the inventory method. However, if encroachments upon

Account 117.1 volumes are to be replaced within 12 months, the pipeline

may, at its option, account for such withdrawals in accordance with the

requirements for encroachments of system gas under the fixed asset

method. The method chosen should be applied consistently from year to

year and not changed without express approval of the Commission.

5. Fixed Asset Accounting Implementation Issues

A number of commenters requested clarification of certain aspects

of the proposed fixed asset model and noted various implementation

difficulties with the Commission's approach. The following discussion

is the Commission's response to the concerns expressed by commenters.

As stated above, the Commission is replacing Account 117, Gas

Stored Underground-Noncurrent, with four new accounts: Account 117.1,

Gas Stored-Base Gas and Account 117.2, System Balancing Gas, 117.3, Gas

Stored in Reservoirs and Pipelines--Noncurrent, and 117.4, Gas Owed to

System Gas. The Comments address those accounts.

a. Accounts 117.1 and 117.2. Williston asks for clarification that

gas previously capitalized in Account 101 [utility plant] is not to be

reclassified as Account 117.1 gas. The Commission clarifies that the

cost of gas volumes properly includable in Account 101 is not to be

reclassified to Account 117.1. The rule is making no change to the

requirements of the existing Uniform System of Accounts that the cost

of non-recoverable gas in underground reservoirs used for the storage

of gas, and the first cost of gas introduced into the utility's system

necessary to bring the pipeline system up to its designed operating

capacity or increases therein, are to be included in the plant

accounts.

Enron maintains that Accounts 117.1 and 117.2 should be combined

into a single account titled ``System Gas,'' because there is no clear

line between volumes serving a pressure maintenance function and

volumes used for system balancing.

[[Page 53024]]

The Commission will not adopt Enron's suggestion. The Commission

recognizes that a bright line separating the volumes necessary for

maintaining storage pressure and deliverability requirements from those

necessary for efficient transmission operation (i.e. system balancing

gas) does not exist for most if not all storage facilities. However,

base gas volumes in storage reservoirs are used to maintain pressure

and deliverability requirements for both customer storage and pipeline

storage of system gas. Because storage rates are often separate from

transmission only rates, it is necessary to separately identify the

cost of base gas so that proper allocations of base storage costs can

be made between storage and transmission services. Commingling base

storage with system balancing gas would make cost and rate

determinations more difficult.

CNG urges the Commission to delete the requirement to report line

pack in Account 117.2 because CNG includes line pack in plant accounts

or has expensed it already and its line pack fluctuations are

immaterial from month to month.

The final rule does not require the cost of line pack gas

previously charged to expense to be included in Account 117.2. However,

pipelines must account for volumes stored in the pipeline above line

pack volumes consistent with the rule. That is, the cost of such

additional volumes must be recorded in Account 117.2 or 117.3, as

appropriate. If the pipeline has previously charged the cost of any

such additional volumes on its system to expense such volumes must be

included in the accounts at zero cost.

NGSA would create a number of new accounts to deal with system gas.

NGSA states that although both Accounts 117 and 164.1, Gas Stored

Underground--Current, should be maintained as fixed assets, Account 164

also should be used for system balancing transactions because it is

NGSA's belief that working gas, not base gas, is cycled. It would amend

the accounts instructions to require pipelines to record both volumes

and dollars and would establish specific subaccounts in Account 164,

rather than Account 117, to match the pipeline's accounting of

imbalances by service type and rate schedule (e.g., no-notice,

exchange, gathering, FT and IT). Gas Owed to System Gas would be

reflected in Account 174.4 and a separate asset account would be

established for line pack.

The Commission will not adopt NGSA's proposal because the

Commission believes it is unnecessary to establish a separate account

for line pack or to prescribe numerous subaccounts of storage gas by

service type and rate schedule. The proposed new Accounts 117.1 through

117.4 should be adequate for accounting for all system gas. In this

regard, the Commission will modify instruction A of the proposed

Account 117.3 to include the cost of all stored gas in excess of

system, whether or not it is available for sale. Although the

Commission declines to require specific subaccounts for system gas,

pipelines may establish whatever subaccounts they deem necessary to

facilitate the needs of their individual pipelines.

Panhandle interprets the NOPR's proposal to price volumes

includible in Account 117.2 ``at the inventory price that would be

applicable to the last volumes that would be withdrawn from storage

before encroachment upon base gas'' (NOPR at p. 33,002), as requiring

restatement of all system gas that had previously been accounted for

using a LIFO or FIFO inventory method. Panhandle maintains this is

improper.

Panhandle's interpretation is incorrect. The proposed rule was not

intended to require or permit pipelines to restate the carrying value

of system gas in storage upon implementation of the new accounting. The

proposed rule clearly states that the initial investment cost to be

recorded in Accounts 117.1 and 117.2 is to be determined from the book

balances on the date of adoption of the new accounts. The statement

cited by Panhandle was intended to address potential situations where

the initial volumes of gas in storage exceeded the volumes designated

as system gas. In these situations, the cost to be assigned to Account

117.2 should be determined based on historical inventory price layers

starting with the pricing layer applicable to the last volumes that

would be withdrawn from storage before encroachment upon base gas and

continuing until all of the volumes of system gas have been priced.

b. Account 117.4. (1) Nature of the Account. The Commission

proposed Account 117.4 as an account that would reflect the obligation

to replace volumes that encroached on system supply.

Panhandle contends that the Commission has not explained whether

Account 117.4 is designed as a liability or a valuation account and

that, in any event, the proposed approach is not in accordance with

Generally Accepted Accounting Principles (GAAP). It asserts that there

is no liability on the pipeline's part to restore system gas. It then

argues that, like a valuation account, Account 117.4 reduces the

carrying value of the system gas asset, but it ``reduces system gas to

a value that is neither cost-based nor market-based, but a varying

hybrid which does not qualify as an asset account.''\27\

\27\Comments at 16.

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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.

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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).

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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.

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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.

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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.

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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.

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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.

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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)

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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.

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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).

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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.

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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.

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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.

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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).

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The Commission is also removing section 250.12, governing the form

of escrow agreements. This regulation was originally promulgated by

Order No. 400, issued April 28, 1970, in Docket No. R-376. It is rarely

used. In the instances in which companies are required to place funds

in escrow, the Commission will determine in the proceeding establishing

the escrow requirement, the form of the escrow agreement, and whether

the form should be filed with the Commission.

In the NOPR, the Commission invited comments from parties who

believe it would be useful to retain a form of escrow agreement, or

suggestions as to how this regulation could be modified to become more

useful, rather than eliminated.

Only two parties commented in response to the Commission's inquiry.

Missouri states that it has no concerns with the removal of this

section as long as the Commission will still require the placement of

funds in escrow when it deems such a remedy appropriate. Missouri

believes that establishing the requirements for such an escrow

arrangement in the proceeding where it is found appropriate is

acceptable. The Industrials, however, object to the elimination of the

form of escrow agreement in its present form from the regulations. They

urge the retention of the escrow agreement due to its value in

preserving ratepayers' refunds. They argue that if a case arises in

which a modification to the form may be appropriate, the changes to the

agreement may be addressed at the time it arises in the individual

proceedings.

The intent of the Commission's inquiry in the NOPR was to determine

whether there was support for retention of the escrow agreement in its

present form, or for adoption of a different form of escrow agreement,

instead. None of the comments suggested a more appropriate form of

escrow agreement. Rather, the parties' comments reflected concern that

the Commission was proposing to eliminate altogether the use of escrow

agreements to preserve ratepayers' refunds. The Commission's inquiry

was not intended as a referendum on the utility of escrow agreements.

The removal of section 250.12 does not prejudge the usefulness of an

escrow agreement in a particular proceeding. The decision whether an

escrow agreement should be imposed in a particular proceeding will have

to be made in that proceeding, whether section 250.12 is retained or

not. The elimination of the form of the escrow agreement should not

impact the availability of escrow agreements or degree to which they

are utilized. Therefore, since no comments were received suggesting why

the current form of escrow agreement should be retained, or any

improvements to the form of escrow agreement, the Commission will

remove this section of the regulations.

Finally, the Commission is changing all references in Part 250 from

the ``FPC'' and the ``Federal Power Commission'' to the ``FERC,'' and

to the ``Federal Energy Regulatory Commission,'' respectively.

VI. Part 260

The provisions of Part 260 require that pipelines file certain

forms and reports with the Commission, such as the FERC Form Nos. 2, 2-

A, 11, and 549-ST. As further discussed below, the Commission is

modifying the actual Form Nos. 2, 2-A, and 11, and various sections of

Part 260. The changes to Part 260 are designed to update these

reporting requirements to reflect current regulatory practice, and to

conform these prescriptive requirements to the changes to the other

parts of the Commission's regulations in this rule.

A. Revisions to Form No. 2

The Commission is revising Form No. 2 for a variety of reasons.

First, it is desirable to update Form No. 2 by deleting unneeded

schedules, or individual data elements, by clarifying and modernizing

schedules and instructions, and by increasing the thresholds for the

reporting of certain information. Second, it is vital to revise Form

No. 2 to accurately present the restructured nature of the natural gas

pipeline industry, which is primarily focused on the transportation of

gas rather than the sale of gas. Only then will the Form No. 2 provide

more useful and relevant information to the Commission and to pipeline

customers for the assessment of pipeline operations. A sample copy of

the revised Form No. 2 is attached as Appendix B.

The specific changes the Commission is making are:

General Information--Pages i and ii

The Commission is requiring Form No. 2 to be filed by each major

interstate natural gas company having combined gas transported or

stored for a fee exceeding 50 million dekatherms (Dth) in each of the

three previous calendar years. This will replace the present

requirement that Form No. 2 must be filed by major companies which are

those having combined gas sold for resale and gas transported or stored

for a fee exceeding 50 million Mcf at 14.70 psia (60 deg.F) in each of

the three previous calendar years. The elimination of ``gas sold for

resale'' reflects the current nature of the pipeline industry, in which

pipelines are primarily transporters of gas and make sales for resale

on an unbundled basis in the supply area. The replacement of Mcf with

Dth reflects the current measurement of gas by heat content rather than

by volume.

The Commission also is revising the first two sentences of

Instruction 1 on page i to eliminate as not needed the

[[Page 53034]]

statement that Form 2 is a regulatory support requirement. The last

sentence in Instruction 1 is being revised to eliminate the reference

to the Energy Information Administration's statistical publication

(Financial Statistics of Interstate Natural Gas Pipeline Companies).

The first sentence in Instruction II on page i is being revised to read

``Each major natural gas company that meets the requirements of 18 CFR

260.1 must submit this form.'' The Commission is revising Instruction

III (a) to include the present requirement for filing on an electronic

medium.

The Commission is changing Instruction III(c) to replace the

present Certified Public Accountant (CPA) certification statement with

a flexible format that will enable the respondent's CPA firm to prepare

its certification statement in accordance with current standards of

reporting and still attest as to the conformity of listed FERC Form No.

2 schedules with the Commission's Uniform System of Accounts and the

Chief Accountant's published accounting releases. In addition, the

Commission is requiring that the letter or report required by

Instruction III(c) for the CPA certification be submitted with each

copy as well as with the original submission and be submitted with that

submission rather than alternatively within 30 days after the filing

date for Form No. 2.

INGAA supports the above-described revisions. AGD maintains that

the schedule on page 108, ``Important Changes During the Year'' should

be covered by the audit report by including this page on page (i) in

the list of schedules to which the independent auditor attests.

AGD also suggests that, once the Commission updates its electronic

filing capabilities, pipelines be required to file their Form No. 2

electronically and that this filing include all backup data that

supports and elucidates the Form No. 2 information. It believes this

monthly data is critical to detect trends, spot nonrecurring items,

test the reasonableness of base period actuals, and determine the need

for a Section 5 complaint. It also suggests that pipelines post their

Form No. 2 filing on their electronic bulletin boards. Last, AGD

submits that the Commission should establish new accounts to track

computer system expenses.

The Commission does not agree that page 108 should be covered by

the independent auditor's attestation. The purpose of the CPA

certification requirement is to obtain an independent verification that

the basic financial statements in the Form No. 2 and 2-A were prepared

in conformity in all material respects with the Commission's Uniform

System of Accounts and published accounting releases. Page 108 requires

the reporting of information that is not required to be disclosed on

the face of the financial statements or the accompanying notes. To

include this page as part of a CPA certification would require

expanding the scope of the work conducted by the CPA beyond what was

necessary to attest to the conformity of the financial statements to

Uniform System of Accounts' requirements. Therefore the Commission will

not adopt AGD's request. In addition, the Commission believes the

additional burden that would be imposed would be greater than the

benefit to be realized from it. The Commission therefore rejects the

inclusion of page 108 as part of the independent auditor's attestation.

The Commission concludes that AGD's electronic filing suggestions

would be too burdensome. Therefore, although the Commission requires

pipelines to file Form No. 2 on electronic media, it will not expand

the scope of the electronic filing requirements to include all

supporting data or to require posting on an electronic bulletin board.

In addition, the Commission will not establish new accounts to track

computer system expenses because existing accounts are adequate for

this purpose.

KN would eliminate all paper copies where electronic filings are

required. Paper copies are still needed because not all respondents

have electronic capability this time.

General Instructions--Page iii

The Commission is replacing Mcf with Dth in General Instruction II

on page (ii) and ``14.73 psia and a temperature base of 60 deg.F'' with

``in Btu and Dth,'' in General Instruction XII on page (iii). The

Commission also is deleting General Instruction V with respect to the

means of completing the report as outdated and unnecessary.

INGAA supports the above described revisions.

Definitions--Page iv

The Commission is defining dekatherm as a unit of heating value

equivalent to 10 therms or 1,000,000 Btu.54

\54\Btu refers to British Thermal Unit--the quantity of heat

required to raise the temperature of one pound of water by one

degree Fahrenheit.

---------------------------------------------------------------------------

INGAA supports the above-described definition.

Excepts From the Law--Page iv

The Commission is correcting the quoted language of the Natural Gas

Act.

INGAA supports this correction.

List of Schedules (Natural Gas Company)--Pages 2-3

The Commission is revising the list of schedules to conform with

the changes to the schedules adopted by this NOPR. No comments were

filed.

Control Over Respondent--Page 102

The Commission is revising the instructions and providing a format

for information required with respect to entities controlling the

respondent natural gas company to provide better reporting of the

vertical integration of the respondent and its parents.

The Commission is deleting referencing the SEC 10-K Report Form

because most respondents are included in consolidated reports and do

not prepare separate SEC 10-K reports.

INGAA would allow referencing the SEC 10-K report. It would clarify

that the instruction refers to a direct link between the holding

company and the respondent. Missouri submits that the pipelines should

report information about affiliate relations of other companies

controlled by the pipeline's parent. It suggests including the name,

manner of control, extent of control and a brief description of the

business purpose.

Panhandle maintains that this schedule should be deleted because

material matters will be described in financial footnotes.

The Commission is removing the ability of pipelines to reference

the SEC 10-K reports for information because such references in the

past have been inadequate for regulatory purposes. The Commission's

experience has shown that the information contained in a respondent's

parent's SEC 10-K generally has not provided the detail on the

respondent that is needed by the Commission. Therefore, the Commission

is rejecting the arguments that it not adopt the NOPR's proposed

deletion of the respondent's ability to reference the SEC 10-K reports

for information. Further, based on past filings, the Commission

believes that the information to be required on page 102 will not be

included in sufficient detail (if at all) in the footnotes to the

financial statements for Commission regulatory purposes. The Commission

will therefore require the information to be reported on page 102. On

the other hand, requiring the respondents to report information about

affiliates of other companies controlled by the pipeline's parent

appears to be beyond what is needed for regulatory purposes at this

time. Therefore, the Commission will not adopt Missouri's suggestion to

[[Page 53035]]

require the reporting of such information.

Corporations Controlled By Respondent--Page 103

The Commission is deleting instruction 4, which permits referencing

the SEC 10-K Report Form filing for the reason stated above. The

Commission also is adding a new instruction 4 and new column (b) for

designation of the type of control held by the respondent. The

Commission is relettering columns (b)-(d) as (c)-(e).

INGAA would allow referencing the SEC 10-K report. Panhandle would

delete this schedule because material matters will be disclosed in

financial statements.

The Commission is adopting the changes proposed in the NOPR for

page 103 for the reasons given for adopting the proposals for page 102.

Officers--Page 104

The Commission is deleting this page because it is not needed for

Commission regulatory purposes.

INGAA supports deletion of this schedule.

Directors--Page 105

The Commission is deleting this page because it is no longer needed

for Commission regulatory purposes.

INGAA supports deletion of this page.

Security Holders and Voting Powers--Page 106 (Now 107)

Panhandle would delete this page because material matters will be

disclosed in financial footnotes.

Based on past filings, the Commission believes that information

sought by the instructions to page 106 will not be presented in the

notes to the financial statements in the detail needed for Commission

regulatory purposes. Therefore, this page will be retained.

Security Holders and Voting Powers (Continued)--Page 107

The Commission is deleting this continuation page because it is not

needed with electronic reporting since supplemental pages can be added

if more space is needed.

INGAA supports deletion of this page.

Important Changes During the Year--Page 108

The Commission is deleting item 12, which allows the respondent to

substitute notes from the annual report to stockholders for required

data because the Commission's experience shows those notes to be

inadequate or unresponsive due in part to the fact that many

respondents are included in consolidated reports to stockholders and do

not prepare separate annual reports.

INGAA suggests deleting page 108 because the information is

reported in the Notes to Financial Statement. Panhandle would also

delete this page because material matters will be disclosed in

financial statements. Williston asserts that the information required

in item 8 is proprietary and that item 11 should be deleted because it

is misleading due to the timing of final Commission rate orders and the

impact on reserves for refund purposes.

The Commission does not agree with INGAA or Panhandle that the

information reported in the Notes to Financial Statements duplicates

that required on page 108. In fact, to prevent duplication, the

instructions on page 108 direct the respondent to reference the

schedule in which information required by Page 108 appears, rather than

report the same information in both places.

As to Williston's comments, the Commission does not agree that the

information required in item 8 is proprietary because an adequate

response to the requirement to report the estimated annual effect and

nature of any important wage scale changes may be prepared so as to not

reveal proprietary information. The Commission also does not agree with

Williston that information on the estimated increase or decrease in

annual revenues due to important rate changes required by item 11 is

misleading. The respondent can and should provide explanations to

prevent wrongful interpretations of the data.

Important Changes During the Year--Page 109

The Commission is deleting this continuation page because it is not

needed with electronic reporting.

No comments were filed.

Comparative Balance Sheet (Assets and Other Debits)--Page 110

The Commission is modifying column (c) by deleting ``Balance at

Beginning of Year'' and inserting ``Balance at End of Current Year (in

dollars)'' and is modifying column (d) by deleting ``Balance at End of

Year (in dollars)'' and inserting ``Balance at End of Previous Year (in

dollars).'' The Commission also is deleting ``Gas Stored Underground

Noncurrent (117)'' at Line 12 and replacing it with four new accounts--

Gas Stored--Base Gas (117.1), System Balancing Gas (117.2), Gas Stored

in Reservoirs and Pipelines--Noncurrent (117.3), and Gas Owed to System

Gas (117.4). The Commission further is changing the title on Line 16

from ``Other'' to ``Other Property and Investments.''

The comments addressing the proposed storage accounting are

discussed above.

Comparative Balance Sheet (Assets and Other Debits) (Continued)--Page

111

The Commission is modifying column (c) by deleting ``Balance at

Beginning of Year'' and inserting ``Balance at End of Current Year (in

dollars)'' and is modifying column (d) by deleting ``Balance at End of

Year'' and inserting ``Balance at End of Previous Year (in dollars).''

No comments were filed.

Comparative Balance Sheet (Liabilities and Other Credits)--Page 112

The Commission is modifying column (c) by deleting ``Balance at

Beginning of Year'' and inserting ``Balance at End of Current Year (in

dollars)'' and is Modifying Column (d) by deleting ``Balance at End of

Year'' and inserting ``Balance at End of Previous Year (in dollars).''

The Commission also is adding the language ``(Less) Current Portion of

Long-Term Debt'' to Line 22.

INGAA supports the above-described revisions.

Comparative Balance Sheet (Liabilities and Other Credits) (Continued)--

Page 113

The Commission is modifying column (c) by deleting ``Balance at

Beginning of Year'' and inserting ``Balance at End of Current Year (in

dollars)'' and modifying column (d) by deleting ``Balance at End of

Year'' and inserting ``Balance at End of Previous Year (in dollars).''

INGAA supports the above-described revisions. The Commission is

adding the language ``Current Portion of Long-Term Debt'' as line No.

33.

Statement of Income For the Year--Pages 114-116

The Commission is moving instructions 5 and 6 from this schedule to

Notes to Financial Statements on page 122.

INGAA would clarify that the proper accounts for lines 9 and 10 are

407.1 and 407.2 to be consistent with the Uniform System of Accounts.

The Commission agrees and is changing the account numbers on lines

9 and 10 to 407.1 and 407.2 respectively.

The Commission is deleting instruction 7, which permits the

attaching at page 122 of any notes appearing in the report to

stockholders that are applicable to this Statement of Income, and is

moving instruction 8

[[Page 53036]]

from this schedule to Notes to Financial Statements on page 122.

INGAA supports the above-described revisions.

The Commission is adding the words ``(in dollars)'' to column

headings (c) through (j).

Statement of Retained Earnings For the Year--Page 118

The Commission is modifying column (c) by deleting ``Amount'' and

inserting ``Current Year Amount (in dollars)'' and by adding column (d)

``Previous Year Amount (in dollars).'' The Commission also is deleting

instruction 8, which requires the attaching at page 122 of applicable

notes in the annual report to stockholders.

INGAA supports the above-described revisions. Consistent with

discussion of the revisions to page 118 of Form No. 2-A, the Commission

will revise line 36 to read ``Balance--End of Year (Total of lines 1,

9, 15, 16, 22, 28, 34, and 35)''.

Statement of Retained Earnings For the Year (Continued)--Page 119

The Commission is modifying column (c) by deleting ``Amount'' and

inserting ``Current Year Amount (in dollars)'' and is adding column (d)

``Previous Year Amount (in dollars).''

INGAA supports the above-described revisions.

Statement of Cash Flows--Pages 120 and 121

The Commission is deleting the first sentence of instruction 1,

which requires the attachment at page 122 of applicable notes in the

annual report to stockholders.

The Commission is modifying column (b) by deleting ``Amounts'' and

inserting ``Current Year Amount'' and by adding Column (c) ``Previous

Year Amount.''

INGAA supports the above-described revisions.

Notes to Financial Statements--Page 122

The Commission is changing instruction 1 to require at least the

same level of detail for disclosures that would be given in shareholder

annual reports and is adding new instructions to provide significant

details on: the respondent's pension and other benefit plans and

disclosure of financial changes either to the respondent or the

respondent's consolidated group that will directly affect the

respondent's gas pipeline operations. The Commission also is deleting

instructions 3 (``For Account 116, Utility Plant Adjustments'') and 6

(permitting the attaching of notes to financial statements in the

annual report to stockholders). In addition, as stated above, the

Commission is moving three instructions from pages 114 and 115 to page

122. As discussed below, the Commission is not adopting proposed

instructions 4 (income taxes) or 7 (differences between financial

statements to stockholders/public and Form No. 2).

INGAA recommends changes to improve the focus of information to be

provided on this page. It would allow a reference to SEC 10-K reporting

or reliance on GAAP for information on pensions, benefits, deferred

taxes, etc. It suggests removing the requirement in Instruction 1 that

notes be grouped under subheadings for each financial statement because

most notes apply to more than one financial statement. It submits that

this requirement could increase the number of notes and the duplication

of information. It adds that GAAP does not require grouping of notes by

financial statement and that this requirement creates a difference

between GAAP and FERC reporting that is not needed or useful to the

reader. It would delete instructions 2, 4, and 5. It would revise

Instruction 3 to exclude the disclosure of cash contributions to

pension, PBOP and other post-employment benefit plans since, it

asserts, GAAP disclosures for those plans are adequate for Form 2. It

would revise Instruction 7 because this should not be a regulatory

requirement, except in limited instances where differences are not

consistent with the Uniform System of Accounts or FERC Orders. It

further states that the general purpose financial statements issued to

shareholders or the public generally refer to the respondent's

financial statements, and not those of the respondent's parent or

ultimate parent. It states that instruction 11 requires explanations of

changes in accounting methods made during the year which had an effect

on net income. It maintains that instruction 11 should be revised to

limit the requirement to significant changes.

AGD would include any differences in accounting classifications

between Form No. 2 and the latest NGA section 4 rate filing with more

than a $3-4 million impact.

Columbia maintains it would be an undue burden to list pursuant to

proposed instruction 7 the differences in the way transactions are

presented in the stockholders annual report versus the Form No. 2. It

argues that the proposed requirement to disclose financial changes that

will directly affect pipeline operations is unnecessarily duplicative

of information that is reported on page 108.

National Fuel submits that disclosures should be in accordance with

GAAP as reflected in general purpose financial statements to the public

or to shareholders, so that pipelines would not be forced to rewrite

their Notes for the version of their financial statements incorporated

in the Form No. 2. It also suggests that, because Form No. 2 will

include a complete set of Notes to Financial Statements, any

accompanying notes filed on an interim basis in other contexts (e.g., a

new rate case) be deemed sufficient if they make the financial

statements not misleading. It states that it assumes the reader has

read the most recent Form No. 2.

The Commission concurs with the commenters who question the

regulatory applicability and the burden that will be caused by proposed

instruction 7 and is deleting it. The Commission concurs with the

comment that GAAP is sufficient for information on income taxes and is

deleting proposed instruction 4. The Commission also agrees that

instruction 11 should only require information on significant changes

in accounting methods made during the year that had an effect on net

income and is revising the wording in that instruction to read: ``* * *

significant changes in accounting methods * * *''

The Commission does not agree that a reference to the SEC 10-K is

sufficient and therefore will not allow referencing the SEC 10-K. As

explained above, the Commission has found that such references in the

past were inadequate for regulatory purposes.

The Commission does not agree that instruction 1 should be revised

as proposed by National Fuel because no rewriting is needed of the

disclosures in general purpose financial statements. Rather, respondent

merely will supplement those disclosures with information needed for

Commission regulatory purposes.

The Commission also does not agree with the comment that the

requirement in instruction 1 to group notes by financial statement

subheadings will result in duplication. The instruction is flexible in

allowing separate disclosure of items that are applicable to more than

one financial statement.

In answer to the commenter who wants to exclude from proposed

instruction 3 the cash contributions to pension, PBOP and other post-

employment benefit plans, the reporting of cash contributions is

necessary to aid the Commission staff in their determination of the

level of these costs includible in a pipeline's rates.

[[Page 53037]]

Likewise, the retention of instructions 2 and 5 is essential in the

Commission's ongoing analysis of the effect on rates of certain actions

taken by a company. The Commission will not adopt AGD's recommendation

to require reporting of significant differences between Form 2

accounting classifications and those used for rate filings because the

accounting required for Form No. 2 must be consistent with that used

for ratemaking purposes. Last, the Commission rejects National Fuel's

suggestion that Form No. 2 notes may be filed in other contexts,

because the Commission does not believe that filing updated notes will

be unduly burdensome.

Notes to Financial Statement (Continued)--Page 123

The Commission is deleting this continuation page because it is not

needed with electronic reporting.

No comments were received.

Summary of Utility Plant and Accumulated Provisions for Depreciation,

Amortization and Depletion (Continued)--Page 201

The Commission is deleting columns (f) and (g) both entitled

``other (specify)'' as unneeded because electronic reporting permits

additional columns to be added as necessary.

INGAA supports the above-described revision.55

\55\In this schedule's pages, the Commission is also deleting

duplicative columns of account numbers.

---------------------------------------------------------------------------

Gas Plant In Service (Accounts 101, 102, 103, and 106)--Pages 204-209

The Commission proposed no changes to these pages. However,

consistent with the Commission discussion below of revisions to these

pages of Form No. 2-A, the Commission will modify these Form No. 2

pages to indicate which lines are used for totals.

Gas Property and Capacity Leased From Others--Page 212

The Commission is adding a new schedule to provide information

about gas property and capacity leased from others. The Commission is

requiring only the reporting of property leases in which the average

annual lease payment under the initial term of the lease exceeds

$500,000.

INGAA responds that information requested by the NOPR is at a level

of detail that is not needed. It asks for clarification that reporting

is for gas property and capacity leased from others pertaining to gas

operations. INGAA and Panhandle comment that pipelines should disclose

only names of lessor, description of leases, and lease payments.

Panhandle would raise the threshold to $1,000,000.

The Commission clarifies that reporting is for gas property and

capacity leased from others pertaining to gas operations and agrees

that pipelines need to disclose only the name of the lessor,

description of lease, and lease payments. The instructions will so

indicate. The Commission will not raise the threshold to $1,000,000

because that level is too high for the reporting of meaningful

information.

Gas Property and Capacity Leased To Others--Page 213

The Commission is revising the schedule on page 213 entitled ``Gas

Plant Leased to Others (Account 104)'' by changing the schedule and

instructions about gas property and capacity leased to others. The

changes are necessary to provide information that would allow the

Commission to determine whether ratepayers are paying for facilities

not used in the respondent's utility operations. The Commission is

requiring only the reporting of property leases in which the average

annual lease income over the initial term of the lease exceeds

$500,000.

INGAA asks for clarification that reporting is for gas property and

capacity leased to others pertaining to gas operations. It comments

that columns (c) and (e) are missing on the form.

The Commission so clarifies and has corrected the columns.

Gas Plant Held For Future Use (Account 105)--Page 214

The Commission is raising the reporting threshold of $250,000 to

$1,000,000 as suggested by INGAA, rather than to $500,000 as proposed

in the NOPR. The Commission is also deleting the language in Line No. 1

which refers to pages 500-01, which are proposed to be deleted.

Production Properties Held For Future Use (Account No. 105.1)--Page 215

The Commission is deleting this schedule because it is not needed

for Commission regulatory purposes.

INGAA supports deletion of this schedule.

Construction Work In Progress--Gas (Account 107)--Page 216

The Commission is raising the threshold from $500,000 to $1,000,000

as suggested by INGAA and Panhandle. The NOPR had proposed no change to

the $500,000 threshold.

Construction Overheads--Gas--Page 217

The Commission, as suggested by INGAA, is deleting this page

because page 218 reports adequate information.

Gas Stored (Accounts 117.1, 117.2, 117.3, 117.4, 164.1, 164.2, and

164.3)--Page 220

The Commission is deleting Account 117 and replacing it with four

new accounts as discussed above. The Commission also is changing Mcf to

Dth in instruction 1 and lines 6 and 7, is redesignating the column

letters, eliminating instructions 2 through 5 as no longer necessary,

and adding a new instruction on encroachments on base gas, system

balancing gas, and gas properly recordable in the plant accounts.

INGAA suggests that additional changes may be required on this page

to accommodate the actual use of storage inventories. NGSA states this

page should match page 513 and page 513 should have reporting by

account.

The Commission believes this schedule is adequate as proposed and

will make no further changes to it. The Commission does not agree with

the comment that this page should match page 513; the two schedules

serve different purposes. Page 220 is a supplement to the Balance Sheet

and page 513 is meant only for operational data.

Nonutility Property (Account No. 121) and Accumulated Provision For

Depreciation and Amortization of Nonutility Property (Account 122)--

Page 221

The Commission is deleting these schedules because they are not

needed for Commission regulatory purposes.

INGAA supports this deletion. The APGA opposes deletion because

this page has vestigial value about changes is a pipeline's business.

The Commission does not believe that vestigial value supports the

burden of reporting this information.

Investments (Accounts 123, 124, 136)--Pages 222-225 and Investments in

Subsidiary Companies (Account 123.1)--Pages 224 and 225

The Commission did not propose any changes to these pages.

INGAA and Panhandle would delete these pages. INGAA states the

information has no regulatory purpose. Panhandle states that material

matters will be described in financial footnotes.

The Commission will retain these pages because the required data

provides the Commission with relevant information that is useful in

[[Page 53038]]

determining the respondent's affiliations and in analyzing financing

arrangements that may affect regulated pipeline operations. In

addition, the Commission, based on past filings, concludes that the

data will not be presented in the notes to the financial statements in

the detail needed for Commission regulatory purposes.

Gas Prepayments Under Purchase Agreements--Pages 226 and 227

The Commission is deleting this schedule because it is not needed

for Commission regulatory purposes.

INGAA supports this deletion. But the APGA opposes it because this

page has vestigial value about changes in a pipeline's business.

The Commission does not believe that vestigial value supports the

burden of reporting this information.

Advances For Gas Prior to Initial Deliveries or Commission

Certification (Accounts 124, 166, and 167)--Page 229

The Commission is deleting this schedule because it is not needed

for Commission regulatory purposes.

INGAA supports deleting this schedule.

Prepayments (Account 165)--Page 230

The Commission is eliminating the instruction requiring the

reporting of all payments for undelivered gas and the completion of

pages 226 to 227, along with Line 5, Gas Prepayments (pages 226-227).

Pages 226 and 227 are also eliminated.

INGAA supports the revisions in order to make this page consistent

with pages 226 and 227. The Commission is also adding a column entitled

``Balance at Beginning of year.''56

\56\This column is also being added to the schedules,

``Extraordinary Property Losses (Account 182.1)'' and ``Unrecovered

Plant and Regulating Study Costs (Account 182.2).''

---------------------------------------------------------------------------

Preliminary Survey and Investigation Charges (Account 183)--Page 231

The Commission is deleting this schedule because it is not needed

for Commission regulatory purposes.

INGAA supports deleting this schedule.

Other Regulatory Assets (Account 182.3)--Page 232

The Commission is raising the reporting threshold for minor items

from $50,000 to $250,000 rather than to $100,000 as proposed in the

NOPR. The Commission is adding new instruction 4--``Report separately

any `deferred regulatory Commission expenses' that are also reported on

pages 350-351, Regulatory Commission Expenses''.

INGAA agrees with the proposed revisions and, along with Columbia,

suggests the addition of a beginning balance field. Transco would raise

the threshold to $500,000 and Panhandle would raise it to $1,000,000.

The Commission will add a beginning balance field and, as stated,

will raise the threshold to $250,000, consistent with the threshold we

are adopting for other asset and liability schedules. This threshold

will mitigate the reporting burden on pipelines while providing the

Commission with useful information for small as well as large

pipelines.

Miscellaneous Deferred Debits (Account 186)--Page 233

The Commission is raising the reporting threshold for minor items

from $100,000 to $250,000 and is deleting Line No. 48 ``Deferred

Regulatory Commission Expenses (see pages 350-351).

INGAA and Columbia support this revision, but would also delete

``Account charged'' col. (d). Transco would raise the threshold to

$500,000. Panhandle would raise it to $1,000,000.

The Commission believes that column (d) should be retained as it

provides useful information and that the $250,000 threshold is the

appropriate threshold level for this information.

Accumulated Deferred Income Taxes (Account 190)--Pages 234-235

The Commission did not propose any changes to these pages.

INGAA would delete the ``Notes'' section and follow the pages 274

and 275 format, which it says is more consistent and better organized.

The Commission will make the format of pages 234-235 consistent

with that of pages 274-275. However, the Commission will retain the

``Notes'' section.

Capital Stock (Accounts 201 and 204)--Pages 250 and 251

The Commission is deleting part of instruction 1, which permits

referencing the SEC 10-K Report Form filing. The Commission is making

this deletion because many respondents are included in consolidated

reports that do not provide the required information about the

respondent. The Commission discusses below the arguments to delete this

schedule.

Capital Stock subscribed, Capital Stock Liability For Conversion,

Premium on Capital Stock, and Installments Received on Capital Stock

(Accounts 202 and 205, 203 and 206, 207, 217)--Page 252

The Commission below discusses the arguments to delete this

schedule.

Other Paid-in Capital (Accounts 208-211, inc.)--Page 253

The Commission discusses below the arguments to delete this

schedule.

Discount on Capital Stock (Account 213)--Page 254

The Commission discusses below the arguments to delete this

schedule.

Capital Stock Expense (Account 214)--Page 254

The Commission discusses below the arguments to delete this

schedule.

Securities Issued or Assumed and Securities Refunded or Retired During

the year 1992--Page 255

The Commission discusses below the arguments to delete this

schedule.

Long-Term Debt (Accounts 221, 222, 223, and 224)--Page 256

The Commission is deleting part of instruction 1, which permits

referencing the SEC 10-K report Form filing for the reason stated

above.

The Commission discusses below the arguments to delete this

schedule.

Unamortized Debt Expense, Premium and Discount on Long-term Debt

(Accounts 181, 225, and 226)--Pages 258 and 259

The Commission discusses below the arguments to delete this

schedule.

Unamortized Loss and Gain on Reacquired Debt (Accounts 189, 257)--Page

260

INGAA and Panhandle maintain that the above pages (250-260) should

be deleted because material matters will be in the Footnotes to the

Financial Statements or there is no regulatory purpose for the

information.

The Commission disagrees with INGAA and Panhandle. The information

required to be reported on pages 250-260 is not detailed in the

footnotes to the Financial Statements. This information allows the

Commission and the public to determine the cost and changes in the

levels of the respondent's debt, preferred and common stock. Such

information is directly relevant to the pipeline's cost of providing

service. Therefore, the Commission will not delete these pages.

[[Page 53039]]

Reconciliation of Report Net Income With Taxable Income for Federal

Income Taxes--Page 261

The Commission did not propose any changes to this page.

INGAA would delete this schedule because there is no regulatory

purpose for this information.

The Commission disagrees. The information on this page is useful in

analyzing the pipeline's Federal income tax component of its cost of

service, including its deferred taxes. Therefore, this page will be

retained.

Taxes Accrued, Prepaid and Charged During Year--Pages 262 and 263

The Commission proposed no change to this schedule.

INGAA suggests the grouping of minor items under $250,000 and the

reporting by type rather then by state and year.

Panhandle would revise the instructions to report taxes prepaid and

charged by type only and eliminate the excessive detail of reporting by

type of tax, by state, and by year.

The Commission does not agree that reporting by type of tax, by

state and by year is excessive detail. Rather, it is essential to the

Commission in determining the yearly effects of federal and local taxes

on the costs of pipeline operations. To only report the type of tax

without any breakdown by year or local jurisdiction would render the

information practically useless for analysis or analytical purposes.

The Commission will permit the grouping of items under $250,000.

Investment Tax Credits Generated and Utilized--Pages 264 and 265.

The Commission is deleting this schedule because it is not needed

for Commission regulatory purposes.

INGAA supports this deletion. But the APGA would retain this

schedule because the information has vestigial value about changes in a

pipeline's business. The Commission does not believe that vestigial

value supports the burden of reporting this information.

Accumulated Deferred Investment Tax Credits (Account 253)--Pages 266

and 267

The Commission is deleting this schedule because it is not needed

for Commission regulatory purposes.

INGAA supports deleting this schedule. But the APGA would retain

this schedule because the information has vestigial value about changes

in a pipeline's business. The Commission does not believe that

vestigial value supports the burden of reporting this information.

Miscellaneous Current and Accrued Liabilities (Account 242)--Page 268

The Commission is raising the reporting threshold for minor items

from $100,000 to $250,000.

INGAA supports this revision. Transco, however, would raise the

threshold to $500,000. The Commission believes that $250,000 is the

appropriate threshold level for this information.

Other Deferred Credits (Account 253)--Page 269

The Commission is raising the reporting threshold for minor items

from $100,000 to $250,000 and is deleting instruction 4 as not needed

for Commission regulatory purposes in that it refers to undelivered gas

obligations to customers under take-or-pay clauses in sales agreements.

INGAA supports above-described revisions and would delete ``Contra

account,'' col. (c), as would Columbia. Panhandle would raise the

threshold to $1,000,000. Transco would raise it to $500,000.

The Commission will not delete column (d) because it provides

useful information and the Commission believes that $250,000 is the

appropriate threshold level for this information.

Undelivered Gas Obligations Under Sales Agreements--Pages 270 and 271

The Commission is deleting this schedule because it is not needed

for Commission regulatory purposes.

INGAA supports deleting this schedule. But the APGA would retain it

because it has vestigial value about changes in a pipeline's business.

The Commission does not believe that vestigial value supports the

burden of reporting this information.

Accumulated Deferred Income Taxes--Accelerated Amortization Property

(Account 281)--Pages 272 and 273

The Commission is deleting this schedule because it is not needed

for Commission regulatory purposes.

INGAA supports deleting this schedule. But the APGA would retain it

because it has vestigial value about changes in a pipeline's business.

The Commission does not believe that vestigial value supports the

burden of reporting this information.

Accumulated Deferred Income Taxes--Other Property (Account 283)--Pages

276 and 277

The Commission proposed no change to this schedule.

INGAA would make the format consistent with pages 274 and 275. In

the Form No. 2 appendix in the final rule, the two schedules will be

consistent.

Other Regulatory Liabilities (Account 254)--Page 278

The Commission is raising the reporting threshold for minor items

from $50,000 to $250,000 as suggested INGAA, rather than to $100,000 as

proposed in the NOPR. The Commission is correcting a typographical

error and, as suggested by INGAA and Columbia, is adding a beginning

balance field.

INGAA would delete ``Contra account'' col. (b). Panhandle would

raise the threshold to $1,000,000. Transco would raise it to $500,000.

The Commission will not delete column (b) ((now (c)) because it

provides useful information needed for regulatory purposes. In

addition, the Commission believes the $250,000 threshold is the

appropriate threshold for this information.

Gas Operating Revenues (Account 400)--Pages 300 and 301

The Commission is adopting substantial and significant changes to

this schedule. The changes are: (1) The elimination of instruction 1's

reference to manufactured gas revenues; (2) the deletion of instruction

2 defining natural gas; (3) the deletion of instruction 3 and present

columns (f) and (g) concerning average number of natural gas customers

per month; (4) the deletion of instruction 4 with respect to Mcf and

therms; (5) the revision of instruction 5 to eliminate the reference to

columns (c), (e), and (g); (6) the deletion of instruction 6 concerning

commercial and industrial sales; (7) the revision of instruction 7 to

read, on page 108, include information on major changes during year,

new service, and important rate increases or decreases;'' (8) the

addition of new instruction 2 to provide that revenues for transition

costs include transition costs from upstream pipelines;57 (9) the

addition of new instruction 3 to provide that other revenues in columns

(f) and (g) include reservation charges received by the pipeline plus

usage charges less revenues reflected in columns (b) through

(e);58 (10) the addition of a new instruction 6 with respect to

reporting the revenue of bundled transportation and storage service as

transportation service revenue; (11) the revising of operating revenues

in columns (b) and (c) to revenues for transition costs and take-or-pay

costs, (12) the deletion of lines 2-12 and 28-32, which provide for

[[Page 53040]]

the reporting of sales revenues; (13) the addition of lines to show

separately gas sales revenues,59 and transportation revenues

associated with gathering, transmission, and distribution facilities,

and revenues from storage services; and (14) added columns for GRI and

ACA revenues, other revenues, and total operating revenues and

dekatherms of natural gas, each for the current reporting year and the

previous year.60

\57\For example, Order No. 636 transition costs.

\58\The respondent must include in columns (f) and (g) revenues

for Accounts 480-495.

\59\The proposed new sales line includes Accounts 480-84 which

are now reported on lines 2-12.

\60\Penalty revenues are to be reported on page 308, Other Gas

Revenues.

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The Commission's main reason for adopting these changes is to

recognize that pipelines now receive most of their revenues from

transportation and not sales. Hence, the breakout of information by

types of sales is not needed. The Commission is breaking out Account

489 into four new accounts (Accounts 489.1--489.5) as discussed above.

INGAA maintains that gathering quantities should not be included in

total throughput columns (l) and (m), because they may also be reported

as transmission. It seeks clarification whether dekatherms are to be

reported in millions. It seeks clarification that ``other'' revenues

includes only the pipeline's transition or take or pay costs and not

those of upstream pipelines. It seeks clarification that GSR costs

included in interruptible rates need not be reported separately.

Commission response:

The Commission has not provided for totals in the dekatherm columns

to avoid double counting. Dekatherms are to be reported in units rather

than in millions. As stated above, upstream pipeline transition and

take-or-pay costs are to be included in revenues in columns (b) and

(c). Last the allocated portion of GSR costs for interruptible rates

should be included in columns (b) and (c) and not separately reported.

AGD maintains that the Commission should require pipelines to show

revenues by month to avoid standard data requests in rate cases for

that information. The Commission concludes that such reporting would be

unduly burdensome because it is too detailed for reporting purposes.

Revenues from Transportation of Gas of Others Through Gathering

Facilities (Account 489.1) and Dth Gathered--Pages 302 and 303

The Commission is replacing the schedule ``Distribution Type Sales

by States'' with several new schedules. The current schedule, which

reflects residential, commercial, and industrial revenues and volumes

by state is no longer needed for Commission regulatory purposes because

with unbundling those sales are now unbundled and occur in the

production area rather than in the market area.

In response to the comments,61 the Commission is combining

into a single schedule the NOPR's proposed schedules on pages 302-304

and 312(b) and 313(b) to eliminate redundant reporting. However, the

Commission is not, as suggested by some commenters,62 combining

these proposed schedules and the schedule on pages 300-301 into a

single schedule. The Commission believes it convenient for gathering,

transportation, and storage data to be reported on their own schedules.

\61\E.g., Columbia.

\62\E.g., INGAA.

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The Commission does not agree with Panhandle and ANR that these

should only be one schedule with only summary totals.63 Such

limited information is not adequate for regulatory purposes.

\63\CNG maintains that dekatherm does not equal throughput.

Dekatherms is an appropriate and recognized way to measure

deliveries even though it does not measure volumes. Most pipelines'

rates are based on dekatherms.

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In the new Revenues from Transportation of Gas of Others Through

Gathering Facilities Schedule, the pipeline will have to report its

revenues by zone of receipt and by rate schedule.64 The pipeline

would have to report for both the current and previous year its

revenues for transition costs and take-or-pay costs, revenues for GRI

and ACA, other revenues,65 and total operating revenues, and its

Dth of gas delivered.66 The Commission believes that this schedule

will provide the information needed with respect to gathering to obtain

a good description of the pipeline's activities in the unbundled

environment.

\64\If a pipeline has no rate schedule, it should report by

rate.

\65\Other revenues include reservation charges received by the

pipelines plus usage charges, less revenues reflected in columns (b)

through (e).

\66\As suggested by INGAA, the Commission has eliminated

duplicative column (a).

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The Commission has deviated from the NOPR by requiring reporting by

zone of receipt and by rate schedule rather than by state of delivery,

by customer, by rate as in the NOPR's proposed gathering schedules. The

Commission believes that reporting by zone of receipt and by rate

schedule will provide the appropriate information needed for regulatory

purposes without undue burden on the pipeline industry. The Commission

does not believe that such customer information is necessary outside of

the context of a rate proceeding. The Commission believes that it has

thus addressed INGAA's concernabout providing customer data and its

concern that pipelines may not know the exact delivery point from a

multi-point contract, and will have to make an arbitrary allocation to

a state.

The Commission will discuss further here only those comments

specific to gathering. Comments applicable to gathering and also to

other services will be addressed below in the discussion of the

transportation schedule.

Columbia maintains that gathering revenues should be reported by

state of receipt into the system. As stated above, the Commission is

requiring reporting by zone of receipt into the pipeline's system.

Revenues from Transportation of Gas of Others Through Transmission

Facilities (Account 489.2)--Pages 304 and 305

In the new Revenues from Transportation of Gas of Others Through

Transmission Facilities and Dth Transported Schedule, the pipeline

would have to report its revenues by zone of delivery and by rate

schedule. The pipeline would have to report for both the current and

previous year its revenues for transition costs, and take-or-pay costs,

revenues for GRI and ACA, other revenues,67 and total operating

revenues, and its Dth of gas delivered. The Commission believes that

this reporting reflects the current unbundled environment's emphasis on

transportation for others.

\67\Other revenues include reservation charges received by the

pipeline plus usage charges, less revenues reflected in columns (b)

through (e).

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The Commission has deviated from the NOPR by requiring reporting by

zone of delivery and by rate schedule rather than by state of delivery

by customer and by rate schedule as in the NOPR's proposed

transportation schedules. The Commission believes that reporting by

zone of delivery and by rate schedule will provide the appropriate

information needed for regulatory purposes without undue burden on the

pipeline industry. The Commission does not believe that such customer

information is necessary outside of the context of a rate proceeding.

The Commission believes that it has thus addressed INGAA's concern

about providing customer data, including its concern about the

difficulty of complying with the NOPR's customer-data requirement for

some pipelines. The Commission also observes, as did INGAA, that Form

EIA-176 collects state information which, in any event, is not of use

to the

[[Page 53041]]

Commission. The Commission further observes that both the NGSA and AGD

support reporting by zones.68

\68\As suggested by Transco, the Commission has deleted the

requirement that revenues be reported in millions.

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INGAA also submits that transportation quantities appear to require

gathering quantities to be included in transportation totals and since

gathering system quantities will already be included in transmission

deliveries, gathering should not be added to other quantities. CNG also

maintains that gathering is included in transportation. As clarified

with respect to pages 300 and 301, these quantities are not totalled to

avoid double counting.

The Commission has not expanded the coverage of the schedules as

proposed by some commenters. NGSA maintains that reporting should be by

customer type, with MDQ levels, demand and commodity volumes, discount

information, and base and surcharge revenues. AGD submits that revenues

and volumes reporting should be reported by rate schedule by zone of

delivery (not state), and should include with short-term firm

transportation. APGA enthusiastically supports pages 312 and 313,

especially transportation throughput as solely needed. It would add

details on contracts of less than one year as well as contracts of one

year and longer (revenues and volumes).

DOE maintains that the Commission should require the pipelines to

provide a menu of service categories;69 an additional field to

denote type of customer, along with standardized customer numbers;

mileage information; and totals by state and by type of service.

\69\E.g., short-term firm transportation and released firm

transportation.

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The Commission believes the above suggestions would be unduly

burdensome in light of the limited use of the information for

regulatory purposes.

Revenues from Storing of Gas of Others (Account 489.4)--Pages 306 and

307

In the new Revenues from Storing of Gas of Others schedule, the

pipeline would have to report its revenues and Dth of gas withdrawn

from storage by rate schedule. The pipeline would have to report for

both the current and previous year its revenues from transition costs

and take-or-pay costs, revenues from GRI and ACA, other

revenues,70 and total operating revenues, and the Dth withdrawn

from storage.

\70\Other revenues include reservation charges deliverability

charges, injection and withdrawal charges, less revenues reflected

in columns (b) through (e).

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The Commission believes that this schedule will provide the

information needed with respect to unbundled storage to obtain a good

description of the pipeline's activities in the unbundled environment.

The Commission has deviated from the NOPR by requiring reporting by

rate schedule rather than by rate schedule by customer as on the NOPR's

proposed schedules. The Commission believes that reporting by rate

schedule will provide the appropriate information needed for regulatory

purposes without undue burden. INGAA contends that storage revenues are

not tied to withdrawals and Columbia asks why storage injections as

well as storage withdrawals are not included. The Commission is not

tying the reporting of storage revenues by withdrawals. Rather, all

revenues received for storage during the reporting year must be

reported. The Commission has required Dth reporting by withdrawals

because withdrawal completes the storage cycle and such information

should be adequate for regulatory pur

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