[Federal Register Volume 60, Number 196 (Wednesday, October 11, 1995)]
[Rules and Regulations]
[Pages 53019-53075]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 95-24722]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Parts 2, 157, 158, 201, 250, 260, 284, 381, and 385
[Docket No. RM95-4-000; Order No. 581
Revisions to Uniform System of Accounts, Forms, Statements, and
Reporting Requirements for Natural Gas Companies
Issued: September 28, 1995.
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Final rule.
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SUMMARY: The Federal Energy Regulatory Commission is amending its
Uniform System of Accounts, its forms, and its reports and statements
for natural gas companies. The amendments reflect the current
regulatory environment of unbundled pipeline sales for resale at
market-based prices and open-access transportation of natural gas. The
Commission seeks to simplify and streamline its requirements to reduce
the burden of respondents.
[[Page 53020]]
EFFECTIVE DATE: The final rule is effective November 13, 1995, except
for the changes to the Uniform System of Accounts (Part 201).
FOR FURTHER INFORMATION CONTACT: Jeffrey A. Braunstein, Office of the
General Counsel, Federal Energy Regulatory Commission, 825 North
Capitol Street, NE., Washington, DC 20426, (202) 208-2114.
SUPPLEMENTARY INFORMATION: In addition to publishing the full text of
this document, excluding Appendices B (FERC Form No. 2), C (FERC Form
No. 2-A), and D (FERC Form No. 11), in the Federal Register, the
Commission also provides all interested persons an opportunity to
inspect or copy the contents of this document during normal business
hours in Room 3104, 941 North Capitol Street, NE., Washington, DC
20426.
The Commission Issuance Posting System (CIPS), an electronic
bulletin board service, provides access to the texts of formal
documents issued by the Commission. CIPS is available at no charge to
the user and may be accessed using a personal computer with a modem by
dialing (800) 856-3920. To access CIPS, set your communications
software to 19200, 14400, 12000, 9600, 7200, 4800, 2400 or 1200bps,
full duplex, no parity, 8 data bits, and 1 stop bit. The full text of
this document will be available on CIPS in ASCII and WordPerfect 5.1
format. The complete text on diskette in Wordperfect format may also be
purchased from the Commission's copy contractor, La Dorn Systems
Corporation, also located in Room 3104, 941 North Capitol Street, NE.,
Washington, DC 20426.
I. Introduction
The Federal Energy Regulatory Commission (Commission) hereby amends
its Uniform System of Accounts,1 its forms, and its reports and
statements for natural gas companies.2 This Final Rule is a
companion to the Commission's Final Rule ``Filing Requirements for
Interstate Natural Gas Company Rate Schedules and Tariffs'', which
amends Part 154 of the Commission's regulations and is issued
contemporaneously with this rule. The Commission has received 41
comments on the Notice of Proposed Rulemaking (NOPR)3 in this
docket from the commenters listed in Appendix A.4
\1\Section 8 of the Natural Gas Act (NGA), 15 U.S.C. 717g
(1988), authorizes the Commission to prescribe rules and regulations
concerning accounts, records and memoranda as necessary or
appropriate for purposes of administering the NGA. The Commission
may prescribe a system of accounts for jurisdictional companies and,
after notice and opportunity for hearing, may determine the accounts
in which particular outlays and receipts will be entered, charged,
or credited.
\2\Section 10 of the NGA, 15 U.S.C. 717i (1988), authorizes the
Commission to prescribe rules and regulations concerning annual and
other periodic or special reports, as necessary or appropriate for
purposes of administering the NGA. The Commission may prescribe the
manner and form in which such reports are to be made, and require
from natural gas companies specific answers to all questions on
which the Commission may need information. The reports must be made
under oath unless the Commission otherwise specifies.
\3\Revisions to Uniform System of Accounts, Forms, Statements,
and Reporting Requirements for Natural Gas Pipelines, 60 FR 3141
(January 13, 1995), IV FERC Stats. & Regs. Proposed Regulations
para. 32,512 (December 16, 1994).
\4\Appendix A also sets forth the names by which the commenters
are referred to herein.
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In brief, the Commission, in this rule, addresses the Uniform
System of Accounts' treatment of gas in underground storage reservoirs
and in pipelines,5 revenues6 and gas supply expenses,7
eliminates all accounts for Nonmajor respondents and redesignates
accounts used only by Major respondents for use by all respondents. The
Commission also changes or eliminates various forms, reports, and
statements. This includes changes to, and deletions from, FERC Form No.
2 (Form No. 2), Annual report of Major natural gas companies, and FERC
Form No. 2-A (Form No. 2-A), Annual report of Nonmajor natural gas
companies, and FERC Form No. 11 (Form No. 11), Natural gas pipeline
company monthly statement.8
\5\The Commission amends Account 117, Account 164.1, and other
accounts that refer to Account 117.
\6\The Commission amends Account 489 and Account 495.
\7\The Commission amends Account 806, Account 813, and Account
823.
\8\Form No. 2 consists of approximately 162 non-consecutively
numbered pages and a four-page index. See 18 CFR 260.1. The current
version bears OMB approval No. 1902-0028. Form No. 2-A consists of
approximately 22 consecutively numbered pages, 1-22, and 32 non-
consecutively numbered substitute pages from the Form No. 2 that may
be used in lieu of the comparable pages in the first section. See 18
CFR 260.2. The current version bears OMB approval No. 1902-0030.
Form No. 11 consists of approximately 4 consecutively numbered
pages, 1-4. See 18 CFR 260.3. The current version bears OMB approval
No. 1902-0032.
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The Commission is making the changes in order to create forms,
reports, and statements that reflect the current regulatory environment
of unbundled pipeline sales for resale at market-based prices and open-
access transportation of natural gas. In doing that, the Commission
seeks to simplify and streamline its requirements to reduce the burden
on respondents. Hence, the Commission is eliminating reporting
requirements (as well as a few non-reporting requirements) that are
outdated or nonessential in light of current regulation, or are
duplicative of other reporting requirements. At the same time, the
revisions, especially of Form No. 2, will provide financial, rate, and
statistical information on transactions that is more useful than what
is currently available to regulatory agencies and other users of the
financial statements and reports of natural gas companies. The
Commission believes the changes to Form No. 2 are needed because the
characteristics of certain balance sheet and income statement items for
the restructured industry are different from what they were when the
current accounting regulations were adopted. In addition, the
Commission has significantly increased the thresholds for the reporting
of various information.
In Part III-A of this rule, the Commission will address the changes
to the Uniform System of Accounts with respect to storage gas. In Part
III-B the Commission will address other revisions to the Uniform System
of Accounts. In Part IV, the Commission will discuss the changes to
Part 158 of the Commission's regulations with respect to the
certification of compliance with the accounting regulations. In Part V,
the Commission will discuss the changes to Part 250 of the Commission's
regulations, ``Approved Forms, Natural Gas Act.'' In Part VI, the
Commission will discuss the changes to Part 260 of the Commission's
regulations, ``Statements and Reports (Schedules).'' That discussion
will include the changes to Forms No. 2,9 No. 2-A,10 and Form
No. 11.11 In Part VII, the Commission will discuss the changes to
Part 284 of the Commission's regulations, ``Certain Sales and
Transportation of Natural Gas Under the Natural Gas Policy Act of 1978
and Related Authorities.''
\9\Appendix B consists of the revised Form No. 2. Appendix B is
not being published in the Federal Register, but is available from
the Commission's Public Reference Room.
\10\Appendix C consists of the revised Form No. 2-A. Appendix C
is not being published in the Federal Register, but is available
from the Commission's Public Reference Room.
\11\Appendix D consists of the revised Form No. 11. Appendix D
is not being published in the Federal Register, but is available
from the Commission's Public Reference Room.
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In the NOPR, the Commission stated that the changes to these
regulations and forms and to the regulations in the companion rule
titled, ``Filing Requirements for Interstate Natural Gas Company Rate
Schedules and Tariffs,'' will necessitate modifications to the
electronic formats for the affected filings and forms. The Commission
will discuss electronic filings in Part IX below.
[[Page 53021]]
The changes to the Uniform System of Accounts and Form Nos. 2, 2-A,
and 11 in this rule will be effective January 1, 1996.12 The
remainder of the rule will be effective 30 days after publication in
the Federal Register.
\12\That is, the pipelines must comply with the revised Uniform
System of Accounts starting January 1, 1996, and they must report
1996 information on the FERC Form Nos. 2 and 2-A filed in 1997. The
Form No. 2 filed in 1996 will be the current Form No. 2 and will
report for the year 1995.
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II. Public Reporting Burden
The subject final rule establishes new reporting requirements,
modifies existing reporting requirements, and eliminates those
requirements that are now obsolete. In addition, the final rule
reflects many of the changes suggested by industry comments filed in
response to Commission's Notice of Proposed Rulemaking. This
simplification and streamlining of Commission reporting requirements
has reduced the burden on pipelines. The collective reduction in
reporting burden is estimated to be 61,824 hours annually.
The final rule will affect eight of the Commission's existing data
collections. It is expected to reduce or eliminate the current
reporting burden associated with the following six information
collections:
FERC Form No. 2 ``Annual Report of Major Natural Gas Companies''
(1902-0028) (FERC-2);
FERC Form No. 11, ``Natural Gas Pipeline Company Monthly Statement
(1902-0032) (FERC-11);
FERC-549, ``Gas Pipeline Rates: Natural Gas Policy Act Title III
Transactions'' (1902-0086) (FERC-549);
FERC-576, ``Reports on Pipeline Systems Service Interruptions''
(1902-0004) (FERC-576);
FERC Form No. 8, ``Underground Gas Storage Report'' (1902-0026)
(FERC-8); and
FERC Form No. 14, ``Annual Report for Importers and Exporters of
Natural Gas'' (1902-0027) (FERC-14)
The FERC Form Nos. 8 and 14 will be eliminated entirely as a result of
this rule. One of the affected data collections--FERC Form No. 2-A,
``Annual Report of Nonmajor Natural Gas Companies'' (1902-0030) (FERC-
2A)--will have no substantive change in its current reporting
burden.13 Only one of the data collections will have a slight
increase in burden. The burden associated with FERC-549B, ``Gas
Pipeline Rates: Capacity Release Information'' (1902-0169) (FERC-549B)
will increase as a result of the institution of the Index of Customers.
\13\No net change in the reporting burden is expected because of
offsetting increases and decreases within the data collection.
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The aggregate annual reporting burden as a result of the final rule
for all affected data collections is estimated to total 437,835 hours
based on an expected 981 filings per year. The summary table below
shows the impact/reduction on each affected data collection. The
Commission's estimates of public reporting burden for the data
collections include the time for reviewing instructions, searching
existing data sources, gathering and maintaining the data needed, and
completing and reviewing the collection of information.
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Estimated Estimated Net change in Estimated No. Estimated
Affected data collection (RM95-4- annual burden annual burden annual burden of filings/yr burden hrs per
000) hrs (rule) hrs (current) hrs (rule) filing (rule)
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FERC-2.......................... 68,310 113,850 -45,540 46 1,485.0
FERC-549........................ 14795 14,045 -13,250 1590 168.8
FERC-549 (B).................... 350,308 349,060 1,248 17546 641.6
FERC-576........................ 12 36 -24 12 1.0
FERC-11......................... 600 3,420 -2,820 200 3.0
FERC-2A......................... 2,610 2,610 0 87 30.0
FERC-818........................ 0 1,296 -1,296 0 0
FERC-1418....................... 0 142 -142 0 0
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Total..................... 422,635 484,459 -61,824 981 430.8
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\14\Comprised of 750 hours for transportation filings and 45 hours for sales filings.
\15\Comprised of 75 transportation filings and 15 sales filings.
\16\The weighted average of 10.0 hours per transportation filing and 3.0 hours per sales filing.
\17\Includes 468 Index of Customer filings.
\18\This data collection is discontinued by the subject rule.
With respect to the gas companies filing FERC Form No. 2, the
Commission believes that there will be a total reporting burden
decrease of 45,540 hours, or approximately 990 hours per respondent
each year due to the elimination of about 34 schedules and significant
increases in the thresholds for the reporting of information on other
schedules. There will be some additional information required, but
there should be a minimal burden increase as a result, because much of
the information is already collected by the industry in other contexts.
The Commission estimates that the existing public reporting burden
for the other filing requirements under the rule will also be
decreased. With respect to FERC Form No. 11, the quarterly Form No. 11
will contain monthly details of data required annually on an aggregate
basis in FERC Form No. 2. The filing of FERC Form No. 11, quarterly
rather than monthly, will reduce the number of reports from 600 to 200.
In addition, data are primarily required by rate schedule or Uniform
System of Accounts entries. These consistencies in reporting will
simplify the filing burden. The revised reporting schedule will reduce
the existing reporting burden by a total of 2820 hours, or
approximately 56 hours per respondent each year.
The elimination of initial, subsequent, termination, and annual
reports, FERC-549, for interstate pipelines, and the retention of only
the annual transportation reports for intrastate pipelines and the
annual sales reports for interstate pipelines, will reduce the
reporting burden by a total of 13,250 hours. The Commission estimates
that the annual report for the 75 remaining intrastate respondents will
require an average of 10 hours to complete. The annual sales report for
the 15 interstate respondents requires an average of 3 hours to
complete.
The Index of Customers requirement will add approximately 1,248
hours to the total burden under FERC-549B. In
[[Page 53022]]
its Notice of Proposed Rulemaking, the Commission estimated that this
requirement would add 11,700 hours to the reporting burden for FERC-
549B. However, the Commission has deleted the paper filing requirement,
and required that the index be filed electronically with the Commission
and be available through a pipeline's electronic bulletin board. It is
now estimated that the Index of Customers will take approximately 4
hours for each quarterly update for the 78 pipeline respondents.
Allowing reporting of service interruptions in FERC-576 by any
electronic means, including facsimile or telegraph, will expedite the
notice process, and reduce the burden to one hour per response from
three hours. This report is required only in the event of an
interruption to normal service lasting three hours or longer.
The elimination of the FERC Form Nos. 8 and 14 will reduce industry
reporting burden by 1,296 and 142 hours, respectively.
A copy of this rule is being provided to OMB. Interested persons
may send comments regarding these burden estimates, or any other aspect
of these collections of information, including suggestions for further
reductions of burden, to the Federal Energy Regulatory Commission,
Washington, D.C. 20426 [Attention: Michael Miller, Information Services
Division, (202) 208-1415, FAX: (202) 208-2425]. Comments on the
requirements of this final rule may also be sent to the Office of
Information and Regulatory Affairs of OMB, Washington, D.C. 20503
[Attention: Desk Officer for Federal Energy Regulatory Commission,
(202) 395-3087, FAX: (202) 395-5167].
III. Revisions to Uniform System of Accounts (Part 201)
A. Storage Accounting
1. The NOPR
In the NOPR, the Commission proposed to require that the maximum
designated gas volumes maintained for system balancing purposes,19
including those needed for no-notice transportation service, and
recoverable base gas volumes be accounted for as a fixed asset rather
than as inventory held for sale, which is the current practice.20
Collectively these volumes are referred to as ``system gas''.
\19\System balancing, as used here, refers to those situations
where the pipeline provides gas from its own source of supply in
order to meet deficiencies caused by a shipper tendering less
volumes to the pipeline at the receipt point than it takes from the
system at the delivery point. The term can also be used to refer to
situations where the shipper tenders more volumes than it takes from
the system.
\20\The Commission is not changing the accounting requirements
for initial line pack, LNG heel, and non-recoverable base gas. The
cost of this gas will continue to be recorded in the utility plant
accounts.
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Under the fixed asset model, system gas would be accounted for as a
noncurrent asset or permanent investment. In contrast, under the
inventory model, system gas would be accounted for as inventory. The
two models differ in how the pipeline's investment in gas is valued and
in how gains and losses on balancing transactions are measured and
recognized.21
\21\See the NOPR at pps. 32,999-33,001 for a full discussion of
the differences between the fixed asset and inventory models.
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To implement the fixed asset accounting model for system gas, the
NOPR proposed that Account 117, Gas Stored Underground--Noncurrent, be
replaced by new accounts Account 117.1, Gas Stored--Base Gas, Account
117.2, System Balancing Gas, Account 117.3, Gas Stored in Reservoirs
and Pipelines--Noncurrent, and Account 117.4, Gas Owed to System Gas.
2. Comments on Mandating the Fixed Asset Model
The fixed asset approach is supported in whole or in part by
Columbia, ANR, Enron, Tennessee, Texas Gas, KN, NGSA, and NI-Gas. It is
opposed by Panhandle, Transco, and AGD.
INGAA and other commenters22 maintain that the pipelines
should be able to choose either the fixed asset or inventory model.
INGAA submits that this flexibility is justified for two reasons.
First, it argues that adoption of the fixed asset model will not ensure
uniformity in accounting for storage because that model is not uniform
among non-pipeline storage owners and operators, such as independent
storage operators and local distribution companies. Second, INGAA
contends that flexibility would prevent a number of distortions which
will arise from pipelines converting from the inventory method to the
fixed asset model. Third, INGAA asserts that the change from the
inventory to the fixed asset model could increase state ad valorem
taxes and could be considered a change in accounting by the IRS,
causing it to rescind permission to use the LIFO inventory method for
income tax purposes.
\22\ANR, Kern River, Transco, Enron, Tennessee, KN, Williston,
and Consumers Power.
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3. The Treatment of System Gas
As stated above, there is support for both the fixed asset model
and the inventory model as the appropriate approach for accounting for
investments in system gas. Upon review of the comments, the Commission
concludes that valid arguments can be made in support of either
approach. Accordingly, the Commission will permit pipelines to adopt
either the fixed asset model or the inventory model to account for
system gas.23
\23\The Commission is not setting forth the arguments for and
against the models in light of the decision not to mandate a
particular model.
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Each pipeline must inform the Commission of the method it adopts
for accounting for system gaswhen it files its Form No. 2 in 1997. The
method adopted by each pipeline must be used consistently from year to
year and appropriate records must be maintained. The pipeline must
obtain Commission approval for any change in method. The Commission
will not permit a pipeline to adopt one method for determining its
rates and another method for accounting purposes. For example, if a
pipeline elects the fixed asset model for accounting purposes, it must
derive its rates via that model in its first full rate proceeding
subsequent to its accounting decision. Similarly, if a pipeline uses
the fixed asset model in developing its rates, it must use the same
method for accounting purposes.
4. The Rule
a. Investment in System Gas. To implement this rule, the Commission
is revising its accounting regulations to allow pipelines two
alternative methods of accounting for all pipeline investment in system
gas. Under those regulations, pipelines may continue to account for
their gas using a consistently applied inventory method, or pipelines
may adopt the ``fixed asset'' method. As noted above, the Commission is
not changing the accounting requirements for initial line pack, LNG
heel, and non-recoverable base gas. The cost of this gas will continue
to be recorded in the utility plant accounts. The Commission is
replacing Account 117, Gas Stored Underground-Noncurrent with four new
accounts: Account 117.1, Gas Stored--Base Gas, Account 117.2, System
Balancing Gas, Account 117.3, Gas Stored in Reservoirs and Pipelines-
Noncurrent, and Account 117.4, Gas Owed to System Gas.
Account 117.1 will include the cost of recoverable gas volumes that
are necessary to maintain pressure and deliverability requirements for
the storage facility. Nonrecoverable gas volumes used for this purpose
will continue to be recorded in Account 352.3, Nonrecoverable Natural
Gas.
[[Page 53023]]
Account 117.2 will be used to record a pipeline's investment in any
additional system gas volumes, including gas stored in pipelines above
initial line pack, designated as maximum system gas needed for load
balancing, no notice transportation, and other operational purposes.
Account 117.3 will be used to record the cost of noncurrent company-
owned stored gas not includable in Accounts 117.1 or 117.2.
Account 117.4 will primarily be used by pipelines that account for
system gas using the fixed asset model. Account 117.4 will reflect
encroachments upon system gas that result from transportation
imbalances, no-notice transportation, and other operational needs. It
may also be used to reflect encroachments on volumes recorded in
Account 117.1 for pipelines using an inventory method.
The initial investment cost to be recorded in Account 117.1 and
117.2 is to be determined from the book balances in Account 117 on the
date of adoption of the new accounts. If there is no Commission
approved method to the contrary, volumes in Account 117.1 and Account
117.2 are to be priced at their historical cost consistent with the
inventory method previously in use.24 If at the date of adoption,
a pipeline's volumes in storage are less than the maximum volume
authorized by the Commission for operational purposes, the deficient
volumes are to be priced at the then current market price25 with
an equal amount being credited to Account 117.4.
\24\The cost of any volumes of base or system gas actually in
storage that has previously been charged to expense should be
carried in the accounts at zero cost.
\25\Current market price is the delivered spot price of gas as
published in a recognized industry journal. The publication used
must be the same one identified in the pipeline's tariff for use in
its cash-out provision, if it has one. If the pipeline does not have
a cash-out provision, the pipeline must use a publication
representative of the cost of gas in its supply area, use the same
publication consistently, and identify the publication in its
records.
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b. Use of System Gas. (1) Fixed Asset Method. Under the fixed asset
method the Commission is adopting in this rule, future encroachments
upon system gas are to be credited to Account 117.4 at the then current
market price of gas with a corresponding charge to Account 808.1, Gas
Withdrawn From Storage- Debit. If the volumes are used to meet
transportation imbalances, Account 806, Exchange Gas, will be credited
and Account 174, Miscellaneous Current and Accrued Assets, will be
debited for the same amount and simultaneously with the entries to
system gas.
Pipelines will be required to maintain records supporting Account
117.4 of monthly encroachment volumes and unit prices unless the
pipeline revalues its total encroachment balance monthly. If a pipeline
revalues the balance in Account 117.4, it should charge or credit a
separate subaccount of Account 813, Other Gas Supply Expenses, with the
amount of the revaluation. To the extent that there are corresponding
changes in the value of imbalance receivables or payables, the pipeline
should make an appropriate adjustment to Account 174, Miscellaneous
Current and Accrued Assets or Account 242, Miscellaneous Current and
Accrued Liabilities, with contra-entries to Account 813.
If a customer responsible for an owed-to-system gas balance meets
his responsibility for repayment by delivering gas in-kind, the
recorded balance for such customer in Account 174 will be reversed and
Account 806 will be debited. The amount recorded in Account 117.4 for
such volumes must be cleared and Account 808.2, Gas Delivered to
Storage--Credit, credited.
If the customer responsible for an owed-to-system gas balance meets
his responsibility through a cash-out provision, similar accounting
will be followed. To recognize settlement of the receivable, the
pipeline will reverse the recorded amount in Account 174. Any
difference between the cash-out settlement amount and the recorded
receivable will be recognized as a gain in Account 495 or a loss in
Account 813, as appropriate.
When the pipeline replaces the gas, any difference between the cost
of the gas and the amount cleared from Account 117.4 will result in a
gain or loss. The pipeline should record the gain or loss in Account
495, Other Gas Revenues, or Account 813 as appropriate with contra
entries to Account 808.2.
In instances in which a pipeline's tariff requires that gains and
losses on system balancing transactions are to be passed along to
customers, pipelines should record the gains or losses directly in
Account 254, Other Regulatory Liabilities, or Account 182.3, Other
Regulatory Assets, as appropriate.
(2) Inventory Method. Under the inventory method, withdrawals of
system gas are to be credited to Account 117.2, at the inventory cost
of gas\26\ with a corresponding charge to Account 808.1, Gas Withdrawn
From Storage-Debit. If the volumes are used to meet transportation
imbalances, Account 806, Exchange Gas, will be credited and Account
174, Miscellaneous Current and Accrued Assets, will be debited for the
same amount and simultaneously with the entries to system gas.
\26\Withdrawals of gas may be priced according to the first-in-
first-out, last-in-first-out, or weighted average cost method, in
connection with which ``the fixed asset method'' may be employed
provided the method adopted by the utility is used consistently from
year to year and the inventory records are maintained in accordance
therewith.
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The pipeline must also account for withdrawals of gas from Account
117.1 under the inventory method. However, if encroachments upon
Account 117.1 volumes are to be replaced within 12 months, the pipeline
may, at its option, account for such withdrawals in accordance with the
requirements for encroachments of system gas under the fixed asset
method. The method chosen should be applied consistently from year to
year and not changed without express approval of the Commission.
5. Fixed Asset Accounting Implementation Issues
A number of commenters requested clarification of certain aspects
of the proposed fixed asset model and noted various implementation
difficulties with the Commission's approach. The following discussion
is the Commission's response to the concerns expressed by commenters.
As stated above, the Commission is replacing Account 117, Gas
Stored Underground-Noncurrent, with four new accounts: Account 117.1,
Gas Stored-Base Gas and Account 117.2, System Balancing Gas, 117.3, Gas
Stored in Reservoirs and Pipelines--Noncurrent, and 117.4, Gas Owed to
System Gas. The Comments address those accounts.
a. Accounts 117.1 and 117.2. Williston asks for clarification that
gas previously capitalized in Account 101 [utility plant] is not to be
reclassified as Account 117.1 gas. The Commission clarifies that the
cost of gas volumes properly includable in Account 101 is not to be
reclassified to Account 117.1. The rule is making no change to the
requirements of the existing Uniform System of Accounts that the cost
of non-recoverable gas in underground reservoirs used for the storage
of gas, and the first cost of gas introduced into the utility's system
necessary to bring the pipeline system up to its designed operating
capacity or increases therein, are to be included in the plant
accounts.
Enron maintains that Accounts 117.1 and 117.2 should be combined
into a single account titled ``System Gas,'' because there is no clear
line between volumes serving a pressure maintenance function and
volumes used for system balancing.
[[Page 53024]]
The Commission will not adopt Enron's suggestion. The Commission
recognizes that a bright line separating the volumes necessary for
maintaining storage pressure and deliverability requirements from those
necessary for efficient transmission operation (i.e. system balancing
gas) does not exist for most if not all storage facilities. However,
base gas volumes in storage reservoirs are used to maintain pressure
and deliverability requirements for both customer storage and pipeline
storage of system gas. Because storage rates are often separate from
transmission only rates, it is necessary to separately identify the
cost of base gas so that proper allocations of base storage costs can
be made between storage and transmission services. Commingling base
storage with system balancing gas would make cost and rate
determinations more difficult.
CNG urges the Commission to delete the requirement to report line
pack in Account 117.2 because CNG includes line pack in plant accounts
or has expensed it already and its line pack fluctuations are
immaterial from month to month.
The final rule does not require the cost of line pack gas
previously charged to expense to be included in Account 117.2. However,
pipelines must account for volumes stored in the pipeline above line
pack volumes consistent with the rule. That is, the cost of such
additional volumes must be recorded in Account 117.2 or 117.3, as
appropriate. If the pipeline has previously charged the cost of any
such additional volumes on its system to expense such volumes must be
included in the accounts at zero cost.
NGSA would create a number of new accounts to deal with system gas.
NGSA states that although both Accounts 117 and 164.1, Gas Stored
Underground--Current, should be maintained as fixed assets, Account 164
also should be used for system balancing transactions because it is
NGSA's belief that working gas, not base gas, is cycled. It would amend
the accounts instructions to require pipelines to record both volumes
and dollars and would establish specific subaccounts in Account 164,
rather than Account 117, to match the pipeline's accounting of
imbalances by service type and rate schedule (e.g., no-notice,
exchange, gathering, FT and IT). Gas Owed to System Gas would be
reflected in Account 174.4 and a separate asset account would be
established for line pack.
The Commission will not adopt NGSA's proposal because the
Commission believes it is unnecessary to establish a separate account
for line pack or to prescribe numerous subaccounts of storage gas by
service type and rate schedule. The proposed new Accounts 117.1 through
117.4 should be adequate for accounting for all system gas. In this
regard, the Commission will modify instruction A of the proposed
Account 117.3 to include the cost of all stored gas in excess of
system, whether or not it is available for sale. Although the
Commission declines to require specific subaccounts for system gas,
pipelines may establish whatever subaccounts they deem necessary to
facilitate the needs of their individual pipelines.
Panhandle interprets the NOPR's proposal to price volumes
includible in Account 117.2 ``at the inventory price that would be
applicable to the last volumes that would be withdrawn from storage
before encroachment upon base gas'' (NOPR at p. 33,002), as requiring
restatement of all system gas that had previously been accounted for
using a LIFO or FIFO inventory method. Panhandle maintains this is
improper.
Panhandle's interpretation is incorrect. The proposed rule was not
intended to require or permit pipelines to restate the carrying value
of system gas in storage upon implementation of the new accounting. The
proposed rule clearly states that the initial investment cost to be
recorded in Accounts 117.1 and 117.2 is to be determined from the book
balances on the date of adoption of the new accounts. The statement
cited by Panhandle was intended to address potential situations where
the initial volumes of gas in storage exceeded the volumes designated
as system gas. In these situations, the cost to be assigned to Account
117.2 should be determined based on historical inventory price layers
starting with the pricing layer applicable to the last volumes that
would be withdrawn from storage before encroachment upon base gas and
continuing until all of the volumes of system gas have been priced.
b. Account 117.4. (1) Nature of the Account. The Commission
proposed Account 117.4 as an account that would reflect the obligation
to replace volumes that encroached on system supply.
Panhandle contends that the Commission has not explained whether
Account 117.4 is designed as a liability or a valuation account and
that, in any event, the proposed approach is not in accordance with
Generally Accepted Accounting Principles (GAAP). It asserts that there
is no liability on the pipeline's part to restore system gas. It then
argues that, like a valuation account, Account 117.4 reduces the
carrying value of the system gas asset, but it ``reduces system gas to
a value that is neither cost-based nor market-based, but a varying
hybrid which does not qualify as an asset account.''\27\
\27\Comments at 16.
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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.
---------------------------------------------------------------------------
4. Entries--Revenue Recognition
Pipelines electing to recognize shipper provided gas as revenue
must also recognize an equal amount of purchased gas expense. Pipelines
would credit the appropriate transportation revenue account (Accounts
489.1 through 489.4)\41\ and record an equal amount in Account 805,
Other Gas Purchases.
\41\New revenue accounts 489.1, Revenues from Transportation of
Gas of Others Through Gathering Facilities, 489.2, Revenues from
Transportation of Gas of Others Through Transmission Facilities,
489.3, Transportation of Gas of Others Through Distribution
Facilities, and 489.4, Revenues from Storing Gas of Others.
---------------------------------------------------------------------------
5. Entries--Non Revenue Recognition
Although the Commission is not requiring revenue recognition for
the volumes received from shippers, pipelines must recognize all gas
consumed in compressor stations or used for other operational purposes
in the appropriate expense accounts in accordance with existing Uniform
System of Accounts requirements.\42\ Contra-credits for these amounts
are to be recorded in Account 810, Gas Used for Compressor Station
Fuel--Credit, Account 811, Gas Used for Products Extraction--Credit,
and Account 812, Gas Used for Other Utility Operations--Credit, as
appropriate. This will result in comparability of transmission
operating expenses among pipelines and will avoid the statistical
anomalies that exist under current practices.\43\ Further, the value of
gas received from shippers under tariff allowances that is not consumed
in operations nor returnable to customers through rate tracking
mechanisms shall be credited to Account 495, Other Gas Revenues and
charged to Account 805. Pipelines must simultaneously charge Accounts
117.3 or 117.4 as appropriate, with contra credits to Account 808.2,
Gas Delivered to Storage--Credit.
\42\For example, the cost of gas used for transmission
compressor stations is to be recorded in Account 854, Gas for
Compressor Station Fuel, and gas used for underground storage
compressor stations is to be recorded in Account 819, Compressor
Station Fuel and Power.
\43\For example, in 1994 Panhandle and Columbia moved 1.2
billion mcf and 1.3 billion mcf of gas respectively on their
systems. While the volumes moved were approximately the same, the
two pipelines reported widely disparate amounts for the cost of gas
used in transmission compressor stations--$2.7 million for Panhandle
and $28.7 million for Columbia. While the two pipeline systems are
obviously different and therefore fuel usage can not be expected to
necessarily correlate precisely with throughput, the figures
adequately demonstrate the statistical anomalies and lack of
comparability that results from different accounting and reporting
practices.
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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.
---------------------------------------------------------------------------
In the new Revenues from Transportation of Gas of Others Through
Gathering Facilities Schedule, the pipeline will have to report its
revenues by zone of receipt and by rate schedule.64 The pipeline
would have to report for both the current and previous year its
revenues for transition costs and take-or-pay costs, revenues for GRI
and ACA, other revenues,65 and total operating revenues, and its
Dth of gas delivered.66 The Commission believes that this schedule
will provide the information needed with respect to gathering to obtain
a good description of the pipeline's activities in the unbundled
environment.
\64\If a pipeline has no rate schedule, it should report by
rate.
\65\Other revenues include reservation charges received by the
pipelines plus usage charges, less revenues reflected in columns (b)
through (e).
\66\As suggested by INGAA, the Commission has eliminated
duplicative column (a).
---------------------------------------------------------------------------
The Commission has deviated from the NOPR by requiring reporting by
zone of receipt and by rate schedule rather than by state of delivery,
by customer, by rate as in the NOPR's proposed gathering schedules. The
Commission believes that reporting by zone of receipt and by rate
schedule will provide the appropriate information needed for regulatory
purposes without undue burden on the pipeline industry. The Commission
does not believe that such customer information is necessary outside of
the context of a rate proceeding. The Commission believes that it has
thus addressed INGAA's concernabout providing customer data and its
concern that pipelines may not know the exact delivery point from a
multi-point contract, and will have to make an arbitrary allocation to
a state.
The Commission will discuss further here only those comments
specific to gathering. Comments applicable to gathering and also to
other services will be addressed below in the discussion of the
transportation schedule.
Columbia maintains that gathering revenues should be reported by
state of receipt into the system. As stated above, the Commission is
requiring reporting by zone of receipt into the pipeline's system.
Revenues from Transportation of Gas of Others Through Transmission
Facilities (Account 489.2)--Pages 304 and 305
In the new Revenues from Transportation of Gas of Others Through
Transmission Facilities and Dth Transported Schedule, the pipeline
would have to report its revenues by zone of delivery and by rate
schedule. The pipeline would have to report for both the current and
previous year its revenues for transition costs, and take-or-pay costs,
revenues for GRI and ACA, other revenues,67 and total operating
revenues, and its Dth of gas delivered. The Commission believes that
this reporting reflects the current unbundled environment's emphasis on
transportation for others.
\67\Other revenues include reservation charges received by the
pipeline plus usage charges, less revenues reflected in columns (b)
through (e).
---------------------------------------------------------------------------
The Commission has deviated from the NOPR by requiring reporting by
zone of delivery and by rate schedule rather than by state of delivery
by customer and by rate schedule as in the NOPR's proposed
transportation schedules. The Commission believes that reporting by
zone of delivery and by rate schedule will provide the appropriate
information needed for regulatory purposes without undue burden on the
pipeline industry. The Commission does not believe that such customer
information is necessary outside of the context of a rate proceeding.
The Commission believes that it has thus addressed INGAA's concern
about providing customer data, including its concern about the
difficulty of complying with the NOPR's customer-data requirement for
some pipelines. The Commission also observes, as did INGAA, that Form
EIA-176 collects state information which, in any event, is not of use
to the
[[Page 53041]]
Commission. The Commission further observes that both the NGSA and AGD
support reporting by zones.68
\68\As suggested by Transco, the Commission has deleted the
requirement that revenues be reported in millions.
---------------------------------------------------------------------------
INGAA also submits that transportation quantities appear to require
gathering quantities to be included in transportation totals and since
gathering system quantities will already be included in transmission
deliveries, gathering should not be added to other quantities. CNG also
maintains that gathering is included in transportation. As clarified
with respect to pages 300 and 301, these quantities are not totalled to
avoid double counting.
The Commission has not expanded the coverage of the schedules as
proposed by some commenters. NGSA maintains that reporting should be by
customer type, with MDQ levels, demand and commodity volumes, discount
information, and base and surcharge revenues. AGD submits that revenues
and volumes reporting should be reported by rate schedule by zone of
delivery (not state), and should include with short-term firm
transportation. APGA enthusiastically supports pages 312 and 313,
especially transportation throughput as solely needed. It would add
details on contracts of less than one year as well as contracts of one
year and longer (revenues and volumes).
DOE maintains that the Commission should require the pipelines to
provide a menu of service categories;69 an additional field to
denote type of customer, along with standardized customer numbers;
mileage information; and totals by state and by type of service.
\69\E.g., short-term firm transportation and released firm
transportation.
---------------------------------------------------------------------------
The Commission believes the above suggestions would be unduly
burdensome in light of the limited use of the information for
regulatory purposes.
Revenues from Storing of Gas of Others (Account 489.4)--Pages 306 and
307
In the new Revenues from Storing of Gas of Others schedule, the
pipeline would have to report its revenues and Dth of gas withdrawn
from storage by rate schedule. The pipeline would have to report for
both the current and previous year its revenues from transition costs
and take-or-pay costs, revenues from GRI and ACA, other
revenues,70 and total operating revenues, and the Dth withdrawn
from storage.
\70\Other revenues include reservation charges deliverability
charges, injection and withdrawal charges, less revenues reflected
in columns (b) through (e).
---------------------------------------------------------------------------
The Commission believes that this schedule will provide the
information needed with respect to unbundled storage to obtain a good
description of the pipeline's activities in the unbundled environment.
The Commission has deviated from the NOPR by requiring reporting by
rate schedule rather than by rate schedule by customer as on the NOPR's
proposed schedules. The Commission believes that reporting by rate
schedule will provide the appropriate information needed for regulatory
purposes without undue burden. INGAA contends that storage revenues are
not tied to withdrawals and Columbia asks why storage injections as
well as storage withdrawals are not included. The Commission is not
tying the reporting of storage revenues by withdrawals. Rather, all
revenues received for storage during the reporting year must be
reported. The Commission has required Dth reporting by withdrawals
because withdrawal completes the storage cycle and such information
should be adequate for regulatory purposes. The Commission rejects
Columbia's contention that small customers (less than 1 million Dth)
should be combinedbecause this would limit the reporting of meaningful
information.
Residential and Commercial Space Heating Customers and Interruptible,
Off-Peak, and Firm Sales to Distribution System Industrial Customers--
Page 305
The Commission is deleting this page because it is not needed for
Commission regulatory purposes.
INGAA supports deleting this page. But the APGA would retain it
because it has vestigial value about changes in a pipeline's business.
The Commission does not believe that vestigial value supports the
burden of reporting this information.
Other Gas Revenues (Account 495)--Page 308
The Commission is adopting new schedule ``Other Gas Revenues
(Account 495)'' for the reporting of a variety of other gas revenues,
such as revenues from dehydration and gains on settlements of
imbalances. The Commission is not requiring the reporting of revenues
from associated companies as proposed in the NOPR. The Commission is
requiring the reporting of penalty revenues on the schedule and is
requiring the separate reporting of revenues from cash-out penalties.
The Commission has adopted a threshold of $250,000 for each
transaction. This is lieu of the $1,000,000 threshold suggested by
Columbia, which will exclude meaningful data. As suggested by INGAA and
by Columbia, the pipelines need not report the customer names with
respect to the transactions.
NGSA maintains that base and surcharge revenues should be
separately stated. The Commission sees no need for base and surcharge
revenues for these transactions to be separately reported, and so will
not adopt NGSA's suggestion.
Sales of Natural Gas--Pages 306 Through 309
The Commission is deleting this schedule, entitled ``Field and Main
Line Industrial Sales of Natural Gas,'' and is not adopting the sales
of natural gas schedule proposed in the NOPR.
The Commission is so acting because the proposed schedule would
have released proprietary information (customer names as maintained by
INGAA).
Sales for Resale--Natural Gas (Account 483)--Pages 310 and 311
The Commission is deleting this schedule because the level of
detail reported is not needed for Commission regulatory purposes.
INGAA supports the deletion of these pages.
Sales of Products Extracted From Natural Gas (Account 490)--Page 315
The Commission is deleting this schedule because the level of
detail reported is not needed for Commission regulatory purposes.
Revenues From Natural Gas Processed by Others (Account 491)--Page 315
The Commission is deleting this page, as suggested by INGAA,
because the level of detail reported is not needed for Commission
regulatory purposes.
Gas Operations and Maintenance Expenses--Pages 317-325
No changes were proposed to this schedule. However, the Commission
is adding instruction 2 that requires respondents provide in footnotes
the source of the index used to determine the price of gas supplied by
shippers as reflected on line 75 on page 319. In addition, the
Commission is inserting on line 66 the heading ``D--Other Gas Supply
Expense.'' Further, consistent with our discussion of the revision of
page 322 of Form No. 2-A, the Commission will revise line 145 to read
``Total Maintenance (Total of lines 136 through 144)''.
Last, the Commission, as suggested by Panhandle, is deleting the
section
[[Page 53042]]
entitled ``Number of Gas Department Employees'', because it is
irrelevant to the reporting of the distribution of salaries and wages.
Exploration and Development Expenses (Accounts 795, 796, 798) (Except
Abandoned Leases, Account 797)--Page 326
The Commission is deleting this schedule because it is not needed
for Commission regulatory purposes.
INGAA supports deletion of this schedule.
Abandoned Leases (Account 797)--Page 326
The Commission is deleting this schedule because it is not needed
for Commission regulatory purposes.
INGAA supports deletion of this schedule.
Gas Purchases (Accounts 800, 800.1, 803, 804, 804.1 805, 805.1)--Page
327
The Commission is deleting this schedule and is not adopting the
NOPR's proposed Gas Receipts schedule. Those schedules are not needed
for Commission regulatory purposes and needed information is reported
elsewhere in Form No. 2 (pages 317 and 520 and 521).
Exchange and Imbalance Transactions--Page 328
The Commission is revising this schedule differently from the
revision proposed in the NOPR. This schedule (on one page only) will
require details concerning gas quantities and related dollar amounts of
net annual imbalances by zone and rate schedule.
Unlike the NOPR proposal, the Commission is not requiring reporting
by customer or transaction or by point of receipt or delivery. This
will ease the burden on the pipelines and the schedule will still
garner useful data. However, the Commission is retaining the threshold
of 100,000 Dth for the grouping of minor transactions, rather than
increasing the threshold to 1,000,000 Dth as proposed by INGAA, because
the 100,000 Dth level provides more meaningful information.
Gas Used In Utility Operations--Page 331
The Commission is striking ``Credit (Accounts 810, 811, 812)'' from
the title, is replacing Mcf with Dth, and deleting part of Instruction
1 and all of instructions 2, 3 and 5 concerning the definition of
natural gas and Mcf reporting.
INGAA supports the above-described revisions.
Transmission and Compression of Gas By Others (Account 858)--Pages 332
and 333
The Commission is replacing Mcf with Dth, deleting current columns
(b)-(f), and requiring the reporting of Dth of gas delivered in new
column (b). This will eliminate the reporting of the distance gas is
transported and revenue information. The continuation page 333 is
deleted.
INGAA supports the above-describe revisions.
Other Gas Supply Expenses (Account 813)--Page 334
The Commission is requiring that respondents report maintenance
expenses, the revaluation of monthly encroachments recorded in Accounts
117.4, losses on settlements of imbalances and gas losses not
associated with storage, separately. In addition, individual items of
$250,000 or more are to be listed separately. The NOPR proposed a
threshold of $25,000, but, as INGAA maintains, this would lead to the
unnecessary reporting of detail.
Miscellaneous General Expenses (Account 930.2) (Gas)--Page 335
The Commission is dividing Line No. 2 (Experimental and general
research expenses) into (a) Gas Research Institute (GRI) expenses and
(b) other expenses. In addition, the Commission is raising the
thresholds from $5,000 to $250,000, rather than the $25,000 threshold
proposed by the NOPR.
INGAA supports the above-described changes, but would delete the
requirement that the number of items grouped be shown because this
instruction adds no value to the report.
The Commission disagrees with the comment that reporting the number
of items grouped adds no value to the report. This number puts the
grouped item into perspective and facilitates analysis. Therefore, the
instruction to report the number of items grouped will remain as part
of line 4.
Depreciation, Depletion, and Amortization of Gas Plant (Accounts 403,
404.1, 404.2, 404.3, 405) (Except Amortization of Acquisition
Adjustment)--Pages 336 and 337
The Commission is deleting instruction 2 to report information
called for in Section B every fifth year after 1974 and is inserting
the words `` and amortizable'' in the first line of new instruction 2
after the word ``depreciable.''
INGAA supports the above-described revisions. It states that
instruction No. 2 should be corrected by inserting ``Section B.'' The
Commission has made that correction.
Depreciation, Depletion, and Amortization of Gas Plant (Continued)--
Page 338
The Commission is revising the headings to column (b) to read
``Plant Base (thousands)'' and column (c) to read ``Applied
Depreciation or Amortization Rates (Percent).''
INGAA supports this revision.
Income From Utility Plant Leased to Others (Account 412 and 413)--Page
339
The Commission is deleting this schedule because the information
will be reported on page 213.
INGAA supports the deletion of this schedule.
Particulars Concerning Certain Income Reductions and Interest Charges
Accounts--Page 340
The Commission is raising the threshold for the grouping of items
from $10,000 to $250,000, as opposed to the $25,000 threshold proposed
by the NOPR.
Regulatory Commission Expenses (Account 428)--Pages 350 and 351
The Commission is changing the account number reference in the
headings to columns (e), (i) and (l) from 186 to 182.3, and replacing
instruction 4 on page 351, which references Account No. 186, with ``4.
Identify separately all annual charge adjustments (ACA).'' In addition,
the Commission is raising the threshold for minor items from $25,000 to
$250,000, as opposed to the $50,000 threshold proposed by the NOPR.
Columbia would delete columns (e) through (l) because they contain
redundant information that offer little benefit or useful information.
The Commission disagrees with Columbia. The information reported in
these columns enables the Commission staff to obtain a more complete
picture of the amounts and types of regulatory expenses that have been
incurred during the year, as well as information on the amounts
amortized from prior years.
Research, Development, and Demonstration Activities--Pages 352 and 353
The Commission is deleting this schedule because it is not needed
for Commission regulatory purposes.
INGAA supports the deletion of this schedule.
[[Page 53043]]
Distribution of Salaries and Wages--Page 354
The Commission proposed no change to this schedule.
INGAA and Columbia maintain that his schedule should be deleted
because the information reported is required only for NGA section (4)
rate filings.
The Commission is retaining this schedule because it provides
useful information for regulatory purposes, including use in evaluating
rate filings under NGA section 4(e).
Charges for Outside Professional and Consultative Services--Page 357
The Commission is raising the threshold from $25,000 to $250,000,
as suggested by INGAA and Panhandle, as opposed to the $50,000
threshold proposed by the NOPR, is deleting the requirement for the
consultant's address, and is deleting other details about charges and
contracts. The Commission is also adding columns (a) ``Description''
and (b) ``Amount (in dollars).''
INGAA would require only the consultant's name and related payment.
Columbia would eliminate much of the information as it is in an NGA
section 4(e) filing. The Commission believes it relevant for regulatory
purposes to obtain the required information. If a respondent does not
make such a filing, the Commission would not have this information.
The APGA would retain the $25,000 threshold. The Commission
believes the current threshold is too low in today's environment.
Natural Gas Reserves and Land Acreage--Pages 500 and 501
The Commission is deleting this schedule because it is not needed
for Commission regulatory purposes.
INGAA supports the deletion of this schedule.
Changes in Estimated Gas Reserves--Page 503
The Commission is deleting this schedule because it is not needed
for Commission regulatory purposes.
INGAA supports the deletion of this schedule.
Changes in Estimated Hydrocarbon Reserves and Costs, and Net Realizable
Value--Pages 504 and 505
The Commission is deleting this schedule because it is not needed
for Commission regulatory purposes.
INGAA supports the deletion of this schedule.
Natural Gas Production and Gathering Statistics--Page 506
The Commission is deleting this schedule because it is not needed
for Commission regulatory purposes.
INGAA supports the deletion of this schedule.
Products Extraction Operations--Natural Gas--Page 507
The Commission is deleting this schedule because, as INGAA
observes, this information is similar to deleted pages 500-506.
Compressor Stations--Pages 508 and 509
The Commission is replacing the reporting of number of employees in
column (b) with a report of the number of compressor stations and the
horsepower of each station and is redesignating the remaining columns.
In addition, gas for compressor fuel would be reported by Dth rather
than by Mcf. The Commission agrees with INGAA that reporting will be
less burdensome and data will be more useful if pipelines report
horsepower by compressor station, rather than by unit as proposed by
the NOPR.
AGD would require reporting certificated horsepower and available
horsepower at the end of the period, if different.
The Commission has not previously required the reporting of
available horsepower in Form No. 2. If a pipeline cannot operate at its
certificated horsepower, it should file to amend its certificated
horsepower to whatever level it has currently available.
Gas and Oil Wells--Page 510
The Commission is deleting this schedule because it is not needed
for Commission regulatory purposes.
INGAA supports the deletion of this schedule.
Field and Storage Lines--Page 511
The Commission is deleting this schedule because it is not needed
for Commission regulatory purposes.
INGAA supports the deletion of this schedule.
Gas Storage Projects--Pages 512 and 513
The Commission is not deleting page 512 or substantially revising
page 513 as proposed in the NOPR because the Commission is deleting
Form No. 8 with respect to storage. The Commission is retaining the
information required by this schedule about storage operations for gas
delivered to storage, gas withdrawn from storage with regard to
respondent's gas, and gas belonging to others, as well as information
about particular operations (page 513).
INGAA supports the above-described revisions. AGD would require
reporting by field, not in the aggregate, with a showing of actual
withdrawal capacity when full and when top gas is depleted (first and
last day of deliveries) and corresponding injection capability at the
same points. The Commission believes that by retaining this schedule in
most part, the industry will be provided with adequate information. The
reporting requirement on this page has always been in the aggregate and
not by field or by account and is not a new requirement. AGD's
suggestions would require the company to report in such detail that it
would be extremely labor-intensive. Therefore, the Commission will not
adopt the suggestion.
Transmission Lines--Page 514
DOE suggests standardizing the method for describing or identifying
the various transmission lines so that shippers will be able to
reconcile information from various sources to arrange more efficiently
for transportation service. DOE also suggests that each line should
agree with the Form No. 567 map information.
The Commission concludes that DOE's proposals would be unduly
burdensome for Form No. 2 reporting in that they serve no regulatory
purpose.
Liquefied Petroleum Gas Operations--Pages 516 and 517
The Commission is deleting this schedule because it is not needed
for Commission regulatory purposes.
INGAA supports the deletion of this schedule.
Transmission System Peak Deliveries--Page 518
The Commission is replacing Mcf with Dth and is requiring the
reporting of deliveries of gas to interstate pipelines, deliveries to
others, and of total deliveries. The Commission also is deleting the
information with respect to the second and third highest peak day
deliveries and the section, Highest Month's System Deliveries. Single
peak day and consecutive three-day peak deliveries will be reported by
various services and activities. The differentiation between
jurisdictional and non-jurisdictional deliveries will be eliminated as
no longer pertinent with unbundling. The Commission is adding lines
with respect to no-notice transportation and storage services.
INGAA maintains that this amount of detail on peak day deliveries
proposed by the NOPR is not justified. It submits that pipelines should
report only single
[[Page 53044]]
peak and consecutive 3-day peak for total system deliveries. The
Commission has reduced the reporting to firm, interruptible, and other
to reduce the burden and retain adequate information for regulatory
purposes.
DOE proposes that short-term firm transportation and released firm
transportation be reported because they merit monitoring as important
alternatives to interruptible service.
The Commission does not currently require this information to be
reported in Form No. 2, and to do so would unduly increase the
reporting burden on pipelines. In addition, the deliveries on peak days
may not be representative of released and short-term transportation
service on a pipeline.
Auxiliary Peaking Facilities--Page 519
The Commission is replacing Mcf with Dth.
INGAA supports this revision.
Gas Account-Natural Gas--Page 520
The Commission is revising this schedule differently from the
schedule proposed in the NOPR. The salient changes are the reporting of
gas purchases and gas sales on single lines and the reporting of gas
received and delivered according to the revisions to the Uniform System
of Accounts adopted in this rule (e.g., Accounts 489.1-489.4). The
revised schedule no longer requires the reporting of the information
required by NOPR lines 7-13, as suggested by INGAA and Columbia.
The Commission also is revising instruction 1 to exclude the
reference to consideration of pressure bases in measuring Mcf of
natural gas and is replacing Mcf with Dth in instruction 3 and column
(c) on pages 520 and 521.
INGAA recommends the inclusion of definitions for exchange gas
received and delivered, and clarification that gathering sales and
purchased volumes are not to be added to the totals. Columbia seeks
clarification of the relationship between imbalances and other to pages
328 and 329.
Exchange gas received or delivered should be reported in light of
the Exchange Gas Transactions schedule, page 328. Gathering sales and
purchased volumes should be added to totals because this is a balance
sheet item for the year of activity and those volumes are needed to
balance the gas account. Last, the lines for imbalances and other have
been deleted.
System Maps--Page 522
The Commission is clarifying the information to be shown on the
maps and is eliminating the requirement that transmission lines be
colored in red, if they are not otherwise clearly indicated.
INGAA supports the above-described clarification and elimination.
Panhandle would incorporate the System Flow Map from Form 567 into page
522 and eliminate Form 567 because the system flow Map provides a more
detailed map. Columbia asks for clarification about incremental
facilities.
The Commission rejects Panhandle's request to substitute the System
Flow Map because the Form No. 2 map provides useful information, such
as geographical information, that is not shown on the System Flow Map.
The Commission clarifies that only major incremental facilities should
be shown on this map.
Index--Pages 1-4
The Commission is revising the index to reflect the above changes.
B. Revisions to Form No. 2-A
At present, a Nonmajor natural gas company must submit Form No. 2-
A. The respondent is required to submit designated pages reflecting
data designed for Nonmajor natural gas companies in the Uniform Systems
of Account. However, if the respondent maintains the ``Major''
designated accounts, it may substitute certain pages from Form No. 2.
The Commission is requiring Nonmajor respondents to submit only Form
No. 2 pages as their Form No. 2-A report. In addition, the Commission
is replacing Mcf with Dth and revising the instructions, including CPA
certification as discussed above for Form No. 2. A sample copy of the
revised Form No. 2-A is attached as Appendix C.
The revised Form No. 2-A will consist of instructions,
identification, attestation, and list of schedules (pages i and ii and
1 and 2), the following pages from Form No. 2: 107, 110-122, 204-209,
212, 213, 219, 300, 301, 317-325, 520, 551, and the following pages
from current Form No. 2-A as renumbered: 26 as 211, 16 as 232, 19 as
250, and 20 as 278.
In addition, the Commission is revising the definition of Nonmajor
as follows: ``Nonmajor means having annual gas sales or volume
transactions exceeding 200,000 Dth in each of the three previous
calendar years and not classified as `Major'.'' This comports with the
changes to section 260.2 of the Commission's regulations to include the
minimum filing threshold for filing Form No. 2-A and to state the
minimum filing threshold on a dekatherm basis.
INGAA supports the Commission's proposal to adopt, for Form No. 2-A
reporting purposes, the use of Form No. 2 pages as proposed in the NOPR
and the renumbering of Form No. 2-A pages. Freeport also agrees with
the proposed change to 18 C.F.R. section 260.2 on who must file Form
No. 2-A.
INGAA submitted specific comments on the proposed Form No. 2-A
pages. INGAA's comments for the proposed Form No. 2-A pages 110-111,
112-113, 114, 115-116, 120-121, 122-123, 212, 213, 300-301, 327 and
520-521 are identical to the comments it submitted for the proposed
changes to the same Form No. 2 pages; therefore, there is no reason to
repeat them here. For the reasons discussed in the changes to Form No.
2, the Commission will adopt, for those Form No. 2-A pages, the same
changes that the Commission adopted in this final rule for Form No. 2.
INGAA suggested the following revisions to the following proposed
Form No. 2-A pages:
Statement of Retained Earnings for the Year--Pages 118-119
INGAA agrees with the proposal to require reporting of current year
and previous year data and to delete instruction 8. It suggests that,
on NOPR page 118-a, line 38 (now 36) be corrected to read ``Balance--
End of year (Enter total of lines 1, 9, 15, 16, 22, 29, 36 and 37)''.
The Commission agrees with INGAA's suggested change and will adopt
it as modified, for line 36 page 118 of the Form No. 2-A.
Gas Plant in Service--Pages 204-209
No changes were proposed to these pages. INGAA suggests that the
pages be revised to indicate which lines are used for totals and that
lines 114, 115 and 116 on page 209-a should be on page 209.
The Commission agrees with INGAA's suggested change to indicate
which lines are used for totals and will adopt the following
modifications: (1) Line 5 will read ``TOTAL Intangible Plant''; (2)
line 26 will read ``TOTAL Production and Gathering Plant''; (3) line 36
will read ``TOTAL Products Extraction Plant''; (4) line 37 will read
``TOTAL Natural Gas Production Plant''; (5) line 39 will read ``TOTAL
Production Plant''; line 54 will read ``TOTAL Underground Storage
Plant''; (6) line 65 will read ``TOTAL Other Storage Plant''; (7) line
75 will read ``TOTAL Base Load Liquefied Natural Gas, Terminating and
Processing Plant''; (8) line 76 will read ``TOTAL Natural Gas Storage
and Processing Plant''; (9) line 86 will read ``TOTAL Transmission
Plant''; (10) line 102 will read ``TOTAL Distribution Plant''; (11)
line 114 will read ``Subtotal''; (12) line 116 will read
[[Page 53045]]
``TOTAL General Plant''; (13) line 117 will read ``Total (Accounts 101
and 106)''; (14) line 121 will read ``TOTAL Gas Plant in Service,'' and
(15) various existing lines will be renumbered.
With regard to INGAA's suggestion that lines 114-116 be moved to
page 209, this problem will be solved when the Form No. 2-A is type-set
for printing; accordingly these lines will actually appear on page 209
when the Form No. 2-A is printed for distribution.
Gas Operation and Maintenance Expenses--Pages 320-325
No changes were proposed to these pages. INGAA suggests that the
page 322 be revised to correct line 145 to read ``Total Maintenance
(Enter Total of lines 136 through 144).''
The Commission agrees with INGAA's suggested change and will adopt
it except for the Word ``Enter.''
In addition, the Commission has revised the instructions to the
following pages.
General Information on Plant and Operations--Page 211
The Commission has deleted instruction 3 which required the
reporting of information related to the local distribution of natural
or mixed gas at the retail level.
Capital Stock Data--Page 250
The Commission has added a descriptive instruction and revised
stylistically the existing instruction for this page.
C. Revisions to Form No. 11
Natural gas pipelines are required to file with the Commission the
FERC Form No. 11, which is a monthly statement setting forth certain
volume, revenue, and expense data. The Commission is modifying Form No.
11 to accomplish three different purposes. First, the Commission is
modifying Form No. 11 to reduce the reporting burden on the pipelines,
since certain existing portions are no longer necessary. Second, Form
No. 11 is being modified to reflect the reduced emphasis on sales
service, and the greater emphasis on transportation and storage
services. As explained in the NOPR, as a result of the restructuring of
the interstate pipeline industry under Order No. 636, the pipeline's
sales business is declining while the pipeline's transportation and
storage business is increasing in relative importance. Much of Form No.
11 was geared towards the collection of sales-related data. Third, the
Commission is modifying Form No. 11 to ensure that the data collected
in the Form No. 11 and the Form No. 2, as revised, is more consistent.
This consistency will improve the usefulness of the data collected by
the Commission.
In the NOPR, the Commission essentially proposed to: (a) Reduce the
monthly reporting requirement to a semi-annual reporting of monthly
data; (b) remove or consolidate certain portions of the Form No. 11;
(c) collect the Form No. 11 data in the same general format as proposed
in Form No. 2; and (d) make certain other miscellaneous changes
throughout many parts of the Form. After reviewing the comments
received on the Form No. 11 proposal, set forth below, the Commission
is adopting a Form No. 11 that is significantly less burdensome in
detail than that proposed in the NOPR.71 As discussed infra, the
Commission is requiring that the simplified Form No. 11 monthly data be
submitted quarterly, rather than semi-annually as proposed, or monthly,
as it is currently filed. Thus, throughout the Form No. 11, we are
changing the title of the Form No. 11 to ``Natural Gas Pipeline Company
Quarterly Statement of Monthly Data.'' The Commission is also modifying
Form No. 11 to substantially reduce the data collected by the form. For
example, Form No. 11 will collect only data on volumes and revenues; we
are eliminating the reporting of all expense data in the Form No. 11.
\71\Revised Form No. 11 is attached as Appendix D. Appendix D is
not being published in the Federal Register, but is available from
the Commission's Public Reference Room and on the Commission's Gas
Pipeline Data Bulletin Board System.
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1. Comments
KN suggests combining Form No. 11 with Form No. 2, while INGAA and
CNG recommend eliminating Form No. 11. In support, INGAA and CNG argue
the information is already collected in Form No. 2. Further, they argue
that consolidating the monthly reports into two semi-annual reports
does not reduce the reporting burden. INGAA states the annual industry
reporting burden for a semi-annual Form No. 11 would be 6,600 hours,
compared to the Commission's estimate of 920 hours. Finally, INGAA
states that the semi-annual data would be filed too late to be used as
industry indicators, and too incomplete to provide an adequate picture
of pipeline operations or financial performance.
Several commenters support the continuation of Form No. 11, but
suggest changes to the proposed Form No. 11. Panhandle believes that
the required level of preparatory effort would be reduced, without
sacrificing the usefulness of the information, if the second semi-
annual report was incorporated as part of the Form No. 2, and the
information was compiled quarterly, rather than monthly. The
Industrials oppose semi-annual filings, and urge the Commission to
require monthly filing. They argue availability of this information on
a monthly basis helps customers and others determine when and whether
settlements on throughput or for interim rates are appropriate. NI-Gas,
on the other hand, does not object to semi-annual filing, but urges
continued reporting of monthly data (which is, in fact, what was
proposed by the NOPR).
NGSA recommends that the Form No. 11 reflect volumes and revenues
by rate category used by the pipeline. Further, it would like revenues
to be reported by rate schedule, month, and rate category, separately
showing base rate revenue and revenue from each surcharge. DOE uses
Form No. 11 data in several publications. It suggests that rate
schedule information be enhanced with a description to indicate the
different elements of service that are included. DOE suggests the
following classifications:
No-notice transportation
Balancing
Firm transportation
Storage and transportation (firm)
Storage and transportation (interruptible)
Incremental
Interruptible transportation
Short-term transportation
Released firm transportation
Other
The Industrials suggest a breakout by at least long-term firm (one-
year or more), short-term firm (less than a year), and interruptible
transportation; it states that the proposed requirement for reporting
by rate schedule fails to capture short-term firm service.
DOE also asserts the value of Form No. 11 data could be enhanced by
the inclusion of common codes and standardization. The data in Form No.
11 should be easily accessible (and downloadable) on a friendly
bulletin board system which provides access to the general user
community. INGAA makes the following specific suggestions if the
Commission chooses to retain Form No. 11:
Make the reporting in Form No. 11 consistent with Form No.
2 by changing instructions to indicate that all storage service
revenues should be reported on lines 15-17 and that withdrawal
quantities related to those storage services also be included on those
lines.
[[Page 53046]]
Remove language that indicates that injection and withdrawal revenues
should be reported on lines 46 and 47.
Eliminate requirements to provide breakouts of revenue and
quantities for services to interstate pipelines.
Correct the instruction for line 32 to refer to lines 30
and 31, not 22 and 23.
Add an instruction for line 42 to require the reporting of
the estimated total project cost of all of the projects that started
construction during the reporting period that are estimated to
individually cost at least $5,000,000.
2. Commission Ruling
The Commission is sensitive to the concerns of the commenters that
the proposed Form No. 11 filing requirement places a burden on the
pipeline companies. Therefore, we have carefully reconsidered the need
for the data in the Form No. 11. We will not accede to the pipelines'
wish that the Form No. 11 be eliminated. We are adopting a requirement
to file monthly data quarterly. However, we are substantially reducing
the monthly data required by this form from the previous requirements
and the requirements proposed in the NOPR.
Proposed Parts III Income Data, IV Other Selected Data, and V
Operation and Maintenance Expense, will be deleted. Part II Revenue
Data is being retained. The information collected in Part II, Revenue
Data, is the most fundamental information about the pipeline industry--
the amount of gas sold, transported, and stored. The Commission
continues to need, and will make use of, this basic information to
fulfill its responsibility to oversee the gas pipeline industry.
Contrary to INGAA's assertion, the Form No. 11 and Form No. 2 data do
differ. The Form No. 11 collects monthly data allowing aggregation of
data for any 12-month period, while Form No. 2 collects data aggregated
for a calendar year. The collection of monthly data will allow the
Commission to follow developing trends on a pipeline's system. It will
also permit observation of seasonal variation in throughput, something
the Commission cannot do with the data filed in Form No. 2. This
fundamental data makes it possible for the Commission to determine more
accurately the effects of its policies and decisions on the pipeline
industry.
To make the data more timely, we will require the form to be
submitted quarterly, rather than semi-annually, as proposed, and the
data to be submitted within 45 days of the end of the calendar quarter.
However, as noted, we will retain the requirement that monthly data be
reported. In other words, monthly data will be reported quarterly. The
request that data be filed monthly will be denied. The quarterly filing
requirement ensures more accuracy in the data filed. It also balances
the need for timely data against the burden of filing. Since the
monthly character of the data is being retained, we will not combine
Form No. 11 with Form No. 2.
Several commenters ask that the data be reported under additional
classifications or in more detail. The Commission will continue to
require the data in Form No. 11 be reported on the same basis as in
Form No. 2 to maintain consistency. DOE requests that we require the
pipelines to list the nature of the service provided, e.g., no-notice
transportation, firm transportation, balancing, etc. Many of the
classifications requested can be determined by the rate schedule
specified. The nature of the service provided under each rate schedule
is reported in the tariff. The tariffs are available for downloading,
together with the appropriate software, from the Commission's bulletin
board system.
The Commission will adopt the detailed revenue reporting requested
by NGSA. The Form No. 2 separates revenues into a column for transition
costs and take-or-pay, a column for GRI and ACA surcharges, and a
column for other revenues (See Account No. 489). We adopt this
structure for revenue reporting in Form No. 11.
DOE's suggestion that the data be standardized has merit. The
Commission wants the data from various sources to be interrelational.
That is, the data from one source should be capable of being linked
with data from another source. By providing for the linkage of data
from different sources, the Commission can avoid duplicative reporting
requirements. To enhance this capability, the instructions in the forms
and reports will direct the respondent to report the rate schedule
numbers the same way they are reported in all other submittals to the
Commission.
DOE also suggests the data be accessible and downloadable on a
bulletin board system which provides access to the general user
community. Since June 8, 1995, the Commission has made data filed
electronically in the Form No. 11 available on its Gas Pipeline Data
bulletin board (GPD) for download. The Commission will continue to
disseminate the electronic Form No. 11 data in this manner.
The specific changes in each section of the Form No. 11 are as
follows:
General Information and General Instructions
General Information section I (Purpose) is revised to reflect the
elimination of the collection of expense data as a purpose. General
Information section II (Who Must Submit) is modified to exclude gas
sold for resale from the calculation for determining which gas
companies must submit the Form No. 11. It is also modified to change
the requirement to comply to those gas companies whose gas transported
or stored for a fee exceeded 50 million Dth in each of the three
previous calendar years, rather than in only the previous calendar
year, as the current Form No. 11 requires. General Information section
III (When to Submit) is changed to require that the Form No. 11 be
filed quarterly. This section also sets forth a reporting schedule.
Each quarterly report is due 45 days after the end of the three-month
period being reported. Currently, the monthly reports are due 40 days
after the end of each month being reported. Finally, General
Information section IV (What and Where to Submit) is changed to delete
reference to the Commission's street address for the filing of the Form
No. 11.
General Instruction I is revised to require consistency between the
data filed on Form No. 11, and the data filed with Form No. 2. It is
the intent of the Commission to be able to compare the aggregation of
twelve months of information submitted on the Form No. 11 with data
filed on the Form No. 2. Comparisons with the Form No. 2 data may
require aggregation of the Form No. 2 data as well.
There is no change to General Instruction II, specifying the use of
parentheses to indicate negative amounts.
The Commission is adding a requirement to Instruction III to
require that quantities in the Form No. 11 be reported in thousands of
dekatherms. The change to dekatherms is consistent with the changes
proposed to the Form No. 2. Revenues will continue to be reported in
thousands of dollars, as currently required by instruction III.
General Instruction IV, allowing for the use of footnotes in the
Form No. 11, is modified to change the reference to the part number
where the footnotes are listed from Part VI to Part III.
General Instruction V, regarding estimated data, is removed. Since
the average lag time between the month reported and the date the filing
is made will be longer, the Commission anticipates that actual data
will be readily available. Thus, estimated data
[[Page 53047]]
will not be necessary. General Instruction V is replaced with an
instruction specifying that one Part II form must be reported for each
month.
Specific Instructions and Definitions
The instruction for the item ``All'' is modified to specify that
quantities must not be adjusted for discounts. We are adding specific
instructions for items 7 through 12 and 15 through 17, to conform to
the instructions contained in Form No. 2 for reporting transportation
and storage services, and to clarify the reporting of storage revenues.
In the NOPR, we proposed to make separate, specific instructions for
items 15 through 17 for the reporting of storage revenues, which
indicated that certain storage revenues were to be reported at those
items, and other storage revenues were to be reported at items 46 and
47. In accordance with INGAA's suggestion, we are eliminating those
specific instructions for items 15 through 17, and requiring all
storage service revenues be reported at items 15 through 17, including
the withdrawal quantities related to those storage services.
In the NOPR, we proposed specific instructions for items 7 through
12 that required, among other things, that transportation delivered to
a pipeline under a rate schedule be reported separately from
transportation delivered to others under that rate schedule. INGAA asks
us to eliminate this requirement to provide breakouts of revenue and
quantities for services to interstate pipelines. A similar provision
proposed in Form No. 2 is not being adopted. To retain consistency
between the reporting of revenues in Form No. 2 and Form No. 11, we
will not adopt the proposal in the NOPR. This action satisfies INGAA's
request.
Existing specific instructions for items 22, 24, 27 and 38 through
40 are deleted, since the Commission no longer proposes to collect
information on these items, which are contained in Parts III and V,
that are now being deleted. The remainder of INGAA's suggestions,
regarding the Commission's proposed specific instruction for item 32,
and the addition of an instruction for item 42 are no longer relevant
given the elimination of the Form No. 11 reporting requirements in
Parts III, IV, and V.
All existing definitions in the Form relate to purchases or sales
of natural gas. The Commission is simplifying the reporting of sales
and purchase information; therefore, the definitions are removed as no
longer necessary.
Identification (Part I) and Revenue Data (Part II)
Except for revising the instruction to read ``Period Reported''
instead of ``Month Being Reported,'' the Commission is leaving Part I
intact. The Commission is modifying Part II, which relates primarily to
sales service, to reflect the decreased emphasis on sales service, and
increased emphasis on transportation and storage services subsequent to
the implementation of Order No. 636. Specifically, Part II is modified
to collect information for sales, transportation, gathering, storage
and other revenue categories in the same way it is proposed to be
collected in the Form No. 2, but on a monthly basis rather than
annually.
Income Data (Part III), Other Selected Data (Part IV), and Operation
and Maintenance Expense (Part V)
The Commission is eliminating Parts III, IV, and V of the Form No.
11. The information required to be reported under these Parts is no
longer necessary for the Commission's regulatory review purposes.
D. Other Revisions
Section 260.1 requires that major natural gas companies, as defined
in part 201 of the Commission's regulations, file with the Commission
an annual report, designated as FERC Form No. 2. The Commission is
modifying section 260.1 to reflect in the text of the regulations the
new definition of ``major company'' (a natural gas company whose
combined gas transported or stored for a fee exceeded 50 million Dth in
each of the three previous calendar years). The Commission is also
specifying in section 260.1 that newly established entities must use
projected data to determine whether the Form No. 2 must be filed, and
that the Form No. 2 must be filed electronically. In addition, the
Commission is revising section 260.1 to delete reference to an
effective date, and to remove references to reporting requirements pre-
dating December 30, 1988.
Section 260.2 requires that nonmajor natural gas companies file an
annual report, designated as FERC Form No. 2-A. The Commission is
modifying section 260.2 to specifically define who must file the Form
No. 2-A. Section 260.2 is revised to state that those natural gas
companies required to file the Form No. 2-A are companies not meeting
the filing threshold for Form No. 2, but having total gas sales or
volume transactions exceeding 200,000 Dth in each of the three previous
calendar years. The Commission is also specifying in section 260.2 that
newly established entities must use projected data to determine whether
the Form No. 2-A must be filed, and that the Form No. 2-A must be filed
electronically. In addition, the Commission is revising section 260.2
to delete reference to an effective date, and to remove references to
reporting requirements pre-dating December 30, 1988. These latter
changes mirror the changes set forth in section 260.1 governing the
FERC Form No. 2.
Section 260.3 requires that natural gas companies file with the
Commission a monthly statement--the FERC Form No. 11--containing
information concerning selected revenues, income statements, and other
items, and details of operation and maintenance expenses. The
Commission is modifying the title and paragraph (a) of section 260.3 to
reflect the change of the Form No. 11 to a quarterly statement of
monthly data, that no longer collects expense data. In paragraph (b),
the Commission is redefining who must file the Form No. 11 (natural gas
companies whose gas transported or stored for a fee exceeded 50 million
Dth in the previous three calendar years), and is specifying that the
form be filed electronically. Further, the Commission is revising
paragraph (c) prescribing when to file the Form No. 11 to reflect the
quarterly filing schedule set forth in the Form No. 11 itself. In
addition, the Commission is removing references to dates that have long
since passed, and references to reporting requirements pre-dating
November 30, 1988.
Section 260.4 requires that importers and exporters of natural gas
file with the Commission an annual report, FPC Form No. 14. Section
260.11 requires natural gas companies operating an underground natural
gas storage field to file with the Commission a monthly underground gas
storage report, Form No. 8. In the NOPR, the Commission did not propose
any substantive changes to these sections. Instead, the Commission
sought comments on whether the collection of the information contained
in these forms by other governmental or private sources is currently
adequate, making the collection of the same information in these
Commission forms unnecessary.
INGAA, American Forest, KN, and ANR/CIG recommend the elimination
of FPC Form No. 14. American Forest and INGAA note that DOE's Office of
Fossil Energy collects periodic reports on export and import activity
as part of its oversight responsibility. They state that these reports
collect substantially the same information as required by Form No. 14.
According to INGAA, the elimination of this form would reduce
[[Page 53048]]
the burden on respondents by about 1,100 hours per year. ANR/CIG
concurs that this data is collected elsewhere.
The Commission will eliminate the requirement for filing FPC Form
No. 14 from its regulations. The Commission's primary need for natural
gas import and export information is related to its administration of
Presidential Permits for import and export facilities under Executive
Order No. 10485. While we need certain capacity and usage information
to authorize facilities and verify the approved capacity of such
natural gas import and export facilities, the Commission does not
generally need information on the purchasers or prices of imported and
exported natural gas and LNG.
Thus, the Commission expects that it will have adequate data on
natural gas imports and exports through any continuing collection of
import-export data that DOE/EIA may pursue, DOE/Fossil Energy's (FE)
Quarterly Reports, or data requests in specific case processing or
litigation.\72\ Although the DOE/FE Quarterly Reports and Form No. 14
have different data items, it is true, as INGAA and American Forest
state, that most of the substantive information is duplicative.
\72\To the extent DOE/EIA continues to require the Annual Report
for Importers and Exporters it will have to pursue separate OMB
clearance for this data collection on its own.
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The Commission's Staff will consult in more detail with DOE/EIA and
DOE/FE on maintaining an ongoing, non-duplicative collection of import-
export data by DOE, such as peak-day usage, differentiation of multiple
operators at singularly named import-export points, and the BTU content
of natural gas and LNG. Section 260.4, prescribing the Form No. 14, is
deleted from the regulations.
With respect to the Form No. 8, ANR/CIG, INGAA, KN, DOE, and El
Paso support its elimination. They argue this information is collected
elsewhere. Specifically, DOE notes that it collects monthly injection
and withdrawal data from all companies operating storage fields,
including those who file Form No. 8, in its ``Underground Gas Storage
Report,'' Form EIA-191. DOE states that the Form EIA-191 is a more
comprehensive form than the Form No. 8, and collects the data that the
Commission requires to monitor jurisdictional companies. Thus, DOE
maintains that the Commission would no longer need Form No. 8 if it
used the data from Form EIA-191. However, DOE points out that,
currently, the data submitted in Form EIA-191 are considered
confidential. If the Commission agrees with DOE's proposal to use Form
EIA-191, DOE states that it will submit Form EIA-191 to the Office of
Management and Budget for clearance to remove the confidentiality
requirements. DOE notes that a recent attempt to do so in 1991 did not
succeed. However, DOE believes that pipelines' concerns voiced at the
time may have since decreased with the implementation of Order No. 636,
as many companies have provided copies of their Form EIA-191 filings to
the trade press. DOE states that upon OMB's approval for the removal of
the confidentiality requirements, EIA will continue to process the EIA-
191, and will make the data available to the Commission on a timely
basis.
INGAA concurs that there is no regulatory reason for both DOE and
the Commission to spend taxpayer dollars for duplicate reporting. INGAA
states that gas storage data is reported in the monthly Form EIA-191
and the semi-annual storage reports under existing sections 284.106(g)
and 284.223(d)(5), and that weekly estimates of working gas in storage
are available by region through the ``American Gas Storage Survey''
five days after the end of the reporting week. INGAA notes that
elimination of Form No. 8 would reduce the industry reporting burden by
1,440 hours per year.
El Paso also supports elimination of this form or, at least,
elimination for those pipelines with facilities that are not operated
as traditional underground storage facilities. For example, El Paso's
Washington Ranch Storage Facility is operated exclusively as an adjunct
to El Paso's transmission system for load balancing, line pack, and
pressure control. El Paso argues that the Form No. 8 reporting
requirements should not apply to this facility.
The Commission will eliminate the requirement to file Form No. 8.
One of the objectives of this rulemaking is to eliminate duplicative or
unnecessary reporting requirements. DOE's proposal that the Commission
use the information from Form EIA-191 furthers this goal. As a result
of pipeline restructuring, the data from Form EIA-191 can typically be
used to meet the Commission's requirements for storage data in lieu of
the Form No. 8 information. Although we do not seek removal of the non-
disclosure provisions from the Form EIA-191 data collection as a pre-
condition to elimination of the Form No. 8, we endorse DOE's efforts to
reach consensus with the Form EIA-191 respondent population on this
issue.
In the event that OMB does not approve DOE's request to remove the
confidentiality provision from the Form EIA-191 data collection, we
will not reinstate Form No. 8. For most purposes, aggregated data
derived from Form EIA-191 should suffice. In the event specific
pipeline storage data is required for a project or proceeding, and the
Form EIA-191 data continues to be confidential, the Commission could
obtain the company-specific Form EIA-191 data from DOE pursuant to the
confidentiality provisions of this data collection. The Commission also
reserves the right to seek whatever information is required through a
data request in individual proceedings. Section 260.11, prescribing the
Form No. 8, is deleted from the regulations.
Section 260.9 requires every natural gas pipeline company to report
to the Commission serious interruptions of service to any wholesale
customer involving facilities operated under certificate authorization
from the Commission. The Commission is modifying sections 260.9(b) and
(e) to include facsimile transmission as an optional method for
reporting interruptions of service. This recognizes advances in
technology and current practice. Further, the Commission is modifying
sections 260.9(b) and (c) to require that companies send telegrams,
facsimile transmissions, or supplemental information to the Director,
Division of Environmental and Engineering Review, Office of Pipeline
Regulation, the successor to the Director, Division of Engineering,
Market and Environmental Analysis, Office of Pipeline and Producer
Regulation. The Commission is also deleting reference to the
Commission's street address, and correcting the Commission's zipcode in
section 260.9(b).
Section 260.13 sets forth the requirements for the filing of the
FERC Form No. 549-ST, Form of self-implementing transportation reports.
The initial and subsequent reports currently filed by interstate and
intrastate pipelines, Hinshaw companies, and local distribution
companies undertaking transportation transactions under subparts B, C,
or G of part 284 are required to be made on the FERC Form No. 549-ST.
Because the Commission is eliminating the requirements of filing
initial and subsequent reports for companies subject to the
requirements of subparts B, C, and G of part 284, as further described
below, the FERC Form No. 549-ST is no longer necessary. Accordingly,
the Commission is removing section 260.13.
Section 260.15 requires that natural gas companies making direct
sales in
[[Page 53049]]
interstate commerce of natural gas to customers consuming such gas file
a Report of Alternate Fuel Demand Due to Natural Gas Curtailment, FPC
Form No. 69. As noted in the footnote to section 260.15, Form No. 69
was discontinued and replaced with Form No. EIA-50 by order issued June
23, 1978.\73\ The EIA Form No. 50 was eliminated in 1984 after the
Office of Management and Budget (OMB) rejected the Energy Information
Administration's (EIA) request for an extension of OMB approval of the
data collection. Thus, it now appears that the footnote to 18 CFR
260.15 references a non-existent EIA form as a replacement for the Form
No. 69. Since neither the Commission nor EIA has collected this data
since 1984, and there has been no significant curtailment of natural
gas in the nation for more than ten years, the Commission is removing
section 260.15.
\73\FERC Statutes and Regulations, Regulations Preambles, 1977--
1981, para. 30,013 (1978).
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In addition, the Commission is changing all references in Part 260
from the ``FPC'' and the ``Federal Power Commission'' to the ``FERC,''
and ``Federal Energy Regulatory Commission,'' respectively.
VII. Part 284
A. Introduction
Under Part 284, the Commission is revising the reporting
requirements, and/or certain non-reporting requirements, contained in
Subparts A, B, C, E, G, J, and L. These subparts set forth general
provisions and conditions (Subpart A), and govern the transportation of
natural gas by interstate pipelines under section 311(a)(1) of the NGPA
(Subpart B), the transportation of natural gas by intrastate pipelines
under section 311(a)(2) of the NGPA (Subpart C), the assignment by any
intrastate pipeline to any interstate pipeline or local distribution
company of contractual rights to receive surplus natural gas under
section 312 of the NGPA (Subpart E), the transportation of natural gas
by interstate pipelines on behalf of others, and services by local
distribution companies, under blanket certificates authorized by
section 7(c) of the NGA (Subpart G), (General Provisions and
Conditions), as well as the sale of natural gas under section 7(c)
blanket certificates by interstate pipelines offering transportation
service under subparts B or G (Subpart J), and by non-interstate
pipeline sellers (Subpart L).
There are six major categories of changes to the Part 284
provisions: (1) the removal of the initial full report, subsequent
reports, annual report, and notification of termination, currently
required under subparts B, G, and/or J; (2) the removal of the initial
full report, subsequent reports, and notification of termination
required under subpart C; (3) the refinement of the Commission's
discount reporting requirement; (4) the addition of a new reporting
requirement under subparts B and G, an electronic Index of Customers;
(5) the elimination as obsolete of certain non-reporting provisions in
subparts A, B, C, and G, setting forth interim measures related to the
implementation of Order Nos. 436 and 636; and (6) other changes that
either are grammatical in nature, remove references to deadlines that
have long since passed or other outdated requirements, or reflect the
use of current, more accurate, terminology. These revisions are
discussed more fully below.
B. Removal of Initial, Subsequent, Annual, and Termination Reports
Under Subparts B, G, and J
In light of all of the broad changes that are being required in
this rule, and the changes to the industry brought about by Order No.
636, it is no longer necessary to require interstate pipelines to
provide the detailed reporting set forth under the initial, subsequent,
termination, and annual reports in sections 284.106 and 284.223. We
have determined that the information included in these reports is no
longer required for our regulatory review of the natural gas industry.
Accordingly, the Commission is removing paragraphs (a), (b), (c),
and (d) of section 284.106, and paragraph (d) of section 284.223, to
delete the requirements that interstate pipelines file the initial full
report, subsequent reports, notification of termination, and annual
report. The Commission is also removing sections 284.106(e) and
284.223(b) relating to the fees accompanying the initial full report,
and sections 284.106(f) and 284.223(c), prescribing the use of FERC
Form No. 549-ST for the initial and subsequent reports, since they
would no longer apply due to the discontinuance of the associated
reporting requirements.
However, the Commission will retain the requirement in section
284.106(a)(4) that an interstate pipeline file a statement with the
Commission that the pipeline has provided notification of bypass of a
local distribution company (LDC) to the LDC and the LDC's regulatory
agency. The Commission will also retain the semi-annual storage reports
currently required under sections 284.106(g) and 284.223(d)(5).
Because sections 284.106 and 284.223 will require identical
reporting requirements, the Commission is removing all of the filing
requirements from section 284.223(d), and substituting a statement that
all pipelines transporting gas under section 284.223 of Subpart G must
comply with the reporting requirements specified under section 284.106
of Subpart B. There is no reason to specify the same exact reporting
requirements twice in the regulations.
In the NOPR, the Commission proposed to remove the annual sales
report required under section 284.288 of Subpart J, applicable to
pipelines that engage in sales under a blanket certificate and also
offer interstate transportation under subparts B and G. The Commission
proposed to remove this reporting requirement to eliminate duplicative
reporting requirements, because most of the information was also being
collected under the proposed Form No. 2. However, the Form No. 2 that
is being adopted in this final rule no longer captures transaction-
specific volume and revenue data that the section 284.288 sales report
collects. Therefore, the Commission is retaining this sales
report.74
\74\See Pipeline Service Obligations and Revisions to
Regulations Governing Self-Implementing Transportation; and
Regulation of Natural Gas Pipelines After Partial Wellhead
Decontrol, III FERC Stats. & Regs. Preambles para. 30,939 at p.
30,443 (April 8, 1992) (Order No. 636), order on reh'g, III Stats. &
Regs. Preambles para. 30,950 at p. 30,624 (August 3, 1992) (Order
No. 636-A), for the Commission's rationale for collecting this
information.
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These changes are the same changes proposed in the NOPR. Our
proposed deletion of these reporting requirements received strong
support by the commenters. INGAA, Texas Gas, KN, Columbia, and NI-Gas
support the elimination of the initial, subsequent, termination, and
annual reports under subparts B, G, and J without reservation.
Other parties offered conditional support. American Paper supports
the proposed modifications to subparts B and G in light of the other
proposals made by the Commission in the NOPR, including the requirement
that pipelines maintain and update an Index of Customers and file
discount rate reports. Similarly, APGA supports the elimination of
these reports provided that the Commission adopts section 154.1
requiring pipelines to file contracts with the Commission when they
differ from the form of service agreement. Columbia and SoCal express
support for the removal of related section 260.13 requiring the initial
and subsequent reports to be reported on the FERC Form No. 549-ST.
SoCal's support is contingent upon the
[[Page 53050]]
Commission's adoption of the proposed discount rate report.
APGA, SoCal, and NI-Gas support the retention of the requirement
that a pipeline file a statement with the Commission that it has
provided notification of bypass of an LDC to the LDC and the regulatory
agency.
Only our proposal to retain the two semi-annual storage reports
required under sections 284.106(g) and 284.223(d)(5) generated requests
for a different treatment. Texas Gas recommends the elimination of the
semi-annual storage reports in light of the requirement to include
information concerning firm storage service in the Index of Customers.
INGAA suggests that the two semi-annual storage reports be combined
into one annual storage report. INGAA states that this would provide
the Commission with the data it needs while reducing the burden on the
pipelines.
As noted above, the Commission is retaining the semi-annual storage
reporting requirement. We will not adopt Texas Gas' request for
elimination. The Index of Customers adopted in this rule will collect
very limited information concerning firm storage service, and will not
collect many of the data elements required by the semi-annual storage
report. Nor will we adopt INGAA's proposal that the storage report be
filed annually rather than semi-annually. The semi-annual nature of the
reports derives from the timing of the reports. The reports are
submitted so that the withdrawal season is reported separately from the
injection season. This is an important distinction which the Commission
does not wish to eliminate.
The Commission recognizes that some parties may withdraw their
support for the elimination of the initial, subsequent, termination and
annual reports, now that we have substantially modified the discount
report and Index of Customers that were proposed. However, the proposed
elimination of these reports was not solely dependent on the collection
of the information elsewhere. As stated supra, the information in these
reports is no longer needed for the Commission to carry out its
regulatory responsibility.
C. Removal of Initial, Subsequent, and Termination Reports Under
Subpart C
The Commission is deleting certain of the reporting requirements
for intrastate pipelines transporting gas under NGPA section 311 under
Subpart C. The Commission is eliminating the initial full report,
subsequent reports, and notification of termination currently required
under section 284.126. The Commission no longer finds these reports
useful for regulatory review. In the NOPR, the Commission invited the
parties to comment on our proposed removal of these reports. In
response, KN, Transok, Enogex, Texas Intrastates, and NI-Gas filed
comments supporting the elimination of the initial, subsequent, and
termination reports required in section 284.126.
While the Commission is eliminating the annual reporting
requirement for interstate pipelines, as described, supra, the
Commission will continue to require intrastate pipelines to file the
annual report currently required by section 284.126(c), as well as the
semi-annual storage reports required under section 284.126(g), and the
notification of bypass requirement currently included in the initial
report, section 284.126(a)(6). INGAA suggests that the annual report be
eliminated so that the requirements for intrastate reporting will
mirror the requirements for interstate reporting. However, unlike the
interstate pipelines, intrastate pipelines are not subject to the full
force of the federal reporting requirements. Intrastate pipelines do
not file Form No. 2, an Index of Customers, or general rate cases under
section 4 of the NGA. Thus, fewer opportunities are available to the
Commission and the public to obtain information about the intrastate
pipelines' jurisdictional activities. The participation of the
intrastate pipelines in the interstate market should be accompanied by
accountability. Therefore, the Commission is continuing to require the
intrastate pipelines to submit the annual report.
The Commission, though, is revising the annual report (now section
284.126(b)), as proposed in the NOPR, to reflect the fact that the
transportation transactions are no longer docketed, and to require the
specification of whether the transportation service is firm or
interruptible. Until recently, intrastate pipelines only provided
interruptible transportation service. Since they are now performing
firm transportation service, firm and interruptible transactions must
be separately identified for accurate reporting.
Transok and the Texas Intrastates ask that the filing date for the
annual report be changed from March 1 to March 31 to make it easier to
gather the necessary information, and consistent with the due date for
FERC Form No. 2-A. We will grant this request for an extension of the
filing date from March 1 to March 31. This will lessen the burden in
submitting this information.
The Texas Intrastates argue that the requirement to file semi-
annual storage reports (new section 284.126(c)) should be removed. They
state that the Commission has no certificate jurisdiction over NGPA
section 311 storage transactions by intrastate pipelines, and that the
storage reporting requirement is duplicative because information on
storage volumes is reported in the annual transportation report.
Transok, also, supports eliminating the semi-annual storage reports,
adding that the information is incomplete and not necessarily useful to
the Commission because non-jurisdictional intrastate activity is not
reported. Transok states that the DOE receives a complete report of
aggregated intrastate and interstate storage activity each month
through the Monthly Underground Gas Storage Report, Form EIA-191.
Transok further argues that, in its case, the request for price
information is moot because the Commission has approved market-based
pricing for Transok's section 311 storage services.
Similarly, Equitable urges the Commission to exempt intrastate
storage companies with market-based rates from the requirement to file
semi-annual reports, since the reports require pricing information.
Equitable maintains that where market-based rates are in effect, the
Commission does not need pricing information to determine if the rates
charged exceed allowed maximums, or the extent of discounting for
future ratemaking purposes. Equitable states that in a competitive
market, price transparency occurs, if at all, through market channels.
The Commission will not eliminate the semi-annual storage report.
Contrary to the Texas Intrastates' assertion, storage reporting is
expressly excepted from the annual transportation report. This report,
therefore, is not duplicative. Furthermore, the Form EIA-191 cannot be
substituted for the semi-annual storage data. As the Commission stated
in Order No. 636-A,75 the EIA does not collect data by individual
customer, nor does it collect rate and revenue data. In addition, the
pricing information for storage service subject to market-based pricing
is not moot. Although the Commission does not have certificate
jurisdiction over NGPA Section 311 intrastate storage service, Section
311 tasks the Commission with the responsibility to ensure rates and
charges are fair and equitable.76 For the Commission to carry out
this
[[Page 53051]]
responsibility, it is important for rates charged to be reported. It is
even more critical for the Commission to review pricing when the
Commission is relying on competition to regulate rates, rather than
scrutinizing the underlying cost of service. Thus, we will not exempt
intrastate storage companies charging market-based rates from the
requirement to file semi-annual storage reports.
\75\Pipeline Service Obligations and Revisions to Regulations
Governing Self-Implementing Transportation; and Regulation of
Natural Gas Pipelines After Partial Wellhead Decontrol, III Stats. &
Regs. Preambles para. 30,950 at p. 30,581 (August 3, 1992) (Order
No. 636-A).
\76\15 U.S.C. 3372.
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Accordingly, the Commission is deleting from section 284.126
existing paragraphs (a) (initial full report); (b) (subsequent
reports); (d) (notification of termination); (e) (filing fees); and (f)
(reporting form).77 The notification of bypass in paragraph (a)(6)
is now paragraph (a), the revised annual report is now paragraph (b),
and the semi-annual storage report is paragraph (c). The only change we
are making with respect to section 284.126 in this final rule from what
was proposed in the NOPR, is the extension of the filing deadline of
the annual report from March 1 to March 31.
\77\Freeport notes that paragraph 106 of the regulation text
does not list current paragraph (d) regarding notification of
termination among those paragraphs to be removed, contrary to the
stated intent of the preamble. This was simply an oversight of the
Commission in the drafting of the regulations. Paragraph (d) of
section 284.126 should be eliminated, and in the regulation text to
this final rule, we are including paragraph (d) among those to be
removed.
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Finally, the Commission is adopting an additional change proposed
in the NOPR in relation to Subpart C. The Commission is revising the
filing requirements under section 284.123(e) to require that the
statement filed by an intrastate pipeline within 30 days after
commencement of new service under subpart C, include the rate election
made by the intrastate pipeline under section 284.123(b).
D. Modification of Discount Reports
1. NOPR Proposal
In the NOPR, the Commission proposed to combine the following two
discount reporting requirements to avoid duplication. Section
284.7(d)(5)(iv) presently requires that all pipelines charging a
discounted rate for transportation service under subparts B and G of
Part 284 file, within 15 days after a billing period, a report with the
Commission identifying the maximum rate or reservation fee, the rate or
fee actually charged during the billing period, the shipper, and any
affiliation between the shipper and the pipeline. Section 250.16(d)
requires that pipelines transporting gas under subparts B or G that are
affiliated with a gas marketing or brokering entity and conduct
transportation transactions with such affiliate, also maintain a
variety of more detailed information on the transportation discounts
they provide to affiliate and non-affiliate shippers. For example,
section 250.16(d) requires maintenance of information on quantities
scheduled under the discount, while section 284.7(d)(5)(iv) does not
require the filing of any quantity information. Thus, the more detailed
information required by section 250.16 only has to be maintained and
made available to the Commission upon request, while the limited
information required under section 284.7(d)(5)(iv) must be filed with
the Commission.
Because the information required by section 284.7(d)(5)(iv) is also
required by section 250.16(d), the Commission determined in the NOPR
that these requirements were somewhat duplicative, and proposed to
consolidate the two sections into one discount reporting requirement,
new section 284.7(c)(6). The Commission proposed to eliminate the
section 250.16(d) maintenance requirements, and expand the filing
requirements under Part 284 to include most of the information
previously maintained under section 250.16(d). Under this proposal, the
major change from the existing section 284.7(d)(5)(iv) was the addition
of a requirement for filing information on quantities of gas delivered
for discounted interruptible service, and the contract demand for
discounted firm service.78 The Commission stated in the NOPR that
information on quantities shipped and contract demand would enable the
Commission and the market to compare the extent of interruptible and
firm discounting by the pipelines with the extent of the discounting of
capacity release transactions under the capacity release program
established by Order No. 636. The Commission proposed that the discount
information under new section 284.7(c)(6) be filed electronically with
the Commission.
\78\For interruptible discounts, the Commission proposed to
include the zone in which the quantities are delivered. The
Commission stated that information on zones was not needed for firm
service because the information was to be reported in the index of
customers under section 284.106.
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2. Comments
The Commission received a few comments in support of its proposal,
but many more comments in opposition to proposed section 284.7(c)(6),
as summarized below.
APGA believes that the proposed change to the discount reporting
requirements will enhance the quality of data relating to pipeline
discounts. The Registry also fully supports the modifications to the
discount reporting requirements, and believes that respondents will be
able to file the discount report using data that they already collect
either to perform or monitor essential services.
NI-Gas supports the proposed discount rate report but asks that the
Commission require information on the duration of discounts and the
applicable delivery points. NI-Gas asserts that discount information
must continue to be available on a timely basis to interested parties
so that: (a) all interested parties can monitor the operations of the
market; and (b) releasing shippers have access to the same information
with respect to pipeline sales of capacity as pipelines have with
respect to capacity releases. NI-Gas believes that the additional
information is necessary to achieve this parity.
However, many of the commenters argue that the proposed
modifications to the discount report will require pipelines to publicly
divulge commercially sensitive information. Panhandle opposes the
proposed reporting requirements on this basis. It argues that the
Commission should ensure that the pipeline and its customers are not
disadvantaged where there is a competitive alternative provided by a
non-regulated entity. Panhandle states that shippers will be less
inclined to deal with pipelines that are required to reveal sensitive
data. As an alternative to the proposed requirement, Panhandle suggests
providing for confidential periodic audits, and requiring pipelines to
maintain information sets for a period of three years and to provide
the information to the Commission on a confidential basis upon request.
Tennessee, also, believes that pipelines will be harmed if they are
required to reveal customer specific details of their transactions as
proposed in the discount rate reports and Index of Customers. Tennessee
argues that this level of detail has not previously been required and
is not necessary in a more competitive environment. It states that
other market participants are not required to divulge transactional
information at this level of detail. In any case, Tennessee argues that
this information can be produced on a case-specific basis in response
to a complaint or in a rate case, and that this is the wrong time to
expand the type and detail of transactional information.
Consumers Power, NI-Gas, and AGA argue the proposed discount rate
data coupled with other publicly available information, such as the
proposed Index of Customers, will permit the derivation
[[Page 53052]]
of specific point-to-point contractual pricing information for firm
capacity discounts. For this reason, they suggest the removal of the
contract number from the discount rate report.
ANR/CIG note the increase in competition occasioned by the
Commission's issuance of Order Nos. 436 and 636. They state that the
discount reporting requirements provide such a wealth of information
that competitors can target pipelines' customers to offer them better
deals. ANR/CIG argue that specific details of individual discounts
disadvantage the customers who have negotiated those discounts.
Therefore, ANR/CIG assert that discount information should be limited
to the information currently required.
INGAA argues the information the Commission proposes to collect is
commercially sensitive and not necessary to meet the purpose of the
discount reporting requirement--to ensure that discounts are provided
on a non-discriminatory basis. INGAA asserts that the Commission did
not explain in the NOPR why it is proposing to alter the purpose and
method of providing the discount information, or why non-affiliate
discount data is inadequate as currently filed. Texas Gas, while
supporting the elimination of the duplicative discount reporting
requirements, concurs with INGAA's position that certain items of
information are inappropriate for public dissemination and unnecessary
to fulfill the original purpose of the discount reporting requirements.
INGAA adds that consideration of the data required to compare the
extent of interruptible and firm discounting by pipelines with
discounting in the capacity release market is better addressed in the
Commission's rulemaking on capacity release. INGAA asserts that
pipelines should be required to maintain, but not file, discount
information, making the data available to the Commission upon request.
Alternatively, if information on discount transactions must be filed,
INGAA argues that the amount of information required must be reduced to
no more than is currently reported. KN and MRT either adopt or support
INGAA's comments with respect to the discount reports.
Some commenters propose that the Commission require a less frequent
reporting of the discount information and a lengthening of the filing
deadline, which is 15 days after the close of the billing period. If
information on discount transactions must be filed, INGAA supports an
annual reporting period for the discount report, or the filing of the
discount report no more frequently than each quarter, with the filing
deadline 30 days after the last month of the quarter in which billing
occurs. If pipelines must file monthly, INGAA states, the filing
deadline should be extended to 30 days after the close of the billing
period. Texas Gas agrees. Panhandle argues that if discount reporting
remains a requirement, monthly discount activity should be compiled and
submitted on a quarterly basis, 45 days following the last day of each
quarter. Panhandle states that all of the data elements could be
maintained on a monthly basis for a three-year period from the time of
the discounting.
3. Commission Ruling
In light of substantial opposition to the proposed changes, the
Commission will not adopt the proposed modifications to the reporting
requirements for discounted transactions outlined in the NOPR. The
Commission will retain the separate, pre-existing requirements in
sections 284.7 and 260.15(d), with some minor modifications. While this
will involve some duplication, the existing requirements of section
284.7, together with the requirements in section 260.15(d), already
provide the balance between public disclosure and confidentiality that
the commenters seek. The changes to these sections proposed in the NOPR
were not prompted by a need for more stringent reporting requirements
to ensure discounts are offered on a non-discriminatory basis. Thus,
the information available through, not only sections 284.7 and 250.16,
but also through section 161.3, regarding affiliate discount
transactions, continues to be sufficient for the market and the
Commission to determine if any discriminatory activity is taking
place.79 This is, and remains, the primary purpose of these
sections of the regulations.
\79\Under Standard H of the Standards of Conduct, section
161.3(h), pipelines transporting gas under subparts B or G of Part
284 or subpart A of Part 157 that are affiliated with a gas
marketing or brokering entity and conduct transportation
transactions with such affiliate are now required to post discount
information concerning affiliate transactions on their EBBs,
including the delivery points to which the discount applies.
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Our proposal to expand the discount reports to include information
was designed to increase the usefulness of the discount reports by
enabling the market and the Commission to compare the extent of
discounting by pipelines with the extent of discounting in the capacity
release market. However, we have determined that the benefits realized
from the creation of another use for the discount reports are
outweighed by the risk of harm to pipelines and LDCs that would stem
from the release of this detailed information.
The Commission is not modifying the existing regulations to adopt
annual or quarterly discount reporting, nor lengthening the time of
filing to 30 days after the close of the billing period. The primary
purpose of the discount reports is to allow customers to monitor
discounts to determine if the pipeline is discriminating. Such
proposals would make it impossible for customers to monitor
discrimination on a timely basis. Nor is the Commission adopting
INGAA's suggestion that all of the discount data be maintained, but not
filed. However, we are adopting INGAA's alternative recommendation that
the data that is required to be filed be limited to the data currently
required.
The Commission is removing the discount information currently
required in section 284.7(d)(5)(iv), and reinserting it in a new
section 284.7(c)(6). In addition, section 284.7(c)(6) now specifies
that the pipeline report ``the full legal name of the shipper being
provided the discount,'' rather than merely ``the shipper,'' as the
current regulation specifies. Further, the Commission adopts the
proposal from the NOPR to require the data filed under section 284.7 to
be submitted electronically.
The Commission also is adding, as proposed in the NOPR, a provision
specifying that the discount report does not apply to capacity releases
at a discounted rate, except when the release is permanent. The
discount report is designed to capture discounts granted by the
pipelines. In a temporary capacity release, the releasing shipper is
still obligated to the pipeline under its initial contract. Thus, even
if the shipper obtaining released capacity pays a discounted rate, the
pipeline has not agreed to the discount because the releasing shipper
will owe the pipeline the maximum rate under its contract. In a
permanent capacity release, however, the releasing shipper's
contractual obligations end, and the replacement shipper enters into a
new primary contract with the pipeline. Thus, if the pipeline offers a
discount for a permanent capacity release, the pipeline is providing
the discount and would have to report it.
E. Establishment of Electronic Index of Customers
1. NOPR Proposal
In the NOPR, the Commission proposed to require interstate
pipelines
[[Page 53053]]
transporting gas under subparts B and G to provide an electronic Index
of Customers80 through a downloadable file that is updated
monthly, and restated in its entirety annually (proposed sections
284.106 and 284.223). As further discussed below, the Commission is
retaining the requirement that pipelines maintain a downloadable
electronic file containing an Index of Customers in the final rule.
However, the Commission is adopting an Index of Customers that is
greatly abbreviated from the Index that was proposed in the NOPR, and
is quarterly, rather than monthly.
\80\The Commission is using the term ``Index of Customers''
rather than ``Index of Purchasers,'' to reflect the use of that term
in Docket No. RM95-3-000, revising part 154. ``Index of Customers''
more accurately captures the nature of the current natural gas
market.
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The electronic Index of Customers proposed in the NOPR originated
in the Electronic Bulletin Board (EBB) standardization proceeding in
Docket No. RM93-4-000.81 As explained in the NOPR in this
proceeding, the EBB Industry Working Groups in the EBB standardization
proceeding, which developed the standards implemented by the
Commission, failed to reach consensus on a proposal for an Index of
Customers that would provide the market with information about capacity
rights. However, several groups of participants in the process
submitted proposals for consideration.
\81\Standards For Electronic Bulletin Boards Required Under Part
284 of the Commission's Regulations, Order No. 563, 59 FR 516 (Jan.
5, 1994), III FERC Stats. & Regs. Preambles para. 30,988 (Dec. 23,
1993), order on reh'g, Order No. 563-A, 59 FR 23624 (May 6, 1994),
III FERC Stats. & Regs. Preambles para. 30,994 (May 2, 1994), reh'g
denied, Order No. 563-B, 68 FERC para. 61,002 (1994).
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In the NOPR, the Commission proposed to adopt an electronic Index
of Customers containing the elements put forth by some of the EBB
Working Group participants, as well as some additional elements.
Specifically, the Commission proposed to include for each firm
transportation and storage shipper: shipper's name; contract
identifier; rate schedule; contract start date; contract end date;
contract quantity; receipt points (and associated maximum daily
quantities (MDQs)); delivery points (and associated MDQs); and
conjunctive restrictions, if any; information on capacity held by rate
zones to permit verification of reservation billing determinants; data
elements applicable to storage service to capture the additional detail
required to assess storage capacity; a unique customer identifier to
permit the information in the Index of Customers to be tied to the
electronic data interchange (EDI) information on capacity
release;82 and an authorization code to delineate whether the
information is for Part 284, Subpart B, Part 284, Subpart G, or Part
157 service.
\82\Electronic Data Interchange (EDI) is a means by which
computers exchange information over communication lines using
standardized formats. For example, the capacity release data posted
on a pipeline's electronic bulletin board is also available in
downloadable files that conform to the standards for EDI promulgated
by the American National Standards Institute (ANSI) Accredited
Standards Committee (ASC).
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The Commission identified in the NOPR two functions of the Index of
Customers. First, we stated that the Index would provide the Commission
with the information that it requires for analyzing capacity held on
pipelines (which was previously included in the initial and subsequent
reports). Second, it would provide capacity information to the market,
which would aid the capacity release system by enabling shippers to
locate those holding capacity rights that the shippers may want to
acquire.
However, the Commission recognized in the NOPR that some commenters
in the EBB proceeding objected to the inclusion of receipt and delivery
points in an index of purchasers.83 Therefore, the Commission
instructed commenters to address the relative burden or difficulty of
including the receipt and delivery point information in the proposed
Index of Customers, under the assumption that all of the other
information proposed would be required.
\83\These parties contended that the provision of such
information would be burdensome and might disclose information that
would place firm shippers at a competitive disadvantage with respect
to future gas purchase decisions. See Order No. 636-A, III FERC
Stats. & Regs. Preambles at 31,047-48.
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2. Comments
The Commission received widespread comment on the proposed Index of
Customers. Some commenters fully support the Index of Customers as
proposed.84 Other commenters support an Index of Customers, but
suggest modifications or improvements.85 Many commenters oppose
the adoption of any Index of Customers,86 but either suggest
alternatives, or certain changes, to the proposed Index of Customers,
if the Commission continues to require some type of Index. The main
issues raised by the commenters are whether, and to what extent, the
Commission should require an Index of Customers, given the alleged
commercial sensitivity of the information and burden or cost in
reporting the information, and specifically, whether receipt and
delivery point information should be included in the Index.
\84\Those commenters are: DOE, PMTG, PG&E, Registry, and
Gaslantic.
\85\Those commenters are APGA, NI-Gas, and Texas Gas.
\86\Those commenters are: ANR/CIG, AGA, Consumers Power, INGAA,
El Paso, CNG, Columbia, Columbia Distribution, Panhandle, and KN.
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a. Comments In Support. DOE, PMTG, and PG&E support the Index of
Customers as proposed. They believe that the Index will contain
critical baseline information about the rights of firm capacity holders
necessary for markets to operate efficiently and effectively. PMTG
notes it will be extremely beneficial to the capacity release market,
particularly the receipt and delivery point information. PG&E supports
the proposed Index of Customers as a vehicle for price discovery. It
states that price discovery is critical to competition, and that LDCs
need the opportunity to see the price and terms of the interstate
pipelines' competing capacity on a real-time basis.
Gaslantic and the Registry also support the Index of Customers as
proposed. They argue that absent an Index of Customers, and given the
elimination of the ST reports, the Commission, the market, and other
regulators will have no window to the workings of the short-term firm
transportation market. They maintain that this information is necessary
for the market to ensure that short-term firm transportation
transactions do not receive an unfair preference over released firm
service or similar requests for the same service.
The Registry states that short-term firm transportation, including
gray market transactions and interruptible transportation markets, will
be monitored through cross-correlating information contained in the
proposed Index of Customers, Form Nos. 2, 2A, and 11, as well as the
discount rate reports. The Registry argues that the point level MDQ
information is crucial to the proper formation and functioning of the
secondary market in capacity rights, a more efficient regulatory
process, and a more effective day-to-day operating environment. The
Registry states that data on points rights is essential for determining
path-rights, segmentability, and relative flexibility among shippers,
i.e., quantity of receipt and delivery point rights as compared to
mainline rights. Absent the Index, the Registry argues that no
electronically processible means exist to determine who to contact
other than the pipeline, or what total amount of firm rights might be
available. Without point rights information as a baseline, the Registry
believes that the market is bereft of exactly the data which is needed
to
[[Page 53054]]
identify transaction opportunities and pursue them.
Furthermore, according to Registry, regional, LDC, and third-party-
run exchanges, and market center developers, face nearly insurmountable
information integrity hurdles, which are serious barriers to the entry
of competing market centers and information service providers. Registry
believes these hurdles can be avoided with the availability of capacity
inventory information. Moreover, the Registry notes that one of the
impediments to further integration of the national pipeline network is
the inability of the pipelines to coordinate the simplest cross-
pipeline transactions without extensive verbal and written
communication. With minor changes to the pending EDI Nomination dataset
and the addition of an electronic Index of Customers which includes
points and point rights, this problem largely would be solved.
Gaslantic agrees with Registry on the importance of point
information. Gaslantic explains that pipelines confirm and nominate
released capacity as interruptible capacity, unless scheduled from and
to primary receipt and delivery points. Due to this, Gaslantic states
that released capacity moving between points other than primary points
is no more valuable to the replacement shipper than interruptible
capacity. Similarly, Gaslantic states that the pipeline will not
confirm or schedule capacity nominated from, or to, secondary or
alternate points if there is no operationally available capacity at
intervening interconnects. Gaslantic believes that eliminating these
problems will strengthen the secondary market, and that the key is for
buyers in the secondary market to be able to identify, and seek release
of, specific primary capacity. It states that this is possible only if
the primary capacity holders at each point are identifiable.
Gaslantic states that the Index of Customers information is
available now on various reports filed with the Commission. Gaslantic
argues that with the elimination of these reports (specifically, the
initial and subsequent reports), the short-term firm transportation
sold by a pipeline would not be reported anywhere, since it is not
reported on pipelines' EBBs, through EDI, or in tariff indices of
purchasers. Thus, Gaslantic urges that the Commission adopt a
comprehensive Index of Customers including the point information.
Gaslantic states that it and other members of the EBB Working Group
agreed to the reduction of these reports only on the condition that
they were replaced with a comprehensive electronic Index of Customers
that would contain the essential point rights information now contained
in the paper reports.
b. Comments In Opposition. Certain commenters, however, oppose the
adoption of the proposed Index of Customers. Generally, they argue that
the data the Commission wishes to be disclosed is commercially
sensitive, would be burdensome and costly to provide, and would result
in delays in the implementation of other higher priority electronic
data items. Opposing comments also question the necessity of the data
for efficient operation of the capacity release market.
Consumers Power, ANR/CIG, and Panhandle argue that the information
proposed as a part of the electronic Index of Customers is commercially
sensitive and potentially damaging. According to ANR/CIG, by mandating
open access to pipeline transportation services, and the unbundling of
pipeline services, the Commission has introduced competition into
natural gas markets. They argue that the Commission's regulations
provide the pipelines' competitors with a wealth of information about
the pipelines' business arrangements that these competitors can use to
target pipeline customers and offer them deals that undercut those
offered by the pipeline. ANR/CIG stress that pipelines do not have
equivalent information on these competitors. They assert that the
proposed regulations require the filing of information not previously
required, and require that information be filed publicly, without
adequate protection for non-public disclosure of commercially sensitive
information.
NI-Gas, Consumers Power, and Texas Gas argue that receipt and
delivery point information should not be included in the Index of
Customers because it is commercially sensitive data. NI-Gas states that
knowledge of primary receipt points will allow parties to identify
commercially sensitive information about the sources of a shipper's
supply. Consumers Power argues that the release of such information
would result in competitive detriment to pipelines, and that such
detriment is not outweighed by the Commission's stated reasons for the
Index.
Texas Gas believes that some customers might object to the
inclusion of the information, feeling that the increased accessibility
to this information that posting on the EBB would provide may put them
at a competitive disadvantage with certain suppliers. If the Commission
insists on point data, Texas Gas argues it should be limited to receipt
and delivery points where the shipper has reserved capacity on a
primary basis.
Panhandle, Columbia, Columbia Distribution, AGA, and El Paso object
to the Index of Customers as burdensome. They argue that the
implementation and maintenance of the Index of Customers will require
significant financial commitments both in terms of human resources and
computer costs. AGA points to the significant costs the pipelines would
incur in changing their existing EBB computer screens and formats. AGA
also argues the Commission's policy that data available through EDI
datasets must also be available on the EBB will increase costs. AGA
believes that it is questionable whether the benefits outweigh the
costs.
AGA is further concerned that the industry will be applying its
resources to create an index for a capacity release market that is
still evolving and may change significantly over the next several
years. Columbia concurs, stating it is premature to impose significant
information system burdens on pipelines until the capacity release
program has been reviewed and modified. It adds that many of the
proposed elements are superfluous to the purpose of providing a
downloadable listing of customers with firm capacity that could be
releasable.
El Paso, NI-Gas, and Columbia specifically oppose the provision of
receipt and delivery point data on the basis of the burden it imposes
on pipelines. El Paso argues that providing MDQ by receipt and delivery
point will be burdensome because this information is not always readily
available. NI-Gas asserts that receipt points change far more often
than delivery points, placing a heavier burden on the pipeline.
Columbia quantifies the monthly burden of maintaining the Index of
Customers as approximately 16 hours, if receipt point MDQ, delivery
point MDQ, and conjunctive restrictions are required. If they are not
required, Columbia estimates it will take only four hours per month to
maintain. Thus, Columbia proposes that the Commission require contract
quantity and rate schedule information in the aggregate. It states that
aggregate data will provide the Commission with all necessary
information for analyzing the capacity held on pipelines. Columbia
believes that the choice to disclose the contract specific data
requested in the proposed Index of Customers should rest with the
capacity holder.
AGA also challenges the Commission's assertion the information is
necessary to facilitate the capacity
[[Page 53055]]
release market. AGA argues that such need is questionable since
shippers are already under substantial economic pressure to release
capacity. INGAA, too, argues that requiring pipelines to post
underlying contract information is not only burdensome, but is simply
unnecessary for the industry to carry on capacity trading.
INGAA argues that information on capacity for the market is already
available, and that the Commission can obtain pertinent information on
contracts either by requiring pipelines to file an index in their
tariffs, or via a less extensive electronic index.
Similarly, Panhandle asserts that data requirements in the proposed
rule are currently being provided as part of pipeline capacity release
systems and thus to provide this information on all EBBs as part of the
index would be duplicative in many instances. KN agrees.
Texas Gas and AGA argue that requiring information on receipt and
delivery points to be included in an Index of Customers is unnecessary.
Texas Gas explains that with the implementation of flexible receipt and
delivery point authority under Order No. 636, information concerning
specific receipt and delivery points is not as meaningful or
significant as it was when the regulations requiring the reporting of
transportation transactions were first implemented. Texas Gas states
that many pipelines already maintain updated information on their EBBs
concerning their ``master receipt point lists,'' so that including such
information in the Index of Customers would be unnecessary. El Paso,
too, notes that receipt and delivery information is already available
in the Operationally Available Capacity section of each pipeline's EBB.
AGA states that the Commission did not establish in the NOPR a
relevant need for this information. Like Texas Gas, AGA, also, believes
that the creation of flexible receipt and delivery points for all Part
284 transportation service greatly decreases the need to know ownership
of capacity at a particular point.
Furthermore, adoption of the index of customers, according to the
EBB Working Group, ANR/CIG, AGA, Consumers Power, and INGAA, will
result in delays in implementation of other higher priority electronic
communication data items. ANR/CIG and the EBB Working Group point out
the EBB Working Group has identified eight higher priority natural gas
transactions for development and implementation. INGAA and AGA question
the value of the Index, citing a survey of 55 companies by the EBB
Working Group, showing the index of purchasers as the lowest priority
item in a list of 26 items to be standardized.\87\ INGAA and KN also
note that the EBB Working Group was unable to reach consensus on the
need for an Index of Customers. While supporting the concept of an
Index of Customers, NI-Gas, also, questions whether this item should be
a priority, given the other demands on pipeline programming abilities.
\87\The 55 companies surveyed include pipelines, LDCs,
producers, marketers, end-users, and information services providers.
AGA attaches to its comments the survey results showing this ranking
of standardization priorities.
---------------------------------------------------------------------------
As an alternative to establishing an Index of Customers, AGA and
Consumers Power believe the Commission should update the Index of
Purchasers contained in existing section 154.41. AGA supports an Index
of Purchasers that includes an alphabetical list of all firm
transporters under the pipeline's tariff, the applicable rate
schedules, and the maximum contract quantity (summed by rate schedule,
if appropriate). Consumers Power adds the contract start date and end
date to AGA's list. As is now the case, AGA proposes that the revised
Index of Purchasers be included in the pipelines' tariffs. It states
that since these tariffs are currently available from the Commission in
electronic format, interested parties would be able to obtain the Index
in electronic format directly from the Commission. ANR/CIG maintain
that the data required in the Index of Customers can be provided to the
Commission during a rate case, if necessary.
INGAA argues that instead of imposing a mandatory requirement that
pipelines post contract information on an electronic Index of
Customers, the Commission should instead allow the market to develop
the information it needs on its own. It states that the capacity
release market has experienced rapid and widespread growth, and that a
number of third-party information reporting systems have been
developed, without the existence of a mandatory pipeline electronic
contract reporting system.
Those commenters opposing the proposed Index of Customers suggest
modifications if the Commission adheres to the position an index is
necessary. Some commenters make broad-based suggestions. Panhandle
recommends that the same customer information rules apply to all
participants to the extent practicable, so that one competitor class
will not be afforded an arbitrary advantage over another by the
disclosure of information that is not required to be publicly disclosed
for regulatory purposes. KN suggests the information required on an
electronic Index of Customers be limited to data useful to the
industry.
Other commenters opposed to the Index of Customers make specific
recommendations regarding the content of an Index if one must be
imposed. Columbia asserts the Index should be limited to the basic
information required to identify shippers that have releasable
capacity, the customer name, maximum contract quantity, and rate
schedule. INGAA urges the Commission to reduce the amount of
information to be included in the Index of Customers to the shipper's
name, rate schedule under which service is performed, and the effective
date of the contract. To that, Panhandle would add the execution date
of the contract. However, it opposes public disclosure of the term of
the contract as commercially sensitive. ANR/CIG, on the other hand,
would add the termination date of the contract to the list. El Paso
supports the more limited Index of Customers discussed by the
Commission in Order No. 563-A, and noted supra.
c. Miscellaneous Comments. Both those commenters supporting and
opposing the concept of an index of customers suggest various minor
modifications to the proposed electronic Index of Customers.
To make the index more useful, DOE asserts that each customer's
name should be accompanied by a standardized I.D. number for ease of
identification. Similarly, the Industrials want to be able to correlate
the information reported in Statement G with the information reported
on the Index of Customers. Therefore, they urge the Commission to
require consistent reporting of customer names between Statement G and
the index of customers and the reporting of contract numbers on both.
In addition, DOE suggests that receipt and delivery point information
be accompanied by a standardized identification number (PI-GRID) such
as the location number used in EDI datasets.
While supporting the proposed Index of Customers, APGA suggests two
modifications. APGA wants a pipeline to file an updated copy of the
Index of Customers on paper when it files a general rate case. Further,
APGA would like the Commission to consider making the Index of
Customers available through its Central Issuance Posting System.
Freeport seeks to be excluded from the requirement to establish an
EBB to disseminate the Index of Customers.
[[Page 53056]]
Freeport states that the Commission expressly exempted it from having
to implement an EBB during its restructuring proceedings. It argues
that the reasons supporting that decision continue to apply here.
Freeport asserts this new regulation should not apply to any interstate
pipeline exempted from the Commission's EBB regulations under Order No.
636, or whose throughput during the past twelve months has been zero.
3. Commission Ruling
The proposal to establish an electronic Index of Customers has been
a highly contentious issue throughout both the EBB standardization
proceeding and this rulemaking proceeding. In the NOPR, we proposed an
extensive Index of Customers. In response, proponents of the proposed
Index argue that the data included in the Index of Customers,
particularly the receipt and delivery point data, is crucial for the
efficient operation of the capacity release market; it will ease the
integration of the national pipeline network by simplifying cross-
pipeline transactions; it provides solutions to information integrity
hurdles for exchanges and market center developers; and it will provide
a window on short-term firm transactions. Opponents of the proposed
Index argue just as strenuously that the data will be burdensome and
costly to provide; it is commercially sensitive; it identifies
sensitive data about a shipper's supply; it is duplicative since it is
supplied on the pipeline's EBB; and it may not always be readily
available.
In keeping with the primary goal of this rulemaking proceeding to
eliminate unnecessary regulations, and in light of the numerous
complaints in the comments that much of the information is commercially
sensitive, and that its disclosure would be harmful and burdensome, the
Commission has reassessed its regulatory need for the information
included in the proposed Index of Customers. We have attempted to
distinguish between data that is absolutely necessary for the
Commission's regulation of the industry, and data that may not be
necessary for review purposes. The amount and type of information
included in the proposed Index extends beyond that which the Commission
needs to receive from all pipelines on a regular basis to regulate the
natural gas industry today. For the Commission's purposes, only a list
of a pipeline's firm shippers, the rate schedule numbers for the
services for which the shippers are contracting, the effective and
expiration dates of the contracts, and maximum daily contract
quantities are necessary.
Several commenters have argued that the contract expiration date
and contract quantity should not be included in the Index. We believe
that this information is necessary for our regulatory purposes. The
information included in the Index being adopted represents fundamental
data about the natural gas industry--namely, how much of the pipeline's
capacity shippers have under firm contract. This information is basic
to the Commission's understanding of events taking place in the
industry. With this information, the Commission will remain apprised
of, for example, trends in the industry, the willingness of shippers to
hold firm capacity, the average length of time capacity remains under
contract, and the proportion of capacity rolling over under evergreen
provisions. Pipelines are beginning to deal with complex issues related
to shippers' contracts coming up for renewal in the post-restructuring
period.\88\ The lack of easily accessible data regarding customers'
contract levels and contract terms could hamper the Commission's
ability to assess the impact of this phenomenon on the industry. The
Index will provide key data for this purpose.
\88\For example, Transwestern Pipeline Co. recently filed a
settlement in Docket No. RP95-271-000 to deal with the turn back of
significant amounts of capacity by a key customer.
---------------------------------------------------------------------------
Those commenters in favor of the proposed Index of Customers have
not persuaded us that the Commission should require the pipelines to
maintain a comprehensive list of capacity rights by receipt and
delivery points to aid the secondary capacity market, or to assist
third-party-run exchanges and market center developers. Their comments
do not make clear what practical effect providing the proposed
additional information would have on the secondary market. For example,
there has been no evidence presented that the inefficiencies in the
capacity release market would be removed if detailed information on the
location of capacity rights were made public. However, AGA's comments
stating that the capacity holders have incentives to market idle
capacity are persuasive. Moreover, the Commission can require more
detailed information on capacity rights to be produced in particular
proceedings, as necessary.
The Registry supports the proposed Index as a window on short-term
firm transportation. While the Index adopted in this rule will provide
information on short-term firm transportation, not all short-term firm
contracts entered into on the pipeline's system will be reported, due
to the decrease in the frequency of filing. However, the Index adopted
will provide a snapshot profile of the pipeline's contracts on the
first day of each quarter. This will enable the industry to follow
trends in the proportion of capacity held under short-term firm
contracts versus the proportion of capacity held under longer-term
contracts.
With respect to cross-pipeline issues, the industry is currently
grappling with the best way to resolve these issues. Therefore, the
Commission believes that it is premature to adopt a reporting standard
to aid in resolution of such issues. Rather, the industry should be
afforded time to attempt to reach a resolution.
Therefore, while the Commission is retaining the requirement that
pipelines file an electronic Index of Customers, the Commission is
adopting only a limited Index of Customers. The Index will contain for
all firm customers under contract as of the first day of the calendar
quarter,89 the full legal name of the shipper, the rate schedule
number for which service is contracted, the contract effective and
expiration dates, and the contract quantities. The Commission is
requiring the full legal name of the customer to be reported to help to
ensure that the same customer name is reported regardless of the filing
or form in which it is reported. We are also requiring that the rate
schedule number be reported in the same format as it appears in other
reports and filings with the Commission.
\89\It is not necessary to require the posting of interruptible
contracts in the Index of Customers.
---------------------------------------------------------------------------
The Index must be posted on the pipeline's EBB, and filed
electronically, once each calendar quarter. That is, on the first of
each calendar quarter, the Index must be restated and reposted on the
EBB to include all firm contracts in effect on that date, and filed
with the Commission in electronic form. A paper copy of the Index is
not required to be filed. When a pipeline has implemented the
electronic Index of Customers, its obligation to provide for an Index
of Customers in its tariff will cease. In addition, where a pipeline
has received a waiver from establishing an EBB, it does not have to
establish an EBB in order to implement an Index of Customers. In that
case, pipelines, such as Freeport, must comply with the reporting
requirements of section 154.111 instead.
Several commenters argue for the information included in the Index
to be filed in a rate case, or as part of the tariff, instead of in a
separate Index of
[[Page 53057]]
Customers. Filing the data with the rate case would not be timely
enough for the Commission's review purposes. It is true that filing the
data as part of the tariff, either by updating section 154.41 or
establishing a new index, would make it publicly available in an
electronic format. However, in the past, the Commission has had
difficulty extracting the Index of Customer data from the tariff for
use in spreadsheets and databases due to the inconsistent way the data
is presented, even from page to page within a single tariff. To make
the data most useful, we are requiring that it be filed in a consistent
format by all pipelines. The index will be maintained on each
pipeline's EBB in a delimited ASCII format in a file which can be
downloaded from the EBB.
Similarly, APGA proposed that the Commission require pipelines to
file an updated copy of the Index of Customers on paper when it files a
general rate case. We will not adopt APGA's suggestion. The Index will
now be updated quarterly, and it should be fairly simple for a paper
copy of the index to be generated from the electronic data. We will,
however, adopt APGA's proposal to make the Index of Customers available
through the Commission's bulletin board system.
A number of commenters express concern about the delay that
providing an electronic Index of Customers may cause in implementing
electronic data interchange (EDI) services which the industry has
identified as being higher priority. Others are concerned with the
costs involved. Still others, DOE for instance, support using EDI to
transmit the Index. Since the Commission is proposing a substantial
reduction in the data included in the Index of Customers, transmittal
through EDI will not be necessary. As stated, the index will be
available on the pipeline's EBB. Therefore, implementation of the index
should cause no delay in the implementation of EDI services.
As discussed in the electronic format section of this rule, Section
IX, the industry will be working with the Commission staff to develop
the data sets and other procedures necessary to provide for downloading
of the Index of Customers on the EBB. Instructions for reporting the
data elements listed in the regulations will need to be finalized. For
example, appropriate file names and the presentation of dates still
need to be determined.
Thus, the final implementation of the Index of Customers by the
industry and the Commission Staff will not occur until some time after
the effective date of this rule. In the NOPR, the Commission proposed
to require the pipelines to initially comply with the Index of
Customers requirement within 180 days of the effective date of the
final rule, in order to allow ample time for the industry and Staff to
conclude their conferences, and for the pipelines to implement the
resulting electronic elements of the Index of Customers. However, we
will remove the requirement that the index be completed within 180 days
of the effective date of this rule. The Commission would like the data
to be provided as quickly as possible, but recognizes the competing
demands on the pipelines' resources. We will require the pipelines to
work out a flexible implementation schedule with staff, and to report
back to the Commission for approval.
In the intervening period between the effective date of the rule
and the pipelines' implementation of the electronic Index of Customers
under sections 284.106 and 284.223, pipelines providing transportation
service under sections 284.106 or 284.223 will be required to comply
with the Index of Customer requirements applicable to transportation
and sales under Part 157, as set forth in sections 154.111(b) and (c).
F. Removal of Obsolete Transitional Requirements
Several sections in Part 284 were established by either Order No.
436 or Order No. 636 as interim measures to implement those orders, or
to bridge the transition between the two orders. Some of these
provisions contained action deadlines that have long since passed. The
Commission is removing the following sections because they have become
outdated due to subsequent events, and the current state of the
regulatory environment.
Section 284.7(b) provides for interim rates for part 284
transactions to be charged until new transportation rates are filed
under section 284.7, which had to have been filed by July 1, 1986. This
section has become obsolete, and therefore is no longer necessary.
Section 284.10 provides an interim program for bundled sales
customers to convert to firm transportation services. Since Order No.
636 has unbundled sales service, so that sales and transportation
services are now separate services, there is no need for customers to
convert from one to the other. This section is no longer applicable to
the current regulatory framework.
Section 284.11 sets forth environmental compliance requirements for
any activity involving the construction of, or abandonment with removal
of, certain facilities. Paragraph (d)(1) of section 284.11 requires the
filing of a one-time report, by December 9, 1992, for any such activity
costing more than $6.2 million that was commenced between July 14, 1992
and November 9, 1992. This provision is now meaningless because it
required a one-time report, and the date for filing the report has
passed. Thus, paragraph (d)(1) is deleted from the section.
INGAA recommends the Commission change the filing deadline for the
capacity report required under section 284.12 to May 1 to avoid
conflict with financial reports due in April. Freeport requests
modification of this provision in order not to require a report for any
year whenever there has been no change from the last such report filed.
The Commission will not change the deadline for filing the capacity
report under section 284.12. The arguments made by INGAA for moving the
deadline to May 1 are not persuasive. The filing date for the financial
reports and the report due under section 284.12 have been in close
proximity for some time. The respondents have been able to meet the
April filing deadlines in the past, and there is no reason to assume
they cannot meet the filing deadlines in the future.
Nor will the Commission modify section 284.12 so that no capacity
report is required when the capacity report remains the same from the
last report filed. Rather than revise our regulations to provide for a
situation that is likely to be the exception and not the rule,
pipelines may, as always, seek waivers from this provision in these
instances.
INGAA and Texas Gas recommend the Commission remove the
recordkeeping requirement in section 284.13. This section requires that
within 30 days after commencing any subpart B or G transportation
arrangement, the pipeline keep a log that includes the date of the
request, the name of the person requesting transportation, and the
volume of gas to be transported. INGAA and Texas Gas state that this
information was based on the first-come, first-served capacity
allocation procedure begun under Order No. 436, and is no longer
relevant for today's capacity allocation method based on price. They
further state that pipelines that use methods other than price to
allocate capacity must comply with the capacity allocation requirements
of Order No. 566. The Commission agrees with INGAA and Texas Gas. This
information was primarily used to establish queues for the first-come,
first-served allocation scheme under Order No. 436, and that allocation
procedure was changed by Order Nos. 636 and 566. In addition, this
recordkeeping
[[Page 53058]]
requirement largely duplicates the log keeping requirement for
allocating capacity contained in section 250.16(c). Therefore, section
284.13 is eliminated from the regulations.
Section 284.14--Provisions governing pipeline restructuring--was
designed to implement the restructuring of pipelines' services under
Order No. 636, and contains, among other things, the requirements for
the compliance filings pipelines were required to make, and for the
associated restructuring proceedings. The restructuring process is now
complete; therefore this section is no longer necessary. Any pipeline
who proposes to offer transportation service under subpart B or G of
part 284 in the future will simply file to comply with the requirements
of this part and Order No. 636.
Sections 284.105 and 284.125, applicable to section 311 interstate
and intrastate transportation, respectively, provided that
transportation arrangements existing prior to Order No. 436 could
continue in effect, under the same terms and conditions existing prior
to Order No. 436 (with some exception), after the issuance of Order No.
436, for an interim period that would end, at the latest, on October 9,
1987. Thus, these transitional provisions only had effect for an
interim period that is now over. Accordingly, we are eliminating
sections 284.105 and 284.125.
Section 284.122 governs transportation by intrastate pipelines
under Section 311(a)(2) of the NGPA. The Commission is deleting
paragraph (e) of section 284.122, which sets a January 31, 1992
expiration date for the authorization provided under that section for
certain transportation. This transitional provision is no longer
required. Similarly, section 284.123, governing the rates and charges
for this section 311 transportation service, contains in subparagraph
(e)(2) a transitional filing requirement deadline of February 1, 1985
for certain pre-existing transportation arrangements; thus, the
Commission will remove section 284.123(e)(2).
The Commission will also remove sections 284.223(e) (Transitional
rule for transportation arrangements) and 284.223(f) (governing the
conversion of transportation service under NGPA section 311 to NGA
section 7(c) blanket transportation service). Section 284.223
authorizes an interstate pipeline to transport gas under a section 7
blanket certificate of public convenience and necessity for any shipper
for any end use by that shipper or any other person. Section 284.223(e)
was established as a transitional provision to permit transportation
arrangements authorized under section 157.209(a)(1), which commenced
before October 9, 1985, to qualify as transportation under section
284.223. Section 157.209(a)(1) permitted section 7 certificate holders
under section 157.201 to transport natural gas only on behalf of a
high-priority end user for a high-priority end use. Section
157.209(a)(1) was replaced by section 284.223, and was removed from the
regulations effective November 18, 1985.90 Accordingly, the
transitional rule contained section 284.223(e) applicable to
transportation under section 157.209 is obsolete, and no longer
necessary. Similarly, Section 284.223(f) is an interim measure that was
designed to implement the addition of blanket transportation services.
This section requires that all conversions be made prior to November 1,
1990. Consequently, sections 284.223(f) is also obsolete, and no longer
necessary.
\90\See 50 FR 42408 (October 18, 1995).
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Section 284.227 grants a certificate for intrastate pipelines in
the coastal states for the transportation of federal offshore gas for
use in that state. Paragraph (d) requires the intrastate pipeline
converting from section 311 transportation service to service under
this section to file a conversion report. This conversion report was a
transitional requirement, and references the initial and subsequent
reports that are being deleted by this rule. Accordingly, we are
eliminating section 284.227(d).
Section 284.402 of Subpart L, setting forth the authorization for
blanket marketing certificates, provides in paragraph (c)(1) that the
authorization for an ``affiliated marketer'' with respect to
transactions involving affiliated pipelines becomes effective either
when the affiliated pipeline receives its blanket sales certificate
under Subpart J, a transportation-only affiliated pipeline's Order No.
636 compliance filing is approved, or when the Commission terminates
the affiliated pipeline's RS proceeding. The Commission will delete the
latter two conditions, since those occurrences have passed.
G. Other Revisions
The Commission is deleting most of Subpart D, governing certain
sales under section 311 of the NGPA by intrastate pipelines. In Order
No. 547,91 the Commission granted any person who is not an
interstate pipeline a blanket certificate of public convenience and
necessity pursuant to section 7 of the Natural Gas Act, authorizing the
certificate holder to make sales for resale at negotiated rates in
interstate commerce of any category of gas that is subject to the
Commission's Natural Gas Act jurisdiction. The certificate of limited
jurisdiction does not subject the certificate holder to any other
regulation under the Natural Gas Act by virtue of transactions under
the certificate. Although the blanket certificate eliminates the need
for Subpart D, the Commission will retain the basic authorization and
rate provisions under Subpart D in sections 284.141, 284.142, and
284.144 for those persons who may wish to make sales under the NGPA
instead of the blanket certificate under the Natural Gas Act. However,
in recognition that an intrastate pipeline can also sell natural gas in
an unbundled transaction under the blanket certificate, at negotiated
rates, the Commission will retain a simplified version of section
284.144 governing rates and charges as part of the authorization
provision set forth in section 284.142. The new rate rule within
section 284.142, simplifies the current maximum sales rate rule to
permit the gas commodity price negotiated in the contract, plus a fair
and equitable transportation rate.
\91\61 FERC para.61,281 (1992).
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The Commission is deleting Subpart E in its entirety, governing the
assignment by any intrastate pipeline to any interstate pipeline or
local distribution company of its contractual right to receive surplus
natural gas at any first sale, without prior Commission approval. The
Natural Gas Wellhead Decontrol Act of 1989 amended the definition of
``surplus natural gas'' in section 312 of the NGPA to mean ``any
natural gas.'' Moreover, the only filings under Subpart E were made in
1979. Therefore, Subpart E is no longer necessary.
The Commission is removing section 284.222, regarding
transportation by interstate pipelines on behalf of other interstate
pipelines. Since the Commission deleted the prior notice requirement in
Order No. 537,92 which applied to transportation by interstate
pipelines on behalf of shippers other than interstate pipelines under
section 284.223, but did not apply to transactions under section
284.222, there is no longer any reason to distinguish between
transportation under sections 284.222 and 284.223. Thus, the Commission
will delete section 284.222, and apply section 284.223 to
transportation by interstate
[[Page 53059]]
pipelines on behalf of other interstate pipelines, as well as
transportation by interstate pipelines on behalf of non-interstate
pipeline shippers. Therefore, the Commission is also modifying the
title of section 284.223 to read ``Transportation by interstate
pipelines on behalf of shippers.''
\92\Revisions to Regulations Governing Transportation under
Section 311 of the Natural Gas Policy Act of 1978 and Blanket
Transportation Certificates, 56 FERC para.61,415 (1991).
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The Commission is removing sections 284.225 and 284.226 concerning
the transportation of gas released under the good faith negotiation
procedures. Order No. 567,93 issued July 28, 1994, in Docket No.
RM94-18-000, removed the good faith negotiation procedures under
Section 270.201 as a result of the repeal of maximum lawful ceiling
prices under the NGPA.
\93\68 FERC para.61,135 (1994).
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Section 284.266 concerns the rates and charges for emergency
transportation and sales service by interstate pipelines. Paragraph (b)
of section 284.266 governs the determination of the emergency sales
rate, and refers to the methodology a pipeline uses in designing its
sales rates and its current purchased gas costs. This paragraph is no
longer relevant in light of the changes brought about by Order No. 636.
Order No. 636 unbundled transportation and sales services. All
pipelines wishing to make unbundled sales, and holding a blanket
certificate under subparts B or G of Part 284, were granted a blanket
certificate authorizing firm and interruptible sales service with pre-
granted abandonment.94 The rate for unbundled sales service is
determined by the market.95 Similarly, the discussion in paragraph
(c) of section 284.266, regarding the treatment of revenues, harks back
to the time when transportation was the exception rather than the rule.
Pipelines primarily sold natural gas bundled with transportation,
calculating the price for the natural gas in their purchased gas
adjustments. Since pipelines now offer transportation and sales
services separately, with sales service provided at market-based
prices, the crediting mechanism described in paragraph (c) has become
an anachronism. Therefore, sections 284.266(b) and (c) are removed.
\94\Order No. 636 at 30,437-38.
\95\Id.
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In addition, the Commission is making a number of more minor,
miscellaneous changes, such as deleting references to dates that have
passed, updating the Commission's address, and changing provisions to
conform with other changes that are being made in this rule. These
modifications are set forth below.
Section 284.2(b), concerning interest on refunds, contains a
reference to section 154.102(c) for the interest formula. This
reference must be changed to indicate the new provision in Part 154
where the interest formula now appears (section 154.501(d)).
Section 284.4, specifying that all reports in Part 284 must
indicate quantities of gas in MMBtu's, refers to Sec. 270.102, which
has been removed, for the definition of MMBtu. The definition of MMBtu
previously found at Sec. 270.102 must be incorporated in this section.
The Commission is still requiring the reporting of quantities in
MMBtu's, and the definition has not been changed. Therefore, this
change does not constitute a modification from past requirements.
The Commission is making a grammatical revision in section
284.8(b)(4)(iii).
In section 284.102(e), governing the certifications interstate
pipelines must obtain from shippers to be able to transport gas on
behalf of an intrastate pipeline or local distribution company under
section 311, the Commission is deleting reference to a January 3, 1992
deadline for tariff revisions establishing the certification
requirement.
The Commission is modifying paragraph (b)(1) of section 284.221,
setting forth the general rules regarding the transportation by
interstate pipelines on behalf of others under section 7(c) blanket
certificates, to delete reference to an October 31, 1989 date no longer
relevant, and a fee no longer collected.
In sections 284.6(b) and 284.8(b)(5)(i), we are deleting reference
to the specific street addresses of the Commission, many of which are
former addresses, and replacing them with only the particular internal
office name, the Commission's name, and ``Washington, D.C. 20426.''
In many provisions, the Commission is deleting reference to
sections that have been eliminated by this rule, or by other prior
rules. For example, in section 284.221(f)(2), we are eliminating
reference to section 284.222, which is removed by this rule. Other
conforming changes are set forth below.
In light of the proposed elimination of Subpart E, the Commission
is removing all references in section 284.224, governing certain
transportation, sales and assignments by local distribution companies,
to Subpart E, as well as to the word ``assignments'' in the section
provisions and in the section heading. The Commission is retaining the
blanket certificate and rate election procedures in section 284.224
that allow local distribution companies served by an interstate
pipeline or Hinshaw pipeline to engage in sales and transportation of
natural gas to the same extent as intrastate pipelines are authorized
to engage in such activities under subparts C and D. The Commission is
also removing the reference to assignment in section 284.3, which sets
forth the NGA jurisdiction.
Section 284.224(e)(5)(ii) requires the blanket certificate holder
to file a copy of all contracts as a part of the initial full report
under sections 284.126 and 284.148. Since the Commission is deleting in
subparts C and D the requirement to file initial full reports, the
Commission is also deleting section 284.224(e)(5)(ii).
Furthermore, since the Commission is deleting the initial reports
required in subparts C and D, the extension report in subpart D, and
entire subpart E, which also required an initial report, the Commission
is deleting section 381.404, which establishes the fee for initial or
extension reports and refers to the removed sections.
Section 284.269, concerning intrastate pipeline and LDC emergency
sales rates, refers to removed section 284.144 for the calculation of
the emergency sales rates. We are revising this section to refer,
instead, to section 284.142.
As a conforming change to our action in eliminating transitional
provision 284.14, the Commission is deleting references to sections
284.14 in, and making modifications to, the following sections:
284.221(d), 284.284(b), 284.286(e), 284.287.
Section 2.104(a), governing the procedures for the passthrough of
pipeline take-or-pay buyout and buydown costs, refers to the
grandfather provisions in sections 284.105 and 284.223. We are
eliminating the reference to these sections, since we have deleted
section 284.105 and the transitional provisions in paragraphs (e) and
(f) of section 284.223.
In Part 381, governing fees, section 381.404, concerning the fee
for initial or extension reports for Title III transactions, references
reports in sections 284.148(e), 284.165(d), and 284.126 that have been
deleted. Therefore, section 381.404 is deleted, also.
The Commission is revising section 385.2011, concerning electronic
filing requirements, to update the reference to part 154 and to the
Commission's address, and add the discount rate report as an electronic
filing requirement.
VIII. Part 157
In keeping with the goals of the NOPR, El Paso suggests that the
Drilling Gas Report required by section 157.53(b) of the Commission's
regulations can be
[[Page 53060]]
eliminated, especially now that pipelines are primarily transporters of
natural gas. Section 157.53 exempts from the certificate requirements
of section 7(c) of the NGA, the construction and operation of
facilities necessary to render direct natural gas service for use in
the drilling of gas or oil wells, or for use in the testing and purging
of new natural gas pipeline facilities, as long as a drilling gas
report describing such operations is filed annually.
The Commission agrees with El Paso, in part. Facilities necessary
to render direct natural gas service for use in the drilling of gas or
oil wells may be constructed and operated under other procedures short
of a full certificate filing. For example, since pipelines generally
have a reduced merchant role, many of the facilities of this type will
be built on behalf of natural gas producers. These facilities would be
eligible for a blanket certificate under subpart F of section 157.
References to these transactions will be removed from this section. We
will retain this section for facilities built to purge and test new
natural gas pipeline facilities since these facilities will otherwise
generally require full certificate proceedings.
IX. Electronic Filing Requirements
A. Introduction
Currently, the Commission requires pipelines to file the Form No.
2, Form No. 2-A, and Form No. 11 electronically. The pipelines file the
electronic data on the following media: diskette, 9-track magnetic
tape, and 18-track cartridge. The tapes and cartridges are used with
the mainframe computer. However, the majority of pipelines file their
data on diskette. The present filing requirements call for the data to
be submitted in an ASCII flat file format.96 A flat file is
composed of data arranged in records or rows with no delimiters. Each
data item is assigned a position in the row to distinguish it from
other data in the row. This data structure was adopted primarily
because it was well-suited for use on mainframe computers. In the NOPR,
the Commission expressed the desire to adopt filing requirements which
are better suited for use on a personal computer. In this rule, the
Commission is requiring that the Form Nos. 2, 2A, 11, and the discount
rate reports be filed both on paper and electronically. The Index of
Customers will be posted on the pipelines' EBB's, and filed
electronically only; no paper copy of the Index of Customers will be
required.
\96\ASCII, or ``American Standard Code for Information
Interchange,'' conveys only letters, punctuation, and certain
symbols. It does not convey how the document should be formatted or
what fonts to use. A delimited ASCII file is created by keypunching
a series of symbols using commas, tab, or some other symbol to
designate the space at the end of a word or number (thus, ``tab
delimited,'' ``comma delimited,'' etc.)
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In the NOPR, the Commission acknowledged that the changes to the
regulations and forms that it was proposing in that NOPR, and in the
companion NOPR in Docket No. RM95-3-000, would necessitate
modifications to the electronic formats for the affected filings and
forms. Thus, to ensure the widest possible input, the Commission
directed its staff to convene a technical conference to obtain the
participation of the industry and other users of the filed information
in designing the electronic filing requirements.
On April 4, 1995, the Commission staff held the technical
conference to address the electronic filing requirements associated
with the proposed rules. Many issues were discussed at the conference,
such as whether to require the data to be saved in files in a standard
format, such as ASCII, or to allow pipelines to submit electronic data
in the format of the applications software they employ;97 whether
the appropriate method for transmitting data to the Commission is via
diskette, or telecommunications; whether the Commission or the
pipelines should disseminate the electronic data, and how dissemination
should be accomplished (i.e., on diskette, or via the EBB); and the
standardization of data elements.
\97\Applications software means proprietary software, such as
Lotus, Quattro Pro, Excel, or WordPerfect.
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As a result of oral comments made at the conference, and written
comments submitted in this rulemaking, the Commission is able to make a
number of decisions related to the electronic filing requirements in
this rule. However, other issues still will need to be resolved jointly
with the industry. Therefore, the Commission is directing staff to
convene a further technical conference, and to work with the industry,
as needed, to resolve the outstanding electronic filing issues in both
this rule and the Docket No. RM95-3-000 rule. This conference is to be
held as soon as possible after the issuance of these rules. The various
electronic filing issues raised at the conference, and the comments on
those issues, are addressed below.
B. Format For Electronic Filings
Commenters generally support a change to the current means of
filing forms electronically. The Registry identifies three main forms
in which data can be delivered electronically, and which allow for
consistent presentation and unambiguous cross-correlation:
Applications software, such as Lotus, which are best for
financial, performance, and other one-to-one reporting subject areas;
Comma-delimited ASCII formats, which allow for all PC-
based spreadsheet and database software to import the data set forth in
this format; and
Relational data structures such as electronic data
interchange (EDI),98 which are best for one-to-many relationships
and reporting areas.
\98\Electronic Data Interchange (EDI) is a means by which
computers exchange information over communication lines using
standardized formats. For example, the capacity release data posted
on a pipeline's electronic bulletin board is also available in
downloadable files that conform to the standards for EDI promulgated
by the American National Standards Institute (ANSI) Accredited
Standards Committee (ASC).
---------------------------------------------------------------------------
INGAA notes that at the April 4 conference on electronic filings,
pipelines recommended that the electronic filing format for most
reports in this rulemaking should be platform independent (in other
words, able to be used with any hardware), with delimited ASCII formats
for numeric files, and Rich Text Format (RTF) for text. Williston Basin
and Panhandle support this preference, voiced at the conference, for
tab-delimited or comma-delimited ASCII files for electronic filing of
numeric data fields.
Williston Basin believes that the Commission should eliminate the
current flat, non-delimited ASCII submission format, because it is a
time consuming and inefficient process. Williston Basin states that
tab-delimited formats for numeric submissions would be more efficient,
and that these formats are readily producible from all of the current
generations of personal computer operating systems and applications
software packages.99
\99\Williston Basin is not opposed to submitting electronic data
in the application software it uses, provided that numerical data
not include formulas and links, and the native application format(s)
supported by the Commission is producible from its application
software.
---------------------------------------------------------------------------
Panhandle asserts that the number of software applications and
computer platforms used by applicants, regulatory agencies, and
intervenors, and the various releases of such applications used by the
participants, calls for the adoption of a ``common denominator''
approach for data transfer, such as delimited ASCII, rather than a
particular software application or applications. Panhandle adds that
delimited ASCII formats permit columnar data fields to
[[Page 53061]]
be imported and exported into, and out of, most off-the-shelf software.
For text only files, Panhandle and Williston Basin support the RTF
recommendation, which permits word files to contain text enhancements,
such as underscoring. The Registry adds that text files, which can be
read by word processors, are very useful for scanning text, such as
direct testimony, tariffs, and descriptions. RTF can be read by AMI-PRO
by Lotus, Word by Microsoft, and Wordperfect by Novell. The format
retains most of the bold, indentation, tabbing, and paging formats,
which can be imported into any of the three applications with a minimum
effort for conversion and reformatting.
A related issue to electronic filing formats is whether the
Commission should develop form-fill software to assist the pipelines to
prepare the filings. In the NOPR, the Commission noted its intention to
use user-friendly form-fill software. Williston Basin responded in
support of a form-fill software approach to preparation of the Form No.
2, if the software package is appropriately designed and tested prior
to implementation. A critical requirement for Williston Basin would be
data import capabilities allowing the form-fill software to receive
data from its software packages.
The companion rule in Docket No. RM95-3-000 adopts the use of tab-
delimited ASCII for most numeric data, with limited use of spreadsheets
for the rate case data. The Commission is adopting a tab-delimited
ASCII format for the numeric data submitted electronically in this
rulemaking, as well. The Commission is adopting this standard in light
of the substantial support it enjoys.
The Commission is not adopting in this rule a format for the text
data that is filed electronically. RTF for text data enjoys substantial
support. The nature of RTF is discussed at greater length in the
companion rulemaking. However, the Commission has certain concerns that
we wish to have addressed before adopting RTF for text. Thus, the
companion rule directs staff to establish a conference to explore
further the efficacy of RTF for text data. At the conference, the
participants should address alternatives to RTF, if any, and the
concerns that: (1) the data be error-free when translated; (2)
translation be available in the most popular word processing programs;
and (3) RTF text be usable in databases.
In light of the industry's support for independence from a
particular platform or software, the Commission will not prepare form-
fill software for the use of the industry. The data layouts will be
determined and edit specifications will be provided as a result of the
conference; however, no software for form-fill, edit-checking, or
printing will be provided. The industry is free to develop whatever
software best meets its needs, and the filing requirements set forth by
the Commission.
C. Data Requirements
The Registry recommends that the collection of information across
various reports and filings encourage correlation and comparison. In
particular, the Registry notes that:
Time periods should be consistent and cross-comparable;
Units of measurement should be consistent, and only one
energy and volume unit should be employed;
Geographic zones (i.e., county and states) should be
equated to economic (i.e., rate) zones;
Services (firm, interruptible, etc.) should be equated to
rate schedules; and
Identifiers such as DUNS numbers of customers/contract
parties should be consistent.
The Registry also suggests that respondents should be required to
adhere to the following standards and practices:
Standard naming conventions, page numbering, and ordering
of fields/contents of spreadsheets;
Provision of both values-only, and formulas and values,
versions of data files; and
Provision of both an edit-enabled and a password locked,
edit-protected version of each of the values-only and formulas-only
files; there should be no hidden cells.100
\100\The Registry also makes certain recommendations for the
electronic filing requirements for rate case data. The Commission is
addressing this issue in the companion rule in Docket No. RM95-3-
000.
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The Commission wishes to encourage consistent reporting among
different electronic forms and filings. Where possible, the conference
participants should come to agreement on standards for reporting common
data elements, such as dates. The participants must also explore at the
conference what measures would be appropriate for establishing the
security of the data, such as locking the file with a password, as
suggested by Registry. Further, the participants must discuss certain
other general issues, such as those raised by Registry, i.e., file
naming conventions, page numbering, ordering of fields/contents,
appropriate diskette size and labelling of the diskettes. In addition,
other issues common to electronic filing need to be addressed, such as,
treatment of footnotes, format for dates, and what the industry
considers to be text suitable for RTF. Since we are adopting a tab-
delimited ASCII format for numeric files, the Commission is not
requiring any of the reports subject to this final rule to be filed in
a spreadsheet form. Therefore, the suggestion by Registry that a
values-only version and a values and formulas version of the
spreadsheet data be submitted is not an issue.
The Registry recommends adding a number of data elements to the
electronic version of the forms and/or filings. The Commission is
requiring that the electronic filing be a faithful representation of
the data requirements set forth in the form or filing. The electronic
filing requirements will not be expanded to include data not specified
in the paper version of the form or enumerated in the regulations. For
example, where the rate schedule number is reported, it should not be
construed as also requiring the type of service to be reported, unless
specifically stated in the form or regulations.
D. Submission and Dissemination of Electronic Data
With respect to the submission, or filing, of the electronic data,
INGAA states that, at a minimum, pipelines would prefer to file on a
diskette, but are willing to investigate communication of data through
CD-ROM or telecommunications. INGAA views EDI applications for certain
reports as an option on a voluntary basis, where it can be shown to be
cost effective.
In contrast, Williston Basin supports the use of telecommunications
medium for the submission of electronically filed data. While Williston
Basin prefers telecommunications submission, if physical formats are
used for submission, Williston Basin supports CD-ROM as an alternative
to diskettes.
Current electronic filings are commonly submitted on diskette, as
noted above. Filing on diskette continues to enjoy substantial support
in the comments. Thus, the standard means of submitting data to the
Commission will be by diskette. However, the Commission will also
permit submission on CD-ROM.101
\101\Technical specifications for CD-ROM submission will appear
in the electronic filing instructions for each individual form or
filing.
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The Commission does not currently permit the filing of electronic
data through telecommunications. The Commission is not yet prepared to
accept data through telecommunications. Before adopting
[[Page 53062]]
filing by telecommunications, the Commission would need to put the
proper hardware and software in place, and work out other issues. For
example, section 385.2005 requires filings with the Commission to be
signed. Signatures are difficult to reproduce electronically.102
Such issues can be addressed at the conference to be convened by staff.
Therefore, the Commission will not adopt submission by
telecommunications until all of the issues are resolved.
\102\In the past, the Commission received purchased gas
adjustment (PGA) schedules in electronic form only. The diskette,
tape, or tape cartridge containing the PGA schedules was accompanied
by a letter of transmittal. The signature on the letter of
transmittal met the requirements of section 385.2005.
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With respect to the dissemination of the electronically filed data,
INGAA and Williston Basin support the goal of increased use of
electronic dissemination of reported data by the Commission, and the
elimination of hardcopy dissemination whenever practical. Panhandle,
too, supports the industry preference that the Commission be the
primary disseminator of filed information. However, Williston Basin and
INGAA urge the Commission to put procedures in place to ensure the
integrity of the electronic filing, and the security of any
confidential data.
AGD suggests that the Commission require pipelines to post their
Form No. 2 filings, (including backup information) on their EBBs. The
Registry suggests that the Form No. 2 data be made available to the
public in hardcopy printout of the electronic version, and in
compressed files on 3.5'' 1.44 MB disks, in edit-protected mode in the
comma-delimited format in which it was filed. It states that such Form
No. 2 data should be available for the price of reproduction, plus a
handling charge. The Registry also suggests that the diskette should
contain the record layout and description, so that users can import the
company-supplied data, and know how the fields correlate to the Form
No. 2 data with which they are familiar. In addition, the Registry
recommends that the uncompressed file names should appear on the label
or sleeve wrapper of the diskette.
The Registry suggests that the market monitoring information, such
as the Index of Customers and the discount rate reports, be made
available to the public in the following forms:
Via EDI formatted downloads from the pipeline's EBB or
VAN, for which the pipeline has agreed to pay its portion of the
charges associated with using such means of request and delivery;
Via hard copy printout of a translated EDI file available
from the Commission; and
Via EDI formatted files on 3.5'' 1.44 MB disks in write-
protected mode available from the Commission, with a batch file which
prompts the user for sender and receiver IDs for the IS and GS levels
which, once supplied, enables the user to translate the file with their
EDI translator.
Conversely, Williston Basin states that although it may support EDI
for the transmission of certain frequent filings, it believes EDI would
not be a cost-effective option based on the frequency and nature of the
data being submitted.
It is the Commission's intention to disseminate all electronically
filed data to the extent the file size is practical for downloading.
Dissemination would be accomplished through the Commission's Gas
Pipeline Data bulletin board system. Files on the bulletin board system
are currently compressed for faster downloading. The data layouts for
each electronic filing are currently made available through this
system. This practice will continue. Since the Form No. 2 will be
available on the Commission's bulletin board for all companies, we will
not require the pipelines to keep a copy of Form No. 2 on the
pipeline's own bulletin board.
Given the reduction in the number of data elements to be submitted
in the Index of Customers and the discount rate reports, the Commission
does not believe EDI is necessary for transmission of the data.
Further, a delimited ASCII file would be easier to manipulate for many
members of the public using the Commission's bulletin board. Therefore,
the Commission will not adopt EDI for the Index of Customers or
discount rate data.
E. Finalization of Electronic Requirements and Procedural
Considerations
Williston Basin, Panhandle, INGAA, and AGA urge the Commission to
postpone finalization of electronic requirements until such time as a
final order is issued, and sufficient time has been allowed beyond
issuance to develop appropriate procedures, formats, and software.
Panhandle notes that pipeline and commercial software developers would
need time to develop, test, and place into production, the systems that
generate the reports required by the rule. In addition, Panhandle
states that it will be necessary to map data points for the new
reporting requirements. Panhandle is concerned that sufficient time be
allotted for the development, testing, and implementation of the
applications that will be used for generating electronic versions of
filed reports. In the same vein, AGA urges the Commission to consider
designing the software to operate on local area networks.
The Registry recommends that FERC set additional schedules and a
procedural process, including another informal technical conference, to
handle the technical aspects of data layout, content, and format. The
Registry suggests that, at the conference, the Commission should
establish three working groups, their chairs, their agendas, and their
individual jurisdiction. The Registry proposes a rate case working
group dealing with spreadsheets, file naming, formats, and data
protection; a Form No. 2 working group dealing with data field naming
and record layout for the comma-delimited filing format; and a EDI,
market monitoring, and market confidence working group dealing with EDI
formats associated with the Index of Customers and discount reports.
The Registry further proposes a detailed procedural process and
timetable for resolution of the issues.
The Registry also urges the Commission to adopt a flexible
implementation and compliance schedule for the Index of Customers.
Specifically, it proposes that the Commission should set beginning and
end dates for compliance with the electronic index (for example six
months), and that the pipelines submit first, second, and third choices
for the month in which they wish to complete implementation. The
Commission would then select a schedule of compliance for the pipelines
based on these choices, using a first-come, first-served principle.
In view of the need for sufficient time to implement the new
requirements, INGAA suggests the changes to Form Nos. 2, 2-A, and 11
should be effective on the January 1st that falls at least 180 days
after publication of the final rule in the Federal Register.
Contrary to what was stated in the NOPR, this rule does not
finalize all of the electronic filing requirements. As desired by the
commenters, the Commission is allowing adequate time subsequent to the
issuance of this rule for the technical aspects of the electronic
filing requirements to be finalized. As we have stated, we are
convening another joint informal technical conference in the two
companion rulemaking proceedings for this purpose. The Commission staff
will convene the conference as soon as
[[Page 53063]]
possible after the issuance of the rules. The procedures to be
subsequently followed will be discussed, and if possible, established,
at that conference.
The Commission discusses the appropriate filing date for the
revised Form No. 2 elsewhere in this rule. The revised Form No. 2
cannot be filed electronically until all of the electronic filing
instructions have been finalized. We are not requiring that pipelines
file the revised Form Nos. 2 and 2-A, either in paper or
electronically, until April 1997. Thus, there should be more than
adequate time to establish and put into place the new electronic filing
requirements prior to the filing of the revised Form Nos. 2 and 2-A.
The Form Nos. 2 and 2-A for the calendar year 1995, filed in 1996, must
be filed under the old filing requirements, including the old
electronic filing requirements.
Given the reduction in the scope of the Form No. 11 and the Index
of Customers, and the elimination of the changes to the discount rate
report, the Commission does not anticipate a lengthy delay in
implementing the electronic filing requirements for those reports. We
anticipate that the electronic filing requirements will be finalized
prior to the first filing of the Form No. 11. If not, the pipeline must
file only the paper copy of the revised Form No. 11. In any event, a
final schedule for the implementation of the electronic filing
requirements must be worked out among the participants of the
conference.
X. Environmental Analysis
The Commission is required to prepare an Environmental Assessment
or an Environmental Impact Statement for any action that may have a
significant adverse effect on the human environment.103 The
Commission has categorically excluded certain actions from these
requirements as not having a significant effect on the human
environment.104 The action taken here is procedural in nature and
therefore falls within the categorical exclusions provided in the
Commission's regulations.105 Therefore, neither an environmental
impact statement, nor an environmental assessment is necessary, and
will not be prepared in this rulemaking.
\103\Order No. 486, Regulations Implementing the National
Environmental Policy Act, 52 FR 47897 (Dec. 17, 1987), FERC Statutes
and Regulations, Regulations Preambles 1986-1990 para.30,783 (1987).
\104\18 CFR 380.4.
\105\See 18 CFR 380.4(a)(2)(ii).
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XI. Reporting Flexibility Certification
The Regulatory Flexibility Act (RFA)106 generally requires the
Commission to describe the impact that a final rule will have on small
entities or to certify that the rule will not have a significant
economic impact on a substantial number of small entities. An analysis
is not required if a final rule will not have such an impact.107
Most gas companies to whom the final rule applies do not fall within
the definition of a ``small entity.''108 Consequently, pursuant to
section 605(b) of the RFA, the Commission certifies that the final rule
will not have a significant impact on a substantial number of small
entities.
\106\5 U.S.C. 601-612.
\107\5 U.S.C. 605(b).
\108\Section 601(c) of the RFA defines a ``small entity'' as a
small business, a small not-for-profit enterprise, or a small
governmental jurisdiction. A ``small business'' is defined by
reference to section 3 of the Small Business Act as an enterprise
which is ``independently owned and operated and which is not
dominant in its field of operation.'' 15 U.S.C. 632(a).
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XII. Information Collection Statement
The Office of Management and Budget's (OMB) regulations109
require that OMB approve certain information and recordkeeping
requirements imposed by an agency. The information collection
requirements in this final rule are contained in the following:
\109\5 CFR 1320.13.
---------------------------------------------------------------------------
FERC Form No. 2 ``Annual Report of Major Natural Gas Companies''
(1902-0028);
FERC Form No. 2-A, ``Annual Report of Nonmajor Natural Gas
Companies'' (1902-0030);
FERC Form No. 11, ``Natural Gas Pipeline Company Monthly
Statement'' (1902-0032);
FERC-549, ``Gas Pipeline Rates: Natural Gas Policy Act Title III
Transactions'' (1902-0086);
FERC-549B, ``Gas Pipeline Rates: Capacity Release Information''
(1902-0169);
FERC-576, ``Reports on Pipeline Systems Service Interruptions''
(1902-0004);
FERC Form No. 8, ``Underground Gas Storage Report'' (1902-0026);
and
FERC Form No. 14, ``Annual Report for Importers and Exporters of
Natural Gas'' (1902-0027).
By this rule, the Commission is modernizing its regulations to
reflect the current regulatory environment that it instituted with
Order No. 636 and the restructuring of the natural gas industry.
Specifically, the Commission is revising its regulations to focus on
transportation services instead of pipeline sales activities. The
revised filing requirements will improve the internal support of a
pipeline's filing, reduce the filing burden for all parties, and
facilitate pipeline reporting requirements.
The Commission's Office of Pipeline Regulation uses the data in
rate proceedings to review rate and tariff changes by natural gas
companies for the transportation of gas and for general industry
oversight under the Natural Gas Act. The Commission's Office of
Economic Policy also uses this data in its analysis of interstate
natural gas pipelines.
The Commission is submitting to the Office of Management and Budget
a notification of these collections of information. Under the 1995
Recordkeeping Reduction Act, each of the forms being revised or
retained in this rule will carry the following notice: ``You shall not
be penalized for failure to respond to this collection of information
unless the collection of information displays a valid OMB control
number.''
Interested persons may obtain information on these reporting
requirements by contacting the Federal Energy Regulatory Commission,
Washington, DC 20426 [Attention: Michael Miller, Information Services
Division, (202) 208-1415]. Comments on the requirements of this rule
can be sent to the Office of Information and Regulatory Affairs of OMB,
Washington, D.C. 20503, (Attention: Desk Officer for Federal Energy
Regulatory Commission) FAX: (202) 395-5167.
XIII. Effective Date and Transition Provisions
This Final Rule is effective November 13, 1995 except for the
changes to the Uniform System of Accounts and Form Nos. 2, 2-A, and 11,
which will be effective January 1, 1996.
The NOPR proposed that the changes to the Uniform System of
Accounts and Form Nos. 2 and 2-A be made effective January 1, 1995. The
remainder of the proposed rule, including changes to Form No. 11, was
proposed to be effective 30 days after publication in the Federal
Register. Numerous commenters suggested that the effective dates for
these changes be delayed and implemented on a prospective basis.
INGAA, ANR, MRT, and El Paso suggest that the effective date for
the parts of the final rule that make changes to the Uniform System of
Accounts and Form Nos. 2 and 2-A should be the January 1 that falls at
least 180 days after publication of the final rule in the Federal
Register. Other commenters suggest other prospective effective dates:
(1) January 1 at least 90 days subsequent to issuance of the final
[[Page 53064]]
rule;\110\ January 1 following the year of issuance of the final
rule;\111\ and (3) January 1, 1996.\112\
\110\AGA.
\111\Consumers Power.
\112\KN.
---------------------------------------------------------------------------
Panhandle suggests that, prior to the issuance of the final rule on
changes in the storage accounting requirements, the Commission conduct
a field test of the final proposed storage accounting guidelines with
several interstate pipelines for two or three months to thoroughly
evaluate the associated benefits and costs so that necessary revisions
can be made. Panhandle also suggests that a technical conference would
be helpful.
AGA and Consumers Power suggest that all other revisions and
changes not be effective until 90 days after issuance of the final
rule. MRT seeks clarification that the remaining changes are to take
effect only after publication of the final rule in the Federal Register
and not after publication of the NOPR.
In response to the comments filed, as stated above, the Commission
is moving the effective date for the changes to the Uniform System of
Accounts and Form Nos. 2 and 2-A to January 1, 1996. In addition, to
ensure a seamless transition to the new Form No. 11 filing requirement,
the Commission will make the changes to Form No. 11 effective January
1, 1996. All other changes adopted in the final rule will become
effective 30 days after the final rule is published in the Federal
Register.\113\ The Commission believes that 30 days is an appropriate
time period.
\113\In response to Texas Intrastates, this includes the NGPA
Section 311 material.
---------------------------------------------------------------------------
The Commission believes the January 1, 1996 effective date for the
revisions to the Uniform System of Accounts and Form Nos. 2, 2-A, and
11 will provide adequate time for pipelines to adapt to the
requirements of the final rule and to make the necessary modifications
to their recordkeeping systems.
Since the Commission is permitting use of the fixed asset and the
inventory methods of accounting for system gas and has simplified our
accounting requirements for encroachments and replacements of system
gas under the fixed asset model, the Commission sees no need to conduct
a field test or to hold a technical conference on our new storage
accounting requirements.
A number of commenters raise a variety of implementation issues
resulting from the adoption of changes to Uniform System of Accounts
and Form Nos. 2 and 2-A in the final rule.
INGAA, Panhandle, and ANR ask the Commission to waive the
requirement to report prior year comparative data for the first year of
operation under the new requirements. They argue that they need
sufficient time to modify pipeline electronic formats and various
accounting and reporting systems. AGA suggests that the comparative
data requirement for the Statement of Retained Earnings and Statement
of Cash Flows should be delayed for one year to avoid restating the
prior year and that sufficient time should be provided to modify
electronic hardware (local area networks). Consumers Power suggests
that the Commission consider adopting transition provisions, which
delay the comparative data requirement, so that prior data would not
have to be restated.
Since the Commission has postponed the effective date of the
changes to the accounting and Form Nos. 2 and 2-A reporting
requirements, pipelines will not have to recompute or restate amounts
related to 1995 transactions.
In response to concerns raised by commenters about the need to
restate prior year's account balances, the Commission will not require
such a restatement for FERC accounting and Form Nos. 2 and 2-A
reporting purposes. To do so, would result in retroactive application
of the accounting and Form Nos. 2 and 2-A rule changes contained in the
final rule and would be inconsistent with the accounting and Forms Nos.
2 and 2-A reporting requirements in effect through December 31, 1995.
Rather than waiving the reporting of comparative data or adopting
transitional reporting pages, the Commission will permit pipelines to
use the previous data (1995) on the Form No. 2 or Form No. 2-A reports
for the 1996 reporting year filed in 1997. The pipelines must footnote
the place in the report where the previous year's data is reported for
the item.\114\ However, no amounts need to be reported for the previous
year on schedules 302-307.
\114\For example, the footnote should indicate in which Account
No. 489 subaccount the 1995 total for revenues from the
transportation of gas of others is reported.
---------------------------------------------------------------------------
List of Subjects
18 CFR Part 2
Administrative practice and procedure, Electric power, Natural gas,
Pipelines, Reporting and recordkeeping requirements.
18 CFR Part 157
Administrative practice and procedure, Natural gas, Reporting and
recordkeeping requirements.
18 CFR Part 158
Administrative practice and procedure, Natural gas, Reporting and
recordkeeping requirements, Uniform System of Accounts.
18 CFR Part 201
Natural gas, Reporting and recordkeeping requirements, Uniform
System of Accounts.
18 CFR Part 250
Natural gas, Reporting and recordkeeping requirements.
18 CFR Part 260
Natural gas, Reporting and recordkeeping requirements.
18 CFR Part 284
Continental shelf, Natural gas, Reporting and recordkeeping
requirements.
18 CFR Part 381
Electric power plants, Electric utilities, Natural gas Reporting
and recordkeeping requirements.
18 CFR Part 385
Administrative practice and procedure, Electric power, Penalties,
Pipelines, Reporting and recordkeeping requirements.
By the Commission.
Lois D. Cashell,
Secretary.
In consideration of the foregoing, the Commission is amending Parts
2, 157, 158, 201, 250, 260, 284, 381, and 385, Chapter I, Title 18,
Code of Federal Regulations, as set forth below.
PART 2--GENERAL POLICY AND INTERPRETATIONS
1. The authority citation for part 2 continues to read as follows:
Authority: 15 U.S.C. 717-717w, 3301-3432; 16 U.S.C. 791a-825r,
2601-2645; 42 U.S.C. 4321-4361, 7101-7352.
Sec. 2.104 [Amended]
2. In Sec. 2.104(a), the words ``(other than under the grandfather
provisions of Sec. 284.105 or Sec. 284.223)'' are removed.
PART 157--APPLICATIONS FOR CERTIFICATES OF PUBLIC CONVENIENCE AND
NECESSITY AND FOR ORDERS PERMITTING AND APPROVING ABANDONMENT UNDER
SECTION 7 OF THE NATURAL GAS ACT
3. The authority citation for part 157 continues to read as
follows:
Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7101-7352.
[[Page 53065]]
Sec. 157.53 [Amended]
4. In Sec. 157.53, the words ``Drilling of gas or oil wells and
testing'' are removed from the section heading and the word ``Testing''
is added in their place, the words ``drilling of gas or oil wells or
for the use in the'' are removed from paragraph (a), and the words
``well or the'' are removed from paragraph (b).
PART 158--ACCOUNTS, RECORDS, AND MEMORANDA
5. The authority citation for part 158 is revised to read as
follows:
Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7102-7352.
6. Section 158.10 is revised to read as follows:
Sec. 158.10 Examination of Accounts.
All natural gas companies not classified as Class C or Class D
prior to January 1, 1984 shall secure for each year, the services of an
independent certified public accountant, or independent licensed public
accountant (licensed on or before December 31, 1970), certified or
licensed by a regulatory authority of a State or other political
subdivision of the United States, to test compliance in all material
respects of those schedules that are indicated in the General
Instructions set out in the applicable Annual Report, Form No. 2 or
Form No. 2-A, with the Commission's Uniform System of Accounts and
published accounting releases. The Commission expects that
identification of questionable matters by the independent accountant
will facilitate their early resolution and that the independent
accountant will seek advisory rulings by the Commission on such items.
This examination shall be deemed supplementary to periodic Commission
examinations of compliance.
7. Section 158.11 is revised to read as follows:
Sec. 158.11 Report of certification.
Each natural gas company not classified as Class C or Class D prior
to January 1, 1984 shall file with the Commission a letter or report of
the independent accountant certifying approval, together with the
original and each copy of the filing of the applicable Annual Report,
Form No. 2 or Form No. 2-A, covering the subjects and in the format
prescribed in the General Instructions of the applicable Annual Report.
The letter or report shall also set forth which, if any, of the
examined schedules do not conform to the Commission's requirements and
shall describe the discrepancies that exist. The Commission shall not
be bound by the certification of compliance made by an independent
accountant pursuant to this paragraph.
8. In section 158.12, the words ``The Commission will not recognize
any certified public accountant or public accountant through December
31, 1975, who is not in fact independent. Beginning January 1, 1976,
and each year thereafter, the'' are removed and the word ``The'' is
added in their place.
PART 201--UNIFORM SYSTEM OF ACCOUNTS PRESCRIBED FOR NATURAL GAS
COMPANIES SUBJECT TO THE PROVISIONS OF THE NATURAL GAS ACT
9. The authority citation for Part 201 continues to read as
follows:
Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7101-7352,
7651-7651o.
10. In Part 201, Definitions, Definitions 13, 15, 16, 32B, 38, and
39 are amended by removing the words ``in the case of Major natural gas
companies,'' and Definition 29 is amended by removing the words
``(Major natural gas companies).''
11. In Part 201, General Instructions, paragraph 1 is revised to
read as follows:
General Instructions
1. Applicability. Each natural gas company must apply the system of
accounts prescribed by the Commission.
* * * * *
12. In Part 201, General Instructions, paragraphs 8, 12, 14, 15,
and 16, the words ``(Major natural gas companies)'' are removed at the
end of each heading, and in the heading for paragraph 21, the words
``(Nonmajor natural gas companies)'' are removed.
13. In Part 201, Gas Plant Instructions, paragraph 1, the words
``Classification of utilities (Major natural gas companies)'' are
removed from the heading and the words ``Classification of gas plant at
the effective date of the system of accounts'' are added in their
place.
14. In Part 201, Gas Plant Instructions, paragraph 3, introductory
text, the words ``For Major natural gas companies'' are removed and the
words ``A. The'' are added in their place; the words ``(Major and
Nonmajor Natural Gas Companies)'' are removed from paragraphs 3A.(17)
and 3A.(19), and paragraph 3B. is removed.
15. In Part 201, Gas Plant Instructions, paragraph 4C., the words
``For Major natural gas companies, the'' are removed and the word
``The'' is added in their place.
16. In Part 201, Gas Plant Instructions, paragraph 6A., the words
``(For Nonmajor companies, account 404, Amortization of Limited-Term
Gas Plant)'' are removed.
17. In Part 201, Gas Plant Instructions, paragraphs 7C. and 7E.,
the words ``or in the case of Major companies,'' are removed.
18. In Part 201, Gas Plant Instructions, paragraph 7D., the words
``In the case of Major companies, a parcel,'' are removed and the words
``A parcel'' are added in their place.
19. In Part 201, Gas Plant Instructions, paragraph 7G., the words
``in the case of Major companies,'' are removed.
20. In Part 201, Gas Plant Instructions, paragraph 7H., the words
``(For Major companies, see,'' are removed and the word ``(See'' is
added in its place, and the last two sentences of the parenthetical are
removed and the words ``, and account 797, Abandonment, leases'' are
added in their place.
21. In Part 201, Gas Plant Instructions, paragraph 8G., the words
``(Major natural gas companies)'' are removed at the end of Items 2, 6,
11, 12, 18, 19, 22, 28, 29, 32, 35, 36, 39, 40, 41, 42, 44, 45, 47, 49,
52, 53, 55, 58, 60, 61, 62, 64, 65, 66, and 67. 18. In Part 201, Gas
Plant Instructions, paragraph 10E., the words ``or in the case of Major
companies,'' immediately following the words ``Gas Plant Held for
Future Use'' are removed.
22. In Part 201, Gas Plant Instructions, paragraph 10F., the words
``(account 110, Accumulated Provision for Depreciation, Depletion and
Amortization of Gas Utility Plant, in the case of Nonmajor companies)''
and the words ``(account 110 for Nonmajor companies)'' are removed.
23. In Part 201, Gas Plant Instructions, paragraph 10G., the words
``In the case of Major companies, the accounting for'' are removed and
the words ``The accounting for'' are added in their place.
24. In Part 201, Gas Plant Instructions, paragraph 11C, the words
``In the case of Major companies, each utility'' are removed and the
words ``Each utility'' are added in their place.
25. In Part 201, Gas Plant Instructions, paragraph 12, the words
``(105.1, Production Properties Held for Future Use, in the case of
Major companies)'' are removed and the words ``105.1, Production
Properties held for Future Use,'' are added in their place, and the
words ``(Major Companies)'' in the note are removed.
26. In Part 201, Gas Plant Instructions, paragraph 14, the words
``(Major natural gas companies)'' are removed at the end of the
heading.
27. In Part 201, Gas Plant Instructions, paragraph 15A., the words
``(account 180, Other Deferred Debits, in the case
[[Page 53066]]
of Nonmajor companies)'' are removed from paragraph A.(1), the words
``(the amounts recorded in account 186 shall be cleared to the
appropriate plant accounts, in the case of Nonmajor companies)'' are
removed from paragraph A.(2), and the words ``(Account 180 in the case
of Nonmajor companies)'' are removed from paragraph A.(3).
28. In Part 201, Gas Plant Instructions, paragraph 16 is removed.
29. In Part 201, Operating Expense Instructions, paragraph 1, the
words ``(Major natural gas companies)'' at the end of the heading are
removed.
30. In Part 201, Balance Sheet Chart of Accounts, and Balance Sheet
Accounts, the words ``(Major only)'' at the end of the headings of
Accounts 103, 105.1, 106, 108, 111, 115, 117, 123, 123.1, 125, 126,
128, 131 through 135, 151 through 153, 155, 156, 163, 164.3, 166, 167,
171 through 173, 183.1, 183.2, 184, 185, 188, 202, 203, 205 through
210, 216.1, 222, 238 through 241 are removed.
31. In Part 201, Balance Sheet Chart of Accounts, and Balance Sheet
Accounts, Accounts 103.1, 110, 117, 129, 130, and 218 are removed, and
in Balance Sheet Chart of Accounts, Accounts 117.1 through 117.4 and
their respective titles are added to read as follows:
Balance Sheet Chart of Accounts
* * * * *
117.1 Gas stored-Base gas.
117.2 System balancing gas.
117.3 Gas stored in reservoirs and pipelines-noncurrent.
117.4 Gas owed to system gas.
* * * * *
32. In Part 201, Balance Sheet Accounts, Account 116, paragraph A,
the words ``For major companies, see'' are removed, and the word
``See'' is added in their place.
33. In Part 201, Balance Sheet Accounts, Account 117 is removed,
and new Special Instructions and Accounts 117.1, 117.2, 117.3, and
117.4 are added to read as follows:
Balance Sheet Accounts
* * * * *
Special Instructions to Accounts 117.1, 117.2 and 117.3
The investment in and use of system gas included in Account 117.1,
Gas Stored--Base Gas, and Account 117.2, System Balancing Gas, may be
accounted for using either the ``fixed asset'' method or an
``inventory'' method as set forth below. The cost of stored gas
included in Account 117.3 must be accounted for using an inventory
method.
(a) Inventory Method--Gas stored during the year must be priced at
cost according to generally accepted methods of cost determination
consistently applied from year to year. Transmission expenses for
facilities of the utility used in moving the gas to the storage area
and expenses of storage facilities cannot be included in the inventory
of gas except as may be authorized or directed by the Commission.
Withdrawals of gas must be priced using the first-in-first-out,
last-in-first-out, or weighted average cost method, provided the method
adopted by the utility is used consistently from year to year and
appropriate inventory records are maintained. Approval of the
Commission must be obtained for any other pricing method, or change in
the pricing method adopted by the utility.
(b) Fixed Asset Method--The cost of system gas designated by the
Commission as available for transmission load balancing and other uses
associated with maintaining efficient transmission operations must be
determined from the book balances on the date of adoption of the
``fixed asset'' method. If at the date of adoption, the actual volumes
are less than the maximum volumes authorized by the Commission, the
deficient volumes are to be priced at the current market price with an
equal amount being credited to Account 117.4.
Withdrawals that encroach upon the designated volumes must be
priced at an amount equal to the current market price of gas available
to the utility. Account 808.1, Gas withdrawn from storage--debit, must
be charged with such amount and Account 117.4, Gas owed to system gas,
credited.
For the purpose of these instructions, current market price is the
delivered spot price of gas in the utility's supply area, as published
in a recognized industry journal. The publication used must be the same
one identified in the utility's tariff for use in its cash-out
provision, if it has one. If the utility does not have a cash-out
provision, it must use one publication consistently and identify the
publication in its records.
When replacement of the gas is made, the amount carried in Account
117.4 for such volumes must be cleared and Account 808.2, Gas delivered
to storage--credit. Any difference between the utility's cost of
replacement gas volumes and the amount cleared from Account 117.4 must
be recognized as a gain in Account 495, Other gas revenues, or as a
loss in Account 813, Other gas supply expenses, with contra entries to
Account 808.2.
Gas owned by the utility and injected into its system will be
deemed to satisfy any encroachment on system gas first before any other
use.
117.1 Gas stored-base gas.
This account is to include the cost of recoverable gas volumes that
are necessary, in addition to those volumes for which cost are properly
includable in Account 101, Gas plant in service, to maintain pressure
and deliverability requirements for each storage facility.
Nonrecoverable gas volumes used for this purpose are to be recorded in
Account 352.3, Nonrecoverable natural gas. For utilities using the
fixed asset method of accounting, the cost of base gas applicable to
each gas storage facility shall not be changed from the amount
initially recorded except to reflect changes in volumes designated as
base gas. If an inventory method is used to account for gas included
herein, the utility may, at its election, price withdrawals in
accordance with the instructions to Account 117.4.
117.2 System balancing gas.
This account is to be used to record the cost of system gas
designated as available for transmission load balancing (including no-
notice transportation) and other uses associated with maintaining
efficient transmission operations other than gas properly recordable in
Account 117.1 or the plant accounts. Detailed records must be kept
separately identifying volumes and unit prices of system gas held in
underground storage facilities and held in pipelines.
For utilities using fixed asset accounting, the cost initially
recorded herein cannot be changed except for adjustments to volumes
designated as system gas. Encroachments upon system gas must be
accounted for in accordance with the instructions to Account 117.4, Gas
owed to system gas.
117.3 Gas stored in reservoirs and pipelines--noncurrent.
This account is to include the cost of stored gas owned by the
utility and available for sale or other purposes. Gas included in this
account must be accounted for using an inventory method in accordance
with the Special Instructions to Accounts 117.1, 117.2, and 117.3
above.
117.4 Gas owed to system gas.
This account is to be used to record encroachments of system gas
under the fixed asset method. This account may also be used to record
encroachments of base gas for utilities electing to use an inventory
method of accounting for system gas. Utilities may revolve
[[Page 53067]]
cumulative net imbalances, net all transactions, and record one monthly
entry with one month-end price for valuation purposes.
* * * * *
34. In Part 201, Balance Sheet Accounts, Account 154, the words
``For Nonmajor utilities, this account shall include the cost of fuel
on hand and unapplied materials and supplies (except meters and house
regulators). For both Major and Nonmajor utilities, it'' are removed
from the introductory text of paragraph A and the words ``This
account'' are added in their place, paragraph C and Note B are removed,
Note A is redesignated Note, and the words ``they may be charged to a
stores expense clearing account (account 163, Stores Expenses
Undistributed, in the case of Major Utilities), and distributed
therefrom to the appropriate accounts'' in redesignated Note are
removed and the words ``they shall be charged to account 163, Stores
expenses Undistributed'' are added in their place.
35. In Part 201, Balance Sheet Accounts, Account 164.1 is revised
to read as follows:
Balance Sheet Accounts
* * * * *
164.1 Gas stored--current.
This account shall be debited with such amounts as are credited to
Account 117.2, System balancing gas, (for utilities using an inventory
method of accounting for system gas) and Account 117.3, Gas Stored in
Reservoirs and Pipelines-Noncurrent, to reflect classification for
balance sheet purposes of such portion of the inventory of gas stored
as represents a current asset according to conventional rules for
classification of current assets.
Note: It shall not be considered conformity to conventional
rules of current asset classification if the amount included in this
account exceeds an amount equal to the cost of estimated withdrawals
of gas from storage within the 24-month period from date of the
balance sheet, or if the amount represents a volume of gas which, in
fact, could not be withdrawn from storage without impairing pressure
levels needed for normal operating purposes.
* * * * *
36. In Part 201, Balance Sheet Accounts, Accounts 164.2, paragraph
D and 164.3, paragraph D, the words ``Mcf'' and ``Mcf (or Btu),''
respectively, are removed, and the words ``Dth'' are added in their
place.
37. In Part 201, Balance Sheet Accounts, Account 174, the current
text is designated paragraph A, and a paragraph B is added to read as
follows:
Balance Sheet Accounts
* * * * *
174 Miscellaneous current and accrued assets.
* * * * *
B. The utility is to include in a separate subaccount amounts
receivable for gas in unbalanced transactions where gas is delivered to
another party in exchange, load balancing, or no-notice transportation
transactions. (See Account 806.) If the amount receivable is settled by
other than gas, Account 495, Other Gas Revenues must be credited or
Account 813, Other Gas Supply Expenses, charged for the difference
between the amount of the consideration received and the recorded
amount of the receivable settled. Records are to be maintained so that
there is readily available for each party entering gas exchange, load
balancing, or no-notice transportation transactions, the quantity and
cost of gas delivered, and the amount and basis of consideration
received, if other than gas.
* * * * *
38. In Part 201, Balance Sheet Accounts, Account 186, the words
``For Major companies, this account shall'' are removed from paragraph
A, and the words ``This account shall'' are added in their place,
paragraph B is removed, paragraph C is redesignated as paragraph B, and
all the words in parenthesis in redesignated paragraph B are removed.
39. In Part 201, Balance Sheet Accounts, in the Note following
Account 204, the words ``(For Nonmajor companies, account 211,
Miscellaneous Paid-In Capital)'' are removed.
40. In Part 201, Balance Sheet Accounts, Account 211, the words
``(In the case of Nonmajor companies, this account shall be kept so as
to show the source of the credits includible herein)'' are removed, the
ITEMS section and Note B are removed, Note A is redesignated Note, and
the words ``(Major companies)'' are removed from the heading of
redesignated Note.
41. In Part 201, Balance Sheet Accounts, Account 242 is revised to
read as follows:
Balance Sheet Accounts
* * * * *
242 Miscellaneous current and accrued liabilities.
A. This account shall include the amount of all other current and
accrued liabilities not provided for elsewhere appropriately designated
and supported as to show the nature of each liability.
B. The utility is to include in a separate subaccount amounts
payable for gas in unbalanced transactions where gas is received from
another party in exchange, load balancing, or no-notice transportation
transactions. (See Account 806.) If the amount payable is settled by
other than gas, Account 495, Other Gas Revenues, must be credited or
Account 813, Other gas supply expenses, charged for the difference
between the amount of the consideration paid and the recorded amount of
the payable settled. Records are to be maintained so that there is
readily available for each party entering gas exchange, load balancing,
or no-notice transportation transactions, the quantity and cost of gas
received and the amount and basis of consideration paid if other than
gas.
* * * * *
42. In Part 201, Gas Plant Chart of Accounts and Gas Plant
Accounts, the words ``(Major only)'' at the end of each title of
Accounts 363, 363.1 through 363.4, and 364.1 through 364.8 are removed.
43. In Part 201, Gas Plant Accounts, Accounts 302, paragraph C, and
303, paragraph B, the words ``(For Nonmajor Companies; account 110,
Accumulated Provisions for Depreciation, Depletion and Amortization of
Gas Utility Plant)'' following the words ``Gas Utility Plant'' are
removed.
44. In Part 201, Gas Plant Accounts, Account 352.3, paragraph B is
revised to read as follows:
Gas Plant Accounts
* * * * *
352.3 Nonrecoverable natural gas.
* * * * *
B. Such nonrecoverable gas shall be priced at cost according to
generally accepted methods of cost determination consistently applied.
(See the Special Instructions to Accounts 117.1, 117.2, and 117.3.
* * * * *
45. In Part 201, Income Chart of Accounts and Income Accounts,
Accounts 403, 404.1, 404.2, 404.3, and 418.1, the words ``(Major
only)'' are removed from the end of the headings.
46. In Part 201, Income Chart of Accounts, Accounts 403.1 and 404
are removed.
47. In Part 201, Income Accounts, Accounts 421.1 and 421.2, the
words ``(Major only)'' are removed.
48. In Part 201, Operating Revenue Chart of Accounts, Account 489
and its respective title is removed, and Accounts 489.1 through 489.4
and their respective titles are added to read as follows:
[[Page 53068]]
Operating Revenue Chart of Accounts
* * * * *
489.1 Revenues from transportation of gas of others through gathering
facilities.
489.2 Revenues from transportation of gas of others through
transmission facilities.
489.3 Revenues from transportation of gas of others through
distribution facilities.
489.4 Revenues from storing gas of others.
* * * * *
49. In Part 201, Operating Revenue Chart of Accounts and Operating
Revenue Accounts, Account 482, the words ``(Major only)'' are removed
at the end of the headings.
50. In Part 201, Operating Revenue Accounts, Account 481, paragraph
C, the words ``(Major companies)'' are removed from the introductory
text, and the word ``Mcf'' is removed and the word ``Dth'' is added in
its place each time it appears.
51. In Part 201, Operating Revenue Accounts, Account 488, Item 3,
the words ``For Major Companies, see,'' are removed and the word
``See'' is added in its place.
52. In Part 201, Operating Revenue Accounts, Account 489 is
removed, and new Accounts 489.1, 489.2, 489.3, and 489.4 are added to
read as follows:
Operating Revenue Accounts
* * * * *
489.1 Revenues from transportation of gas of others through gathering
facilities.
This account includes revenues from transporting gas for other
companies through the gathering facilities of the utility.
489.2 Revenues from transportation of gas of others through
transmission facilities.
This account includes revenues from transporting gas for other
companies through the transmission facilities of the utility.
489.3 Revenues from transportation of gas of others through
distribution facilities.
This account includes revenues from transporting gas for other
companies through the distribution facilities of the utility.
489.4 Revenues from storing gas of others.
This account includes revenues from storing gas for other
companies.
* * * * *
53. In Part 201, Operating Revenue Accounts, Account 491, paragraph
B is revised to read as follows:
Operating Revenue Accounts
* * * * *
491 Revenues from natural gas processed by others.
* * * * *
B. The records supporting this account must be maintained so that
full information concerning determination of the revenues will be
readily available concerning each processor of gas of the utility,
including as applicable (a) The Dth of gas delivered to such other
party for processing, (b) the Dth of gas received back from the
processor, (c) the field, general production area , or other source of
the gas processed, (d) Dth of gas used for processing fuel, etc., which
is chargeable to the utility, (e) total gallons of each product
recovered by the processor and the utility's share thereof, (f) the
revenues accruing to the utility, and (g) the basis of determination of
the revenues accruing to the utility. Such records shall be maintained
even though no revenues are derived from the processor.
54. In Part 201, Operating Revenue Accounts, Account 495 is revised
to read as follows:
Operating Revenue Accounts
* * * * *
495 Other gas revenues.
This account includes revenues derived from gas operations not
includible in any of the foregoing accounts.
Items
1. Commission on sale or distribution of gas of others when sold
under rates filed by such others.
2. Compensation for minor or incidental services provided for
others such as customer billing, engineering, etc.
3. Profit or loss on sale of material and supplies not
ordinarily purchased for resale and not handled through
merchandising and jobbing accounts.
4. Sales of steam, water, or electricity, including sales or
transfers to other departments of the utility.
5. Miscellaneous royalties received.
6. Revenues from dehydration and other processing of gas of
others, except products extraction where products are received as
compensation and sales of such are includible in account 490, Sales
of Products Extracted From Natural Gas, and except compression of
gas of others, revenues from which are includible in accounts 489.1,
489.2, or 489.3, Revenues from Transportation of Gas of Others.
7. Include in a separate subaccount, revenues in payment for
rights and/or benefits received from others which are realized
through research, development, and demonstration ventures.
8. Include in a separate subaccount, gains on settlements of
imbalance receivables and payables (See Accounts 174 and 242) and
gains on replacement of encroachment volumes (See Account 117.4).
Records must be maintained and readily available to support the
gains included in this account.
9. Include in a separate subaccount revenues from penalties
earned pursuant to tariff provisions, including penalties associated
with cash-out settlements.
* * * * *
55. In Part 201, Operation and Maintenance Expense Chart of
Accounts and Operation and Maintenance Expense Accounts, the words
``(Major only)'' are removed at the end of each title of Accounts 700
through 708, 711 through 724, 725 through 729, 730, 732 through 735,
740 through 742, 751 through 754, 756, 757, 761, 762, 765 through 769,
770 through 775, 777 through 791, 800, 801 through 804.1, 806, 809.1,
809.2, 810, 815 through 822, 824, 830, 831, 833 through 837, 840
through 847.8, 851 through 853, 854 through 857, 859, 861, 862, 865
through 867, 871 through 873, 875 through 877, 880, 885 through 892,
894, 901, 905, 907 through 913, and 916.
56. In Part 201, Operation and Maintenance Expense Chart of
Accounts and Operation and Maintenance Expense Accounts, Accounts
724.1, 729.1, 737, 743, 769.1, 792, 799, 812.1, 827, 838, 839, 853.1,
857.1, 868, 880.1, 892.1, 895, 906, 917, and 933 are removed, and
Account 935 is redesignated Account 932.
57. In Part 201, Operation and Maintenance Expense Accounts,
Account 710, the words ``A. For Major companies, this'' are removed
from paragraph A, and the word ``This'' is added in its place, and
paragraph B and the Items section are removed.
58. In Part 201, Operation and Maintenance Expense Accounts,
Account 731A and 731B, the words ``(for Nonmajor companies, account
154, Plant Materials and Operating Supplies)'' are removed.
59. In Part 201, Operation and Maintenance Expense Accounts,
Account 750, the words ``For Major companies, this'' in paragraph A are
removed and the word ``This'' is added in their place, and in paragraph
B, under Items, the words ``(Major and Nonmajor)'' in the heading
``Items (Major and Nonmajor)'' and the heading ``Nonmajor Only'' and
Items 5 through 21 are removed.
60. In Part 201, Operation and Maintenance Expense Accounts,
Account 755, the words ``stations (including in the case of Major
companies, applicable amounts of fuel stock expenses)'' in paragraph A
are removed and the words ``stations, including applicable amounts of
fuel stock expenses'' are added in their place, the words ``For Major
companies, respective'' in paragraph B are removed
[[Page 53069]]
and the word ``Respective'' is added in their place, Note B is removed,
Note A is redesignated Note, and the words ``(Major Companies)'' is
removed from redesignated Note.
61. In Part 201, Operation and Maintenance Expense Accounts,
Account 759, the words ``(Major companies only)'' in the introductory
text are removed, the headings ``Major only'' and ``(Nonmajor
companies):'' in the Items section are removed, and Items 1 through 18
following Item 5 are removed.
62. In Part 201, Operation and Maintenance Expense Accounts,
Account 776, the words ``in the case of Major companies,'' the words
``(Major only)'' following the heading ``Items'', and the Note at the
end of the account are removed.
63. In Part 201, Operation and Maintenance Expense Accounts,
Account 795, Note, the words ``(in the case of Nonmajor Companies,
account 105, Gas Plant Held for Future Use)'' are removed.
64. In Part 201, Operation and Maintenance Expense Accounts,
Account 796, Note A, the words ``(in the case of Nonmajor companies,
General Instruction 21, Gas Well Records)'' following the words ``Each
Plant'' are removed.
65. In Part 201, Operation and Maintenance Expense Accounts,
Account 797, paragraph A, the words ``For Major companies, this'' are
removed, the word ``This'' is added in their place, and the sentence
following the word ``productive.'' is removed, and in paragraph B, the
words ``(Major only)'' are removed.
66. In Part 201, Operation and Maintenance Expense Accounts,
Account 798, the words ``for Major companies,'' and the words ``for
``Nonmajor companies, see account 186, Miscellaneous Deferred Debits''
are removed.
67. In Part 201, Operation and Maintenance Expense Accounts,
Account 805, a new paragraph C is added to read as follows:
Operation and Maintenance Expense Accounts
* * * * *
805 Other gas purchases.
* * * * *
C. Utilities recognizing revenue for shipper-supplied gas must
include the current market price of such gas in this account. Current
market price is the delivered spot price of gas in the utility's supply
area, as published in a recognized industry journal. The publication
used must be the same one identified in the pipeline's tariff for use
in its cash-out provision, if it has one. If it has no cash-out
provision, the utility must use one publication consistently. Contra
entries to those recorded herein must be made to the appropriate
transportation revenue account (Account 489.1 through Account 489.4).
Records are to be maintained and readily available that include the
name of shipper, quantity of gas, and the publication and price used to
value shipper-supplied gas.
* * * * *
68. In Part 201, Operation and Maintenance Expense Accounts,
Account 806 is revised to read as follows:
Operation and Maintenance Expense Accounts
* * * * *
806 Exchange gas.
A. This account includes debits or credits for the cost of gas in
unbalanced transactions where gas is received from or delivered to
another party in exchange, load balancing, or no-notice transportation
transactions. The costs are to be determined from the current market
price of gas at the time gas is tendered for transportation. (See the
Special Instructions to Accounts 117.1, 117.2, and 117.3 for the
definition of the current market price of gas.) Contra entries to those
in this account are to be made to Account 174, Miscellaneous Current
and Accrued Assets, for gas receivable and to Account 242,
Miscellaneous Current and Accrued Liabilities, for gas deliverable
under such transactions. Such entries must be reversed and appropriate
contra entries made to this account when gas is received or delivered
in satisfaction of the amounts receivable or deliverable.
B. Records must be maintained so that there is readily available
for each party entering gas exchange, load balancing, or no-notice
transportation transactions, the quantity and cost of gas delivered and
received.
* * * * *
69. In Part 201, Operation and Maintenance Expense Accounts,
Account 807, paragraph D, the words ``(Major companies'') are removed.
70. In part 201, Operation and Maintenance Expense Accounts,
paragraph A of Accounts 808.1 and 808.2 are revised to read as follows:
Operation and Maintenance Expense Accounts
* * * * *
808.1 Gas withdrawn from storage-debit.
A. This account shall include debits for the cost of gas withdrawn
from storage during the year. Contra credits for entries to this
account shall be made to Account 117.3, Gas Stored in Reservoirs and
Pipelines-Noncurrent, or Account 117.4, Gas Owed to System Gas, or
Account 164.2, Liquefied Natural Gas Stored, as appropriate. (See the
Special Instructions to Accounts 117.1, 117.2, and 117.3).
* * * * *
808.2 Gas delivered to storage-credit
A. This account shall include credits for the cost of gas delivered
to storage during the year. Contra debits for entries to this account
shall be made to Account 117.3, Gas Stored in Reservoirs and Pipelines-
Noncurrent, Account 117.4, Gas Owed to System Gas, or Account 164.2,
Liquefied Natural Gas Stored, as appropriate. (See the Special
Instructions to Accounts 117.1, 117.2, and 117.3).
* * * * *
71. In Part 201, Operation and Maintenance Expense Accounts,
Account 813, the current text is designated paragraph A, and the
existing concluding text is added to the end of newly designated
paragraph A, the words ``, in the case of Major companies,'' are
removed from redesignated paragraph A, and a new paragraph B is added
to read as follows:
Operation and Maintenance Expense Accounts
* * * * *
813 Other gas supply expenses.
* * * * *
B. Include in separate subaccounts: (1) losses on settlements of
imbalance receivables and payables (See Account 174 and 242) and losses
on replacement of encroachment volumes (See the Special Instructions to
Accounts 117.1, 117.2 and 117.3); (2) revaluations of storage
encroachments; and (3) system gas losses not associated with storage.
Appropriate records must be maintained and readily available that
include the amount of losses and associated volumes in Dth.
72. In Part 201, Operation and Maintenance Expense Accounts,
Account 814, paragraph B and the Items (Nonmajor only) section are
removed, and in paragraph A, the designation ``A.'' and the words ``For
Major companies, this'' are removed and the word ``This'' is added in
their place.
73. In Part 201, Operation and Maintenance Expense Accounts,
Account 823, the words ``For Major
[[Page 53070]]
companies, see'' are removed and the word ``See'' is added in their
place.
74. In Part 201, Operation and Maintenance Expense Accounts,
Account 845.6B, the words ``Mcf or Dth, as appropriate,'' are removed
and the word ``Dth'' is added in their place.
75. In Part 201, Operation and Maintenance Expense Accounts,
Account 850, paragraph B and the Items (Nonmajor only) section are
removed, and in paragraph A, the designation ``A.'' and the words ``For
Major companies, this'' are removed and the word ``This'' is added in
their place.
76. In Part 201, Operation and Maintenance Expense Accounts,
Accounts 853.1B and 854B, the word ``Mcf'' is removed and the word
``Dth'' is added in its place.
77. In Part 201, Operation and Maintenance Expense Accounts,
Account 858, paragraph B, the word ``Mcf'' is removed and the word
``Dth'' is added in its place each time it appears.
78. In Part 201, Operation and Maintenance Expense Accounts,
Account 870, the words ``(Major only)'' are removed, and the words
``For Major companies, see'' are removed, and in their place the word
``See'' is added.
79. In Part 201, Operation and Maintenance Expense Accounts,
Account 874, Items, the words ``(Major only)'' in the heading ``Labor
(Major only)'' are removed, the heading ``Labor (Nonmajor only):'' and
Items 1 through 3 under that heading are removed, the words ``(Major
and Nonmajor):'' in the heading ``Materials and Expenses (Major and
Nonmajor)'' are removed, and the words ``(Major only)'' are removed
from Items 2, and 8 through 12 under that heading.
80. In Part 201, Operation and Maintenance Expense Accounts,
Account 878, Items, the words ``(Major only)'' are removed at the end
of each Item 1 through 12 and 20.
81. In Part 201, Operation and Maintenance Expense Accounts,
Account 879, Items, the words ``(Major only)'' are removed at the end
of Items 1, 2, 4, 5, 6, 9, and 11 through 13.
82. In Part 201, Operation and Maintenance Expense Accounts,
Account 902, Items, Items 13 and 14 are removed, and a new Item 13 is
added to read as follows:
Operation and Maintenance Expense Accounts
* * * * *
902 Meter reading expenses.
* * * * *
13. Transportation, meals and incidental expenses.
* * * * *
83. In Part 201, Operation and Maintenance Expense Accounts,
Account 903, the words ``(Major only)'' at the end of Item 26 are
removed, and Items 31 and 32 are removed.
84. In Part 201, Operation and Maintenance Expense Accounts,
Account 924, the words ``For Major companies, it'' are removed from
paragraph A and the word ``It'' is added in their place, the words
``(stores expenses in the case of Nonmajor companies)'' are removed
from paragraph (1) of Note B, in paragraph (2) of Note B, the words
``For Major companies, transportation'' are removed and the word
``Transportation'' is added in their place, and the words ``For
Nonmajor companies, transportation and garage equipment, to account
933, Transportation expenses.'' are removed, and the words ``(Major
only)'' are removed from the title of Note C.
85. In Part 201, Operation and Maintenance Expense Accounts,
Account 925, paragraph A, the words ``For Major Companies, it'' are
removed and the word ``It'' is added in their place.
86. In Part 201, Operation and Maintenance Expense Accounts,
Account 926, paragraph D, the words ``For Major companies, records''
are removed and the word ``Records'' is added in their place.
87. In Part 201, Operation and Maintenance Expense Accounts,
Account 930.2, Item 4, the words ``For Major Companies, research'' are
removed and the word ``Research'' is added in its place, and the words
``For Nonmajor companies, experimental and general research work for
the industry.'' are removed.
88. In Part 201, Operation and Maintenance Expense Accounts,
Account 935 is redesignated Account 932, and redesignated Account 932
is amended by removing the words ``For Nonmajor companies, include also
other general equipment accounts (not including transportation
equipment).'' in paragraph A, revising paragraph B after the words
``the following accounts:'', and adding the Note to read as follows:
Operation and Maintenance Expense Accounts
* * * * *
932 Maintenance of general plant.
* * * * *
B. * * *
Manufactured Gas Production, accounts 708, 742
Natural Gas Production and Gathering, account 769
Natural Gas Production
Extraction, account 791
Underground Storage, account 837
Local Storage, account 846.2
Transmission Expenses, account 867
Distribution Expenses, account 894
Merchandising and Jobbing, account 416
Garage, Shops, etc.--appropriate clearing account, if used.
Note: Maintenance of plant included in other general plant
equipment accounts shall be included herein unless charged to
clearing accounts or to a particular functional maintenance expense
indicated by the use of the equipment.
PART 250--FORMS
89. The authority citation for part 250 continues to read as
follows:
Authority: 15 U.S.C. 717--717w, 3301--3432; 42 U.S.C. 7101-7352.
90. Section 250.2 is revised to read as follows:
Sec. 250.2 Form of proposed cancellation of tariff or part thereof
(see Sec. 154.602 of this chapter).
When cancelling an entire tariff or an entire rate schedule, the
notice of cancellation as set forth below must be filed as a revised
tariff sheet superseding the first tariff sheet in the sequence of
tariff sheets containing the tariff or part of the tariff being
cancelled. When cancelling an individual tariff sheet, the tariff sheet
should be designated as reserved for future use.
CANCELLATION OF ENTIRE TARIFF
Notice is hereby given that effective ____________________
(date) FERC Gas Tariff of ____________________ (Name of Company) is
to be cancelled.
CANCELLATION OF RATE SCHEDULE
Notice is hereby given that effective ____________________
(date) Rate Schedule ____________________ constituting
____________________ Sheet(s) No.(s) ____________________ of the
FERC Gas Tariff of ____________________ (Name of Company) is to be
cancelled.
91. Section 250.3 is revised to read as follows:
Sec. 250.3 Form of proposed cancellation or termination of contract or
part thereof (see Sec. 154.602 of this chapter).
Notice is hereby given that effective the __________ day of
____________________, ______, the contract with ____________________,
(Name of customer or customers) dated ____________________ and relating
to service under rate schedules(s) ____________________ (Here identify
the rate schedule(s), giving sheet numbers in the Tariff) is to be
____________________ (Specify whether
[[Page 53071]]
it automatically terminates by its terms or is to be canceled by action
of the parties)
----------------------------------------------------------------------
(Name of natural-gas company filing notice)
By---------------------------------------------------------------------
----------------------------------------------------------------------
(Title)
Dated------------------------------------------------------------------
92. Section 250.4 is revised to read as follows:
Sec. 250.4 Form of certificate of adoption (see Sec. 154.603 of this
chapter).
The------------------------------------------------------------------
(Exact name of company or person)
----------------------------------------------------------------------
(Address)
effective--------------------------------------------------------------
(Effective date of adoption)
hereby adopts, ratifies, and makes its own, in every respect, the
Tariff and contracts listed below, which have heretofore been filed
with the Federal Energy Regulatory Commission by
----------------------------------------------------------------------
(Exact name of predecessor)
----------------------------------------------------------------------
(Here identify the Tariff and contracts adopted.)
----------------------------------------------------------------------
(Name of successor)
By---------------------------------------------------------------------
(Title)
Dated------------------------------------------------------------------
Secs. 250.5, 250.7, 250.8, 250.9, 250.10, 250.12, and 250.14 [Removed
and reserved]
93. Sections 250.5, 250.7, 250.8, 250.9, 250.10, 250.12, and 250.14
are removed and reserved.
94. In Sec. 250.16, the words ``941 North Capitol Street, NE.,''
are removed from paragraphs(c)(3) and (d)(2), and paragraph (d)(1) is
revised to read as follows:
Sec. 250.16 Format of compliance plan for transportation services and
affiliate transactions.
* * * * *
(d) Transportation Discount Information. (1) A pipeline that
provides transportation service at a discounted rate must maintain, for
each billing period, the following information: the name of the shipper
being provided the discount; the affiliate's role in the transportation
transaction (i.e., shipper, marketer, supplier, seller); the duration
of the discount; the maximum rate or fee; the rate or fee actually
charged during the billing period; and the quantity of gas scheduled at
the discounted rate during the billing period for each delivery point.
The discount information with respect to each transaction must be
maintained for three years from the date the transaction commences.
* * * * *
PART 260--STATEMENTS AND REPORTS (SCHEDULES)
95. The authority citation for part 260 continues to read as
follows:
Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7101-7352.
96. In Sec. 260.1, paragraph (a) is amended by adding a heading,
and by removing the words ``for the reporting year 1980 and
thereafter'', and paragraph (b) is revised to read as follows:
Sec. 260.1 FERC Form No. 2, Annual report for Major natural gas
companies.
(a) Prescription. * * *
(b) Filing requirements. Each natural gas company, as defined in
the Natural Gas Act (15 U.S.C. 717, et seq.) which is a major company
(a natural gas company whose combined gas transported or stored for a
fee exceeded 50 million Dth in each of the three previous calendar
years) must prepare and file with the Commission, on or before April 30
following the close of each calendar year, FERC Form No. 2. Newly
established entities must use projected data to determine whether FERC
Form No. 2 must be filed. The form must be filed electronically as
indicated in the general instructions set out in that form. The format
for the electronic filing can be obtained at the Federal Energy
Regulatory Commission, Division of Information Services, Public
Reference and Files Maintenance Branch, Washington, D.C. 20426. One
copy of the report must be retained by the respondent in its files. The
conformed copies may be by any legible means of reproduction.
97. In Sec. 260.2, paragraph (a) is amended by removing the words
``for the year 1980 and each year thereafter'', and paragraph (b) is
revised to read as follows:
Sec. 260.2 FERC Form No. 2-A, Annual report for Nonmajor natural gas
companies.
* * * * *
(b) Filing requirements. Each natural gas company, as defined by
the Natural Gas Act, not meeting the filing threshold for FERC Form No.
2, but having total gas sales or volume transactions exceeding 200,000
Dth in each of the three previous calendar years, must prepare and file
with the Commission, on or before March 31 following the close of each
calendar year, FERC Form No. 2-A. Newly established entities must use
projected data to determine whether FERC Form No. 2-A must be filed.
The form must be filed electronically as indicated in the general
instructions set out in that form. The format for the electronic filing
can be obtained at the Federal Energy Regulatory Commission, Division
of Information Services, Public Reference and Files Maintenance Branch,
Washington, D.C. 20426.
98. Section 260.3 is revised to read as follows:
Sec. 260.3 FERC Form No. 11, Natural gas pipeline company quarterly
statement of monthly data.
(a) This form, which is applicable to natural gas companies
designated herein, is designed to obtain on a quarterly basis monthly
information concerning selected revenues and associated quantities.
(b)(1) Who must file. Each natural gas company, as defined in the
Natural Gas Act, whose gas transported or stored for a fee exceeded 50
million Dth in each of the three previous calendar years, must prepare
and file with the Commission FERC Form No. 11. The form must be filed
electronically. The format for the electronic filing can be obtained at
the Federal Energy Regulatory Commission, Division of Information
Services, Public Reference and Files Maintenance Branch, Washington,
D.C. 20426.
(2) When to file. The reports must be filed quarterly on February
14 for data for the three months ending December 31, on May 15 for data
for the three months ending March 31, on August 14 for data for the
three months ending June 30, and on November 14 for data for the three
months ending September 30. Each report must be signed by the person
authorized to sign such report, but is not required to be filed under
oath.
Sec. 260.4 [Removed and reserved]
99. Section 260.4 is removed and reserved.
100. In Sec. 260.9, the introductory text of paragraph (b), and
paragraphs (c) and (e) are revised to read as follows:
Sec. 260.9 Report by natural gas pipeline companies on service
interruptions occurring on the pipeline system.
* * * * *
(b) Natural gas pipeline companies must report such interruptions
to service by any electronic means, including facsimile transmission or
telegraph, to the Director, Division of Environmental and Engineering
Review, Office of Pipeline Regulation, Federal Energy Regulatory
Commission, Washington, DC 20426 (FAX: (202) 208-2853), at the earliest
feasible time
[[Page 53072]]
following such interruption to service, and must state briefly:
* * * * *
(c) If so directed by the Commission or the Director, Division of
Environmental and Engineering Review, the company must provide any
supplemental information so as to provide a full report of the
circumstances surrounding the occurrence.
* * * * *
(e) Copies of the telegraphic or facsimile report on interruption
of service must be sent to the State commission in those States where
service has been or might be affected.
Secs. 260.11, 260.13, and 260.15 [Removed and reserved]
101. Sections 260.11, 260.13, and 260.15 are removed and reserved.
PART 284--CERTAIN SALES AND TRANSPORTATION OF NATURAL GAS UNDER THE
NATURAL GAS POLICY ACT OF 1978 AND RELATED AUTHORITIES
102. The authority citation for part 284 continues to read as
follows:
Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7201-7352;
43 U.S.C. 1331-1356.
Subpart A--General Provisions and Conditions
103. In Sec. 284.2, paragraph (b) is revised to read as follows:
Sec. 284.2 Refunds and interest.
* * * * *
(b) Interest. All refunds made pursuant to this section must
include interest at an amount determined in accordance with
Sec. 154.501(d) of this chapter.
Sec. 284.3 [Amended]
104. In Sec. 284.3(a), the words ``, sale or assignment'' are
removed and the words ``or sale'' are added in their place.
105. Section 284.4 is revised to read as follows:
Sec. 284.4 Reporting.
(a) Reports in MMBtu. All reports filed pursuant to this part must
indicate quantities of natural gas in MMBtu's. An MMBtu means a million
British thermal units. A British thermal unit or Btu means the quantity
of heat required to raise the temperature of one pound avoirdupois of
pure water from 58.5 degrees to 59.5 degrees Fahrenheit, determined in
accordance with paragraphs (b) and (c) of this section.
(b) Measurement. The Btu content of one cubic foot of natural gas
under the standard conditions specified in paragraph (c) of this
section is the number of Btu's produced by the complete combustion of
such cubic foot of gas, at constant pressure with air of the same
temperature and pressure as the gas, when the products of combustion
are cooled to the initial temperature of the gas and air and when the
water formed by such combustion is condensed to a liquid state.
(c) Standard conditions. The standard conditions for purposes of
paragraph (b) of this section are as follows: The gas is saturated with
water vapor at 60 degrees Fahrenheit under a pressure equivalent to
that of 30.00 inches of mercury at 32 degrees Fahrenheit, under
standard gravitational force (980.665 centimeters per second squared).
106. In Sec. 284.6, paragraph (b) is revised to read as follows:
Sec. 284.6 Rate interpretations.
* * * * *
(b) Address. Requests for interpretations should be addressed to:
FERC Part 284 Interpretations, Office of General Counsel, Federal
Energy Regulatory Commission, Washington, DC 20426.
107. In Sec. 284.7, paragraph (b) is removed, paragraphs (c) and
(d) are redesignated (b) and (c), respectively, redesignated paragraph
(c)(5)(iv) is removed, and a new paragraph (c)(6) is added to read as
follows:
Sec. 284.7 Rates.
* * * * *
(c) Rate design. * * *
(6) Discount reports. (i) A pipeline that provides either firm or
interruptible transportation service at a discounted rate must file
within 15 days of the close of the billing period a report containing
the following information:
(A) the full legal name of the shipper being provided the discount;
(B) any corporate affiliation between the transporting pipeline and
the shipper;
(C) the maximum rate or fee; and
(D) the rate or fee actually charged during the billing period.
(ii) The requirements of this section do not apply to discounts
relating to the release of capacity under Sec. 284.243, unless the
release is permanent.
(iii) The discount report information must be provided in
electronic format according to specifications that can be obtained at
the Federal Energy Regulatory Commission, Division of Information
Services, Public Reference and Files Maintenance Branch, Washington, DC
20426.
Sec. 284.8 [Amended]
108. In Sec. 284.8, paragraph (b)(4)(iii), the word ``of'' is added
after the word ``purging'' and before the word ``information'' and in
paragraph (b)(5)(i), the words ``941 North Capitol Street NE.,'' are
removed.
Sec. 284.10 [Removed and reserved]
109. Section 284.10 is removed and reserved.
Sec. 284.11 [Amended]
110. In Sec. 284.11, paragraph (d)(1) is removed and the heading
and paragraph designation for paragraph (d)(2) are removed.
Secs. 284.13 and 284.14 [Removed and reserved]
111. Sections 284.13 and 284.14 are removed and reserved.
Subpart B--Certain Transportation by Interstate Pipelines
112. Section 284.102(e) is revised to read as follows:
Sec. 284.102 Transportation by interstate pipelines.
* * * * *
(e) An interstate pipeline must obtain from its shippers
certifications including sufficient information to verify that their
services qualify under this section. Prior to commencing transportation
service described in paragraph (d)(3) of this section, an interstate
pipeline must receive the certification required from a local
distribution company or an intrastate pipeline pursuant to paragraph
(d)(3) of this section.
Sec. 284.105 [Removed and reserved]
113. Section 284.105 is removed and reserved.
114. In Sec. 284.106, paragraph (a) is revised, paragraphs (b)
through (f) are removed, paragraph (g) is redesignated as paragraph
(b), the introductory text of redesignated paragraph (b) is revised,
and a new paragraph (c) is added to read as follows:
Sec. 284.106 Reporting requirements.
(a) Notice of bypass. An interstate pipeline that provides
transportation (except storage) under Sec. 284.102 to a customer that
is located in the service area of a local distribution company and will
not be delivering the customer's gas to that local distribution
company, must file with the Commission, within thirty days after
commencing such transportation, a statement that the interstate
pipeline has notified the local distribution company and the local
distribution company's appropriate regulatory agency in writing of the
[[Page 53073]]
proposed transportation prior to commencement.
(b) Semi-annual storage report. Within 30 days of the end of each
complete storage injection and withdrawal season, the interstate
pipeline must file with the Commission a report of storage activity
provided under the authority of either Sec. 284.102 or Sec. 284.223, as
applicable. The report must be signed under oath by a senior official,
consist of an original and five conformed copies, and contain a summary
of storage injection and withdrawal activities to include the
following:
* * * * *
(c) Index of customers. (1) Each calendar quarter, subsequent to
the initial implementation of this provision, an interstate pipeline
must provide for electronic dissemination of an index of all its firm
transportation and storage customers under contract as of the first day
of the calendar quarter. Electronic dissemination will be by placing a
file, adhering to the requirements set forth by the Commission, on the
pipeline's electronic bulletin board in a format which can be
downloaded from the electronic bulletin board. The pipeline must also
submit the electronic file to the Commission.
(2) Until an interstate pipeline is in compliance with the
reporting requirements of this paragraph, the pipeline must comply with
the index of customer requirements applicable to transportation and
sales under Part 157, set forth under Sec. 154.111 (b) and (c) of this
chapter.
(3) For each customer receiving firm transportation or storage
service, the index must include the information listed below:
(i) the full legal name of the customer;
(ii) the rate schedule number of the service being provided;
(iii) the contract effective date;
(iv) the contract expiration date;
(v) for transportation service, maximum daily contract quantity
(specify unit of measurement);
(vi) for storage service, maximum storage quantity (specify unit of
measurement).
(4) The information included in the quarterly index must be
available on the electronic bulletin board until the next quarterly
index is established. The electronic files must be archived for at
least three years.
(5) The requirements of this section do not apply to contracts
which relate solely to the release of capacity under Sec. 284.243,
unless the release is permanent.
(6) The requirements for the electronic index can be obtained at
the Federal Energy Regulatory Commission, Division of Information
Services, Public Reference and Files Maintenance Branch, Washington, DC
20426.
Subpart C--Certain Transportation by Intrastate Pipelines
Sec. 284.122 [Amended]
115. In Sec. 284.122, paragraph (e) is removed.
116. In Sec. 284.123, paragraph (e) is revised to read as follows:
Sec. 284.123 Rates and charges.
* * * * *
(e) Filing requirements. Within 30 days of commencement of new
service, any intrastate pipeline that engages in transportation
arrangements under this subpart must file with the Commission a
statement that describes how the pipeline will engage in these
transportation arrangements, including operating conditions, such as,
quality standards and financial viability of the shipper. The statement
must also include the rate election made by the intrastate pipeline
pursuant to paragraph (b) of this section. If the pipeline changes its
operations or rate election under this subpart, it must amend the
statement and file such amendments not later than 30 days after
commencement of the change in operations or the change in rate
election.
Sec. 284.125 [Removed and reserved]
117. Section 284.125 is removed and reserved.
118. In Sec. 284.126, paragraph (a) is revised, paragraphs (b),
(e), and (f) are removed, paragraphs (c) and (g) are redesignated (b),
and (c), respectively, and redesignated paragraph (b) is revised to
read as follows:
Sec. 284.126 Reporting requirements.
(a) Notice of bypass. An intrastate pipeline that provides
transportation (except storage) under Sec. 284.122 to a customer that
is located in the service area of a local distribution company and will
not be delivering the customer's gas to that local distribution
company, must file with the Commission within thirty days after
commencing such transportation, a statement that the interstate
pipeline has notified the local distribution and the local distribution
company's appropriate state regulatory agency in writing of the
proposed transportation prior to commencement.
(b) Annual report. Not later than March 31 of each year, each
intrastate pipeline must file an annual report with the Commission and
the appropriate state regulatory agency that contains, for each
transportation service (except storage) provided during the preceding
calendar year under Sec. 284.122, the following information:
(1) The name of the shipper receiving the transportation service;
(2) The type of service performed (i.e., firm or interruptible);
(3) Total volumes transported for the shipper. If it is firm
service, the report should separately state reservation and usage
quantities; and
(4) Total revenues received for the shipper. If it is firm service,
the report should separately state reservation and usage revenues.
* * * * *
Subpart D--Certain Sales by Intrastate Pipelines
119. Section 284.142 is revised to read as follows:
Sec. 284.142 Sales by intrastate pipelines.
Any intrastate pipeline may, without prior Commission approval,
sell natural gas to any interstate pipeline or any local distribution
company served by an interstate pipeline. The rates charged by an
intrastate pipeline pursuant to this subpart may not exceed the price
for gas as negotiated in the contract, plus a fair and equitable
transportation rate as determined in accordance with Sec. 284.123.
Secs. 284.143 through 284.148 [Removed and reserved]
120. Sections 284.143 through 284.148 are removed and reserved.
Subpart E--Assignment of Contractual Rights to Receive Surplus
Natural Gas
Subpart E--[Removed and reserved]
121. Subpart E is removed and reserved.
Subpart G--Blanket Certificates Authorizing Certain Transportation
by Interstate Pipelines on Behalf of Others and Services by Local
Distribution Companies
122. In Sec. 284.221, the introductory text of paragraph (b)(1) is
revised, in paragraph (d)(1), the words ``Sec. 284.14(e), and'' are
removed, and in paragraph (f)(2), the words ``Sec. 284.222 or'' are
removed, to read as follows:
Sec. 284.221 General rule; transportation by interstate pipelines on
behalf of others.
* * * * *
(b) Application procedure. (1) An application for a blanket
certificate under this section must be filed electronically. The format
for the electronic application filing can be obtained at the Federal
Energy Regulatory Commission, Division of
[[Page 53074]]
Information Services, Public Reference and Files Maintenance Branch,
Washington, D.C. 20426, and must include:
* * * * *
Sec. 284.222 [Removed and reserved]
123. Section 284.222 is removed and reserved.
124. In Sec. 284.223, the section heading is revised, paragraphs
(b) through (f) are removed, and a new paragraph (b) is added to read
as follows:
Sec. 284.223 Transportation by interstate pipelines on behalf of
shippers.
* * * * *
(b) Reporting requirements. Any interstate pipeline transporting
gas under this section must comply with each of the reporting
requirements specified in Sec. 284.106.
113. In Sec. 284.224, the heading, paragraphs (b)(3), (c)
introductory text, (d)(1), (e)(1), and (g) are revised, paragraph
(e)(5)(i) is redesignated as paragraph (e)(5), and paragraph (e)(5)(ii)
is removed to read as follows:
Sec. 284.224 Certain transportation and sales by local distribution
companies.
* * * * *
(b) Blanket certificate-- * * *
(3) The Commission will grant a blanket certificate to such local
distribution company or Hinshaw pipeline under this section, if
required by the present or future public convenience and necessity.
Such certificate will authorize the local distribution company to
engage in the sale or transportation of natural gas that is subject to
the Commission's jurisdiction under the Natural Gas Act, to the same
extent that and in the same manner that intrastate pipelines are
authorized to engage in such activities by subparts C and D of this
part, except as otherwise provided in paragraph (e)(2) of this section.
(c) Application procedure. Applications for blanket certificates
must be accompanied by the fee prescribed in Sec. 381.207 of this
chapter or a petition for waiver pursuant to Sec. 381.106 of this
chapter, and shall state:
* * * * *
(d) Effect of certificate. (1) Any certificate granted under this
section will authorize the certificate holder to engage in transactions
of the type authorized by subparts C and D of this part.
* * * * *
(e) General conditions. (1) Except as provided in paragraph (e)(2)
of this section, any transaction authorized under a blanket certificate
is subject to the same rates and charges, terms and conditions, and
reporting requirements that apply to a transaction authorized for an
intrastate pipeline under subparts C and D of this part.
* * * * *
(g) Hinshaw pipeline without blanket certificate. A Hinshaw
pipeline that does not obtain a blanket certificate under this section
is not authorized to sell or transport natural gas as an intrastate
pipeline under subparts C and D of this part.
* * * * *
Secs. 284.225 and 284.226 [Removed and reserved]
125. Sections 284.225 and 284.226 are removed and reserved.
Sec. 284.227 [Amended]
126. In Sec. 284.227, paragraph (d) is removed, and paragraphs (e),
(f), and (g) are redesignated (d), (e), and (f).
Subpart I--Emergency Natural Gas Sale, Transportation, and Exchange
Transactions
Sec. 284.266 [Amended]
127. In Sec. 284.266, paragraphs (b) and (c) are removed, and
paragraph (d) is redesignated (b).
Sec. 284.269 [Amended]
128. In Sec. 284.269, the number ``Sec. 284.144'' is removed, and
the number ``Sec. 284.142'' is added in its place.
Subpart J--Blanket Certificates Authorizing Certain Natural Gas
Sales by Interstate Pipelines
Sec. 284.284 [Amended]
129. In Sec. 284.284(b), the words ``, except as adjusted in
Secs. 284.14 (d) and (e)'' are removed.
130. In Sec. 284.286, paragraph (e) is revised to read as follows:
Sec. 284.286 Standards of conduct for unbundled sales service.
* * * * *
(e) A pipeline that provides unbundled sales service under
Sec. 284.284 must have tariff provisions on file with the Commission
indicating how the pipeline is complying with the standards of this
section.
131. Section 284.287 is revised to read as follows:
Sec. 284.287 Implementation and effective date.
(a) Prior to offering any sales service under this subpart J, a
pipeline must file revised tariff sheets incorporating the provisions
of this subpart J.
(b) A blanket certificate issued under Sec. 284.284 will be
effective on the effective date (as approved by the Commission) of the
tariff sheets implementing service under that certificate.
Subpart L--Certain Sales for Resale by Non-interstate Pipelines
132. In Sec. 284.402, paragraph (c)(1) is revised, and in the first
sentence of paragraph (c)(2), the word ``criteria'' is removed, and the
word ``criterion'' is added in its place, to read as follows:
Sec. 284.402 Blanket marketing certificates.
* * * * *
(c)(1) The authorization granted in paragraph (a) of this section
will become effective for an affiliated marketer with respect to
transactions involving affiliated pipelines when an affiliated pipeline
receives its blanket certificate pursuant to Sec. 284.284.
* * * * *
PART 381--FEES
133. The authority citation for part 381 continues to read as
follows:
Authority: 15 U.S.C. 717-717w; 16 U.S.C. 791-828c, 2601-2645; 31
U.S.C. 9701; 42 U.S.C. 7101-7352; 49 U.S.C. 60502; 49 App. U.S.C. 1-
85.
Sec. 381.404 [Removed and reserved]
134. Section 381.404 is removed and reserved.
PART 385--RULES OF PRACTICE AND PROCEDURE
135. The authority citation for part 385 continues to read as
follows:
Authority: 5 U.S.C. 551-557; 15 U.S.C. 717-717z, 3301-3432; 16
U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352; 49
U.S.C. 60502; 49 U.S.C. 1-85.
136. In Sec. 385.2011, paragraphs (b), (c)(4), and (d) are revised
to read as follows:
Sec. 385.2011 Procedures for filing on electronic media (Rule 2011).
* * * * *
(b) These procedures also apply to:
(1) Material submitted electronically pursuant to Sec. 154.4 of
this chapter.
(2) Certificate and abandonment applications filed under Subparts
A, E, and F of Part 157 of this chapter.
(3) Blanket certificate applications filed under Subpart G of Part
284 of this chapter.
(4) Discount rate reports filed pursuant to Sec. 284.7 of this
chapter.
(c) What to file. * * *
(4) The formats for the electronic filing and the paper copy can be
obtained at the Federal Energy Regulatory Commission, Public Reference
and Files Maintenance
[[Page 53075]]
Branch, Division of Information Services, Washington, DC 20426.
* * * * *
(d)(1) Where to file. The electronic media, the paper copies, and
accompanying cover letter must be submitted to: Office of the
Secretary, Federal Energy Regulatory Commission, Washington, DC 20426.
(2) EDI data submissions must be made as indicated in the
electronic filing instructions and formats for the particular form or
filing, and the paper copies and accompanying cover letter must be
submitted to: Office of the Secretary, Federal Energy Regulatory
Commission, Washington, DC 20426.
Note: This Appendix will not be published in the Code of Federal
Regulations.
Appendix A--Parties Filing Comments on the Notice of Proposed Rulemaking
Docket No. RM95-4-000
------------------------------------------------------------------------
Commenter Abbreviation
------------------------------------------------------------------------
American Forest & Paper Association American Forest.
American Gas Association........... AGA.
American Public Gas Association.... APGA.
ANR Pipeline Company and Colorado ANR.
Interstate Gas Company.
Associated Gas Distributors........ AGD.
Association of Texas Intrastate Texas Intrastates.
Natural Gas Pipelines.
CNG Transmission Corporation....... CNG.
Columbia Gas Distribution Companies Columbia Distribution.
Columbia Gas Transmission Columbia.
Corporation and Columbia Gulf
Transmission Company.
Consumers Power Company and Consumers Power.
Michigan Gas Storage Company.
Electronic Bulletin Board Working EBB Working Group.
Group.
El Paso Natural Gas Company........ El Paso.
Enogex, Inc........................ Enogex.
Freeport Interstate Pipeline Freeport.
Company.
Gaslantic Corporation.............. Gaslantic.
Great Lakes Gas Transmission Great Lakes.
Limited Partnership.
Independent Petroleum Association IPAA.
of America.
Interstate Natural Gas Association INGAA.
of America.
KN Energy, Inc..................... KN.
Kern River Gas Transmission Company Kern River.
Midwest Gas Services, Inc.......... Midwest.
Mississippi River Transmission MRT.
Corporation and NorAm Gas
Transmission Company.
Missouri Public Service Commission. Missouri.
National Fuel Gas Supply National Fuel.
Corporation.
National Registry of Capacity Registry.
Rights.
Natural Gas Supply Association..... NGSA.
Northern Illinois Gas Company...... NI-Gas.
Panhandle Eastern Pipeline Company, Panhandle.
Trunkline Gas Company, Texas
Eastern Transmission Corporation,
and Algonquin Gas Transmission
Company.
Pacific Gas and Electric Company... PG&E.
Process Gas Consumers Group, Industrials.
American Iron and Steel Institute,
and Georgia Industrial Group.
Producer-Marketer Transportation PMTG.
Group.
Southern California Gas Company.... SoCal.
Tennessee Gas Pipeline Company, Tennessee.
Midwestern Gas Transmission
Company, and East Tennessee
Natural Gas Company.
Texas Gas Transmission Corporation. Texas Gas.
Transcontinental Gas Pipe Line Transco.
Corporation.
Transok, Inc....................... Transok.
United States Department of Energy. DOE.
Williston Basin Interstate Pipeline Williston.
Company.
Williams Natural Gas Company....... Williams.
------------------------------------------------------------------------
[FR Doc. 95-24722 Filed 10-10-95; 8:45 am]
BILLING CODE 6717-01-P
