[Federal Register: December 30, 2005 (Volume 70, Number 250)]
[Rules and Regulations]
[Page 77625-77661]
[DOCID:fr30de05-12]

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Part IV

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 101

Accounting and Financial Reporting for Public Utilities Including RTOs;
Final Rule

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 101

[Docket No. RM04-12-000; Order No. 668]

Accounting and Financial Reporting for Public Utilities Including
RTOs

Issued December 16, 2005.
AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
amending its regulations to update the accounting requirements for
public utilities and licensees, including independent system operators
and regional transmission organizations (collectively referred to as
RTOs). The Commission is also amending its financial reporting
requirements for the quarterly and annual financial reporting forms for
these entities. These updates to the Commission's Uniform System of
Accounts and the financial reporting requirements will allow for better
comparability between public utilities and will result in improved
transparency of financial information and will facilitate better
understanding of RTO costs.

DATES: Effective Date: The amended regulations will become effective
January 1, 2006.

FOR FURTHER INFORMATION CONTACT:

John Okrak (Technical Information), Office of Markets, Tariffs and
Rates, Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426,<PHONE_NUMBER>.
Julie Kuhns (Technical Information), Office of Markets, Tariffs and
Rates, Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426,<PHONE_NUMBER>.
Lodie White (Legal Information), Office of the General Council, Federal
Energy Regulatory Commission, 888 First Street, NE., Washington, DC
20426,<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:
I. Introduction
II. Background
III. Discussion
    A. General
    B. Regional Transmission and Market Operation Asset Function
    C. RTO Revenue Accounts
    D. Regional Market Expense Function
    E. Accounting by Public Utilities for Computer Hardware,
Software and Communication Equipment
    F. Accounting and Financial Reporting by Public Utilities,
Including RTOs
    1. Accounts for Load Dispatching, Scheduling and System Control
Expenses
    2. Accounts for System Planning and Standards Development
    3. Accounts for Study Costs
    4. Accounts for RTO Billings
    5. Account for Revenue From Transmission of Electricity
    6. Accounting for Settlement Amounts
    7. Ministerial Filings
    8. Cost Oversight
    9. Other Matters
IV. Effective Date
V. Changes to the FERC Quarterly and Annual Report Forms
VI. Information Collection Statement
VII. Environmental Analysis
VIII. Regulatory Flexibility Act
IX. Document Availabilty

    Before Commissioners: Joseph T. Kelliher, Chairman; Nora Mead
Brownell, and Suedeen G. Kelly.

I. Introduction

    1. In this Final Rule, the Commission is revising its Uniform
System of Accounts (USofA) \1\ to accommodate the restructuring changes
that are occurring in the electric industry due to the availability of
open-access transmission service and increasing competition in
wholesale bulk power markets. Corresponding changes are being made to
the FERC Form No. 1, Annual Report for Major Electric Utilities,
Licensees and Others (Form 1); FERC Form No. 1-F, Annual Report for
Nonmajor Public Utilities and Licensees (Form 1-F); and FERC Form No.
3-Q, Quarterly Financial Report of Electric Utilities, Licensees, and
Natural Gas Companies (Form 3-Q).
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    \1\ 18 CFR Part 101.
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II. Background

    2. In April 1996, in Order No. 888,\2\ the Commission established
the foundation necessary to develop competitive bulk power markets in
the United States: non-discriminatory open access transmission services
by public utilities and standard cost recovery rules to provide a fair
transition to competitive markets. Public utilities were also required
to functionally unbundle, and to provide transmission service
separately from generation services.
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    \2\ See Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, 61 FR 21,540 (May 10, 1996), FERC Stats. & Regs. ]
31,036 (1996), order on reh'g, Order No. 888-A, 62 FR 12,274 (March
14, 1977), FERC Stats. & Regs. ] 31,048 (1997), order on reh'g,
Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No.
888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub nom.
Transmission Access Policy Study Group, v. FERC, 225 F.3d 667 (D.C.
Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
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    3. Despite the changes brought about by Order No. 888, reports of
discriminatory practices by vertically integrated public utilities
persisted. In Order No. 2000,\3\ the Commission encouraged the
formation of independent and regional organizations, to remedy undue
discrimination and to foster regional efficiencies and efficient
pricing. As a result, a number of independent system operators and
regional transmission organizations (collectively referred to as RTOs)
have formed and are in operation.\4\ These RTOs perform many of the
same activities previously performed by the transmission owners whose
transmission systems they now operationally control. In addition, RTOs
perform some unique functions, not traditionally performed by other
public utilities, they oversee markets and they conduct long-term
system planning on a regional basis.
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    \3\ See Regional Transmission Organizations, Order No. 2000, 65
FR 809 (January 6, 2000), FERC Stats. & Regs. ] 31,089 (1999), order
on reh'g, Order No. 2000-A, 65 FR 12,088 (March 8, 2000), FERC
Stats. & Regs. ] 31,092 (2000), affirmed sub nom. Public Utility
District No. 1 of Snohomish County, Washington, v. FERC, 272 F.3d
607 (D.C. Cir. 2001).
    \4\ See, e.g., the California Independent System Operator
Corporation (CAISO), the Midwest Independent Transmission System
Operator, Inc. (Midwest ISO), the ISO New England, Inc. (ISO-NE),
the New York Independent System Operator, Inc. (NYISO), PJM
Interconnection, L.L.C. (PJM), and the Southwest Power Pool, Inc.
(SPP).
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    4. On September 26, 2004, the Commission issued a Notice of Inquiry
(NOI) in this proceeding.\5\ The NOI invited comments on various
matters including the Commission's accounting and financial reporting
requirements for RTOs. The Commission received comments from RTOs,
public utilities that are RTO members, state regulatory commissions,
and others. Generally, commenters agreed that the existing accounting
regulations and related financial reporting requirements do not provide
sufficient detailed information about RTO-related costs, including the
costs incurred by RTOs and other relevant information concerning the
types of services RTOs provide to their members. On June 3, 2005, the
Commission issued a Notice of Proposed Rulemaking (NOPR) in
response.\6\ The Commission received

comments from RTOs, public utilities that are RTO members, and
others.\7\
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    \5\ See Financial Reporting and Cost Accounting and Recovery
Practices for Regional Transmission Organizations and Independent
System Operators, 69 FR 58,112 (September 29, 2004), FERC Stats. &
Regs. ] 35,546 (2004).
    \6\ Accounting and Financial Reporting for Public Utilities
Including RTOs, 70 FR 36865 (June 27, 2005); FERC Stats. and Regs. ]
32,585.
    \7\ See Appendix A for list of commenters.
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    5. Today, the Commission is issuing this Final Rule to address the
accounting and financial reporting issues raised in the NOPR and the
comments to the NOPR. The changes to the Commission's accounting and
financial reporting requirements adopted here will provide uniformity
and transparency in accounting for and reporting of transactions and
events affecting public utilities, including RTOs. The Commission
expects that these changes in accounting and financial reporting will
also lead to improvements in cost recovery practices by providing
details concerning the cost of RTO functions, and increased assurance
that the costs are both legitimate and reasonable costs of providing
service and assigned to the correct period for recovery in rates.

III. Discussion

A. General

    6. The Commission received 22 comments on the proposed accounting
and reporting requirements which ranged from favorable to falling short
of the proposal's intended goal of providing greater transparency for
transactions and business functions. Most commenters, however,
generally commend and support the Commission's proposed initiative to
amend its regulations to update the accounting requirements for public
utilities, including RTOs.\8\ After careful consideration of the
comments received, the Commission is adopting the changes and revisions
as proposed with certain modifications and clarifications as discussed
below.
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    \8\ See generally National Grid, NRECA, Indicated NYTOs, and
TANC.
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B. Regional Transmission And Market Operation Asset Function

1. Accounting NOPR
    7. In the NOPR, the Commission proposed to create a new asset
function entitled Regional Transmission and Market Operation Plant to
record RTO investments in computer hardware, software and communication
equipment.\9\ The proposed new accounts in this function are Account
380, Land and Land Rights; Account 381, Structures and Improvements;
Account 382, Computer Hardware; Account 383, Computer Software; Account
384, Communication Equipment; Account 385, Miscellaneous Regional
Transmission and Market Operation Plant; Account 386, Asset Retirement
Costs for Regional Transmission and Market Operation Plant; and
reserves Account 387 for future accounts.
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    \9\ NOPR at P 20-32.
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2. Commenters
    8. Commenters were generally supportive and did not oppose the
creation of the Regional Transmission and Market Operation Asset
Function. One commenter recommended breaking down each new asset
account into sub-accounts for general purpose activities, market design
development, and market operation.\10\
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    \10\ City of Santa Clara at 23.
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3. Commission Conclusion
    9. The Commission will adopt the Regional Transmission and Market
Operation Asset Function as proposed in the NOPR: Account 380, Land and
Land Rights; Account 381, Structures and Improvements; Account 382,
Computer Hardware; Account 383, Computer Software; Account 384,
Communication Equipment; Account 385, Miscellaneous Regional
Transmission and Market Operation Plant; Account 386, Asset Retirement
Costs for Regional Transmission and Market Operation Plant; and
reserves Account 387 for future accounts. The Commission notes that in
order to perform many of their primary functions, RTOs must make
significant investments in computer hardware, software and
communication equipment. The cost of these assets is not explicitly
addressed in the existing primary plant accounts, resulting in
inconsistent accounting and reporting for these assets. In order to
provide more financial transparency and consistent accounting and
reporting for the costs of hardware, software and communication
equipment, the Commission believes a new utility plant function is
needed to record the cost of assets owned and used by RTOs.
    10. The Commission does not believe sufficient justification has
been advanced to expand the proposed new accounts further as suggested
by commenters. The new accounts adopted herein will provide the
Commission and others with additional, more detailed information than
is currently available about the major types of assets needed to
perform region-wide transmission and market operations. These assets
perform joint functions and at this point the Commission believes it
may be unduly burdensome to allocate the costs of these assets in
greater detail.

C. RTO Revenue Accounts

1. Accounting NOPR
    11. Revenues RTOs receive for the reimbursement of their
operational costs are not addressed in the current USofA because the
existing revenue accounts were designed principally to record revenues
from electricity sales on a bundled basis. Therefore, the Commission
proposed the creation of two new revenue accounts to record amounts
billed by RTOs to their members.\11\ The first, Account 457.1, Regional
Transmission Service Revenues, would include revenues received by RTOs
for services provided and amounts billed under each Commission-approved
tariff. The second, Account 457.2, Miscellaneous Revenues, would
include revenues received from incidental transactions and events, such
as profits or losses on sales of miscellaneous materials.
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    \11\ NOPR at P 33-35.
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    12. The Commission also proposes to include a new Form 1 Schedule
to report the revenue collected by RTOs for services performed pursuant
to Commission-approved tariffs.
2. Commenters
    13. Commenters are generally supportive of the proposed accounting
for RTO revenue accounts.\12\ However, one commenter suggests that the
Commission should create a mechanism and account for all revenues and
costs arising from managed market services and operations.\13\
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    \12\ See, e.g., APPA at 19, ISO/RTO Council at 2.
    \13\ See TANC at 12.
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    14. Another commenter asserts that RTO constituents have the right
to know how much of their RTO's revenues derive from penalties assessed
by the RTO.\14\ The commenter thus asserts that a new series of
accounts should be created to record RTO's revenue from penalties
assessed against market participants. According to the commenter, these
accounts should be further augmented by another, separate new sub-
account for neutrality charges assessed by the RTO.
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    \14\ See SVP at 20.
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3. Commission Conclusion
    15. We will adopt Account 457.1, Regional Transmission Service
Revenues, Account 457.2, Miscellaneous Revenues, and the RTO Revenue
Schedule as proposed in the NOPR. The Commission declines to adopt the
recommendation to amend the USofA to require RTOs to record revenues on
their books and records for energy products, services and

commodities associated with services that RTOs manage for market
participants. In these instances, an RTO acts as an agent in providing
these services; it does not realize or earn revenue on these
transactions. The RTO merely collects monies from one member or
participant and remits it to another member or participant. For
example, when a member or participant purchases energy through an RTO
managed centralized energy market, the RTO merely collects monies from
the purchaser of the energy and remits it or passes it through to the
appropriate energy supplier, who then records it as revenue.
    16. We also decline to adopt the recommendation to amend the USofA
to create separate sub-accounts of Account 457 to record penalty and
neutrality revenues. According to the instructions of the new RTO
revenue accounts, RTOs are to maintain records showing revenues
received from customers by type of charge. RTOs then must report any
penalty and neutrality revenues received on the newly-created RTO
Revenue Schedule adopted herein, providing adequate disclosure of these
revenues.

D. Regional Market Expense Function

1. Accounting NOPR
    17. In the NOPR, the Commission explained that the current USofA
does not provide sufficient financial transparency concerning the types
of costs incurred by RTOs in facilitating and monitoring energy
markets. In order to address this deficiency the Commission proposed
creating a separate new expense function within the USofA to capture
these types of costs in greater detail.\15\ As part of this new
function, the Commission proposed the creation of certain operating
expense accounts to capture the costs of managing the various RTO
markets and reviewing market data to determine compliance with market
rules. These accounts are Account 575.1, Operation Supervision; Account
575.2, Day-Ahead and Real-Time Market Facilitation; Account 573.3,
Transmission Rights Market Facilitation; Account 575.4, Capacity Market
Facilitation; Account 575.5, Ancillary Services Market Facilitation and
Account 575.6, Market Monitoring and Compliance.
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    \15\ NOPR at P 36-51.
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    18. Additionally, new accounts were proposed to capture and provide
greater detail as to the amount of maintenance expense incurred on
computer hardware, software, communication equipment and other assets
owned and used by RTOs. These accounts are Account 576.1, Maintenance
of Structures and Improvements; Account 576.2, Maintenance of Computer
Hardware; Account 576.3, Maintenance of Computer Software; Account
576.4, Maintenance of Communication Equipment and Account 576.5,
Maintenance of Miscellaneous and Market Operation Plant.
    19. Finally, the Commission proposed that RTOs report in Form 1 the
data required by the Transmission of Electricity for Others schedule
\16\ to provide more complete information concerning the use of the
transmission system under the control of the RTO.
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    \16\ See FERC Form 1 at 328-330.
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2. Commenters
    20. Most commenters did not object to the Commission's proposal to
create a new regional market expense function.\17\ However, some
commenters suggest that the Commission clarify that the regional market
expense function accounts apply solely to RTOs, as the proposed new
regulatory text contained in the NOPR does not make this clear.\18\
Additionally, one commenter suggests that the Commission change the
descriptive caption of this function from ``regional market operations
expense'' to ``market operations expense.'' \19\ This commenter submits
that these accounts should not be limited to RTOs, as other public
utilities in the future may use market oriented approaches to provide
these services.
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    \17\ See, e.g., ISO/RTO Council at 2.
    \18\ See, e.g., EEI at 2.
    \19\ See APPA at 18.
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    21. One commenter also suggests that the word ``facilitation'' in
the title of Accounts 575.2, 575.3, 575.4 and 575.5, be changed to
``administer'' as RTOs administer or operate organized markets while
``facilitation'' describes a more passive role than is the case.\20\
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    \20\ APPA at 19.
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    22. Additionally, one commenter suggests that the Commission
require RTOs to record and report revenues and expenses related to the
cost of energy, energy products, services and commodities that RTOs
manage or provide to market participants.\21\ Another commenter
suggests that RTO customer service costs be recorded separately in a
newly-created account; \22\ customer service costs are a significant
component of RTO expense identified by public utilities and it is
important for RTO/non-RTO customer services expenses to be segregated.
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    \21\ TANC at 2 and SVP at 27.
    \22\ NRECA at 8.
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    23. Finally, most commenters did not object to the proposal to
require RTOs to report the data required by the Form 1 Transmission of
Electricity for Others schedule. However, one commenter asserts that
RTOs do not currently organize transaction data in a way that would
allow them to report the information called for by the schedule.\23\
This commenter notes that RTOs treat most service in their footprint as
network service and as such can only report aggregate flows without
transaction specific source and sink information. The commenter
contends that absent extremely expensive software and design changes
RTOs will not be able to fully report the information called for on the
schedule. The commenter recommends that the Commission not include this
requirement in the Final Rule or in the alternative clarify that
aggregate flow data will be acceptable.
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    \23\ See ISO/RTO Council at 5.
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3. Commission Conclusion
    24. The Commission will adopt the regional market expense function
and accounts proposed, as modified and clarified below. Upon additional
consideration, the Commission clarifies that any jurisdictional entity,
whether an RTO or a non-RTO public utility, must use the regional
market expense accounts if a regional market expense is incurred. The
key for recording costs in these accounts is not whether an entity is
an RTO or not, but whether an entity is performing market services on a
region-wide basis. The accounts are intended to capture costs incurred
in performing region-wide services related to market administration,
market monitoring and market compliance activities whether performed by
an RTO or another non-RTO public utility. These accounts are not
limited to RTOs, as other non-RTO jurisdictional entities may provide
these market services, and the costs incurred by these other non-RTO
jurisdictional entities in performing these services must be captured
in these accounts. The Commission will add a definition of regional
market to the USofA to make clear which type of entities are to use the
regional market expense function accounts. The Commission clarifies
that regional market expense accounts are to be used not only by RTO/
ISO public utilities but by any public utility that operates an
organized energy market, whether directly or through a contractual
relationship with another entity.
    25. The Commission will modify the account titles and instructions
to replace the word ``facilitation'' with ``administer'', as we agree
with the

commenter that it is more descriptive of the role RTOs play (and others
may play) in market operations.
    26. The Commission declines to adopt commenter recommendations to
amend the USofA to require the RTOs to record expenses on their books
and records for energy products, services and commodities associated
with services that RTOs manage for market participants. As previously
discussed, an RTO acts as an agent and does not take title to energy
products, services and commodities associated with services in the
performance of these managed services. The RTO merely collects monies
from one member or participant and remits it to another member or
participant.
    27. The Commission also declines to adopt one commenter's
suggestion to create new accounts to separately record RTO customer
service costs. Our existing accounting rules contain customer service
expense accounts for recording costs of this nature, Accounts 901-910
(Customer Accounts and Customer Service Accounts). RTOs are required to
record their customer service expenses in the appropriate existing
customer service accounts. Therefore, it is not necessary to create new
accounts for this purpose.
    28. One commenter asserts that RTOs cannot provide all of the
information required on the Form 1 Transmission of Electricity for
Others schedule absent costly software changes to their systems; most
of the transmission service in their footprint is network service and
as such RTOs do not currently maintain transaction specific source and
sink information in a format needed to complete the schedule. However,
RTOs can provide aggregate power flow information for the transmission
facilities under their control.
    29. We will, therefore, require RTOs to report aggregate
transmission usage information for imports into the RTO from other
systems, exports from the RTO, through and out service, network service
and point-to-point service. We will also require RTOs to report related
financial information by type of service, such as network and point-to-
point service. These changes we adopt herein will give the Commission
more complete information concerning the use of the transmission system
under the control of RTOs, without requiring RTOs to make costly
software changes. We will require the transmission usage information to
be reported on a new Form 1 and Form 3-Q schedule entitled Monthly ISO/
RTO Transmission System Peak Load and the related financial information
on a newly created schedule entitled Transmission of Electricity by
RTOs, rather than have RTOs report the information on the Form 1
Transmission of Electricity for Others schedule which is not a good fit
for reporting this aggregate information.
    30. In examining the new regional market expense function, we
recognize a rent account is needed to capture the expenses associated
with renting assets to perform regional market functions to be
consistent with our other function classifications. Therefore, we will
also add a new account entitled Account 575.8, Rents, to capture rent
costs in the regional market expense function.

E. Accounting by Public Utilities for Computer Hardware, Software and
Communication Equipment

1. Accounting NOPR
    31. In the NOPR, the Commission proposed to add three new sub-
accounts to the existing transmission asset function for public
utilities and licensees, other than RTOs, to record the cost of
computer hardware, software and communication equipment owned and used
for transmission related activities.\24\ The Commission proposed to
create Account 351.1, Computer Hardware, Account 351.2, Computer
Software, and Account 351.3, Communication Equipment, so as to provide
uniform and consistent accounting and reporting for these types of
assets by non-RTO public utilities and licensees.
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    \24\ NOPR at P 52-53.
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2. Commenters
    32. Commenters generally argue that the proposed changes would
impose a significant burden on companies; \25\ companies will face a
complex undertaking in identifying what portions of their computer
hardware, software and communications equipment and operation and
maintenance costs belong in the new transmission accounts because most
companies rely on such hardware, software, and equipment for multiple
purposes.\26\ One commenter suggests that the Commission appears to
have overlooked the fact that public utilities perform many more
functions than simply transmission functions.\27\
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    \25\ See EEI at 4, SCE at 2, FirstEnergy at 8.
    \26\ EEI at 9.
    \27\ SCE at 2.
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    33. Commenters assert that the new accounts for computer equipment
and computer use will require judgments as to disaggregation and
assignment of these costs among different accounts \28\--costs that are
not necessarily severable and directly assignable. Commenters also
assert that these allocations will be unnecessarily arbitrary and the
Commission's desire for comparability will never be achieved.\29\
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    \28\ International Transmission at 5.
    \29\ FirstEnergy at 17.
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    34. Commenters recommend that, due to the extreme burden the
proposed changes would place on public utilities, these changes should
be applied only to RTOs, whose sole business is related to performing
transmission functions.\30\ Commenters note that the RTOs' primary
function is the administration of transmission systems and the use of
their hardware, software and communication equipment is more easily
identifiable as transmission related.\31\
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    \30\ SCE at 3.
    \31\ FirstEnergy at 16.
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    35. Commenters also suggest that, if the Commission retains the
proposed new computer and communication equipment accounts for use by
licensees and public utilities other than RTOs, that it provide
companies the flexibility to make reasonable allocations to the new
accounts and other accounts in the USofA, including the general plant
accounts.\32\ Commenters also suggest that companies should be able to
adopt the new accounts in a way that makes sense given their
circumstances, with as little extra effort as possible, without having
to perform complex allocations, and without having to modify prior
accounting records and reports.
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    \32\ EEI at 9.
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    36. Another commenter suggests that new sub-accounts should be set
up to record the additional computer hardware, software and
communications equipment required to interface with the RTO.\33\ This
commenter suggests that these sub-accounts should record and disclose
the amount of information and technology and communications spending
that relates specifically to the public utility's RTO interface.
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    \33\ SVP at 35.
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    37. Finally, one commenter also notes that the Commission proposes
to add new sub-accounts to Account 569, Maintenance of Structures,
namely Account 569.1, Maintenance of Computer Hardware, Account 569.2,
Maintenance of Computer Software, and Account 569.3, Maintenance of
Communication Equipment. The commenter suggests that the more
appropriate account for these sub-accounts would be Account 573,
Maintenance of Miscellaneous Transmission Plant (Major only),

making them sub-accounts Account 573.1 though Account 573.3.\34\
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    \34\ EEI at 9.
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3. Commission Conclusion
    38. The great majority of commenters disagree with the NOPR's
proposed accounting for computer hardware, software and communication
equipment by public utilities and licensees other than RTOs. These
commenters argue that these assets are not necessarily severable and
directly assignable. They point out that the equipment and software in
question perform many different functions and that it would be
extremely difficult to determine what portion of the equipment and
software perform a transmission function. These commenters also argue
that individual utilities may use different allocation methods to
determine the portion of these items used in transmission, which will
reduce comparability among utilities and therefore the usefulness of
the reported accounting information. Finally, these commenters contend
that it will be burdensome and costly to implement the proposed changes
and that minimal reporting benefits will be derived from the change.
    39. The Commission acknowledges that some or perhaps most computer
hardware, software and communication assets are joint use assets that
may not be severable or directly assignable to the transmission
function. We agree with commenters that requiring entities to record
that portion of their investments in these assets used for transmission
purposes within the transmission function on an allocated basis is
problematic in that functional reclassification of the investment, as
well as the related depreciation reserve, would be required each
accounting period as the allocation factor changes. Therefore, we have
decided not to adopt proposed Accounts 351.1, 351.2 and 351.3 for
public utilities and licensees other than RTOs and will continue to
allow non-RTO public utilities to account for these items as joint use
assets as they have historically done. However, we will require both
RTOs and non-RTO public utilities to record the costs of maintaining
these assets that are related to providing transmission services in
Accounts 569.1, 569.2 and 569.3 as proposed. Non-RTO public utilities
already allocate these joint use costs for ratemaking purposes in
determining open access transmission rates. We will now also require
that public utilities allocate these costs for accounting purposes.
    40. Allocation approaches used by public utilities must ensure that
a reasonable portion of the cost of maintaining these joint use assets
are used in the transmission of electricity are allocated to the
transmission function. Additionally, public utilities are also expected
to allocate these costs to the transmission function on a consistent
basis from year to year. Public utilities will be required to footnote
their allocation method used to calculate these maintenance expenses as
reported in the Form 1 Electric Operation and Maintenance Expenses
Schedule (pages 320-323).
    41. Finally, we decline to adopt one commenter's suggestion that
instead of adding sub-accounts to Account 569, Maintenance of
Structures, that we add sub-accounts to Account 573, maintenance of
Miscellaneous Transmission Plant, for the maintenance costs related to
computer hardware, software and communication equipment. The commenter
provides no explanation for the proposed change and we see no benefit
in deviating from the account structure originally proposed.

F. Accounting and Financial Reporting by Public Utilities, Including
RTOs

1. Accounts for Load Dispatching, Scheduling and System Control
Expenses
i. Accounting NOPR
    42. In the NOPR, the Commission proposed to replace Account 561,
Load Dispatching, with a series of detailed expense accounts to record
expenses for providing transmission services related to load
dispatching, scheduling and system control.\35\ The proposed accounts
are Account 561.1, Load Dispatch-Reliability, to include the costs
incurred to manage the region-wide reliability coordination function;
Account 561.2, Load Dispatch-Monitor and Operate Transmission System,
to include the costs incurred to monitor, assess and operate the
transmission system and ensure the system's reliability and Account
561.3, Load Dispatch-Transmission Service and Scheduling, to include
the costs incurred to process hourly, daily, weekly and monthly
transmission service requests using an automated system such as an Open
Access, Same-Time Information System (OASIS).
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    \35\ NOPR at P 54, 56-59.
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ii. Commenters
    43. One commenter asserts that the Commission should not apply the
proposed USofA changes to transmission owners that are members of an
RTO or ISO, as doing so will increase the cost to consumers for the
implementation of these systems, while providing little additional
information to the Commission.\36\ This commenter also asserts that it
may be difficult to disaggregate expenses among the proposed new Load
Dispatch sub-accounts (561.1, 561.2, and 561.3), because the same staff
members may perform functions included under more than one of these
sub-accounts, tasks undertaken to accomplish functions relevant to one
sub-account may also contribute to completion of another, and the
descriptions of the sub-accounts are insufficiently detailed.\37\ This
commenter further asserts that if the Commission does decide to apply
the proposed USofA changes to utilities that are members of RTOs and
ISOs, it should allow those utilities to apply for a waiver to allow
consolidated reporting of load dispatch expenses if they fall below a
de minimus threshold.\38\
---------------------------------------------------------------------------

    \36\ NYTOs at 2.
    \37\ Id. at 7.
    \38\ Id. at 10.
---------------------------------------------------------------------------

    44. Another commenter asserts that the lines of demarcation between
costs in these sub-accounts are not clear and that the Commission
should provide additional guidance on its intention as to information
to be captured in these sub-accounts.\39\ Yet another commenter notes
that, while it supports the Commission's goal of greater cost
transparency, it similarly recommends that the Commission provide
further guidance so that the useful cost comparisons that the
Commission is seeking to facilitate can be made across RTOs and public
utilities.\40\ This commenter asserts that the addition of accounts to
reporting forms will be of little use if users are not populating those
accounts with comparable costs and information. This commenter
recommends that the Commission provide additional guidance regarding
the specific information it would like captured in these sub-accounts.
---------------------------------------------------------------------------

    \39\ EEI at 8.
    \40\ International Transmission at 3.
---------------------------------------------------------------------------

    45. One commenter supports the specific account structure the
Commission proposes, as well as its applicability to both RTOs and non-
RTO public utilities. However, that commenter suggests the Commission
realign the grouping of the new accounts under two new functions
(system control and transmission services) that it proposes should be
created.\41\
---------------------------------------------------------------------------

    \41\ APPA at 19.
---------------------------------------------------------------------------

    46. Finally, a commenter notes that, in the text of the NOPR's
discussion of Accounts 561.1, 561.2 and 561.3, the

NOPR states that these proposed accounts are for use by both non-RTO
public utilities and RTOs.\42\ However, in the proposed text of the
USofA for Accounts 561.1, 561.2 and 561.3, the proposed language
specifically states that the accounts are to include expenses incurred
by the regional transmission service provider, with no mention in the
proposed text of non-RTO public utilities. The commenter suggests that
the Commission revise the proposed text of the USofA for proposed
Accounts 561.1, 561.2 and 561.3 to specifically state that the accounts
may be used by RTOs, other public utilities and licensees, consistent
with the NOPR's language.
---------------------------------------------------------------------------

    \42\ See SCE at 3.
---------------------------------------------------------------------------

iii. Commission Conclusion
    47. The proposed accounts for recording load dispatch, scheduling
and system control expenses provide greater transparency concerning the
types of costs incurred by both RTOs and non-RTO public utilities in
providing transmission services. Therefore, we will adopt the proposed
accounting for load dispatch, scheduling and system control expenses.
However, based upon the comments received, we will adopt the proposed
accounting with certain clarifications and modifications as discussed
below.
    48. The instructions to Accounts 561.1, 561.2 and 561.3 are revised
to make clear that the accounts are to be used by both RTOs and non-RTO
public utilities. Additionally, the items list of Account 561.2 has
been revised to include certain items included in replaced Account 561,
Load Dispatching, which were inadvertently not included on the list.
These modifications add clarity as to which entities are to use the
accounts and what types of costs are to be recorded in the load
dispatch, scheduling and system control expense accounts.
    49. We will not adopt one commenter's suggestion to realign the
newly created accounts under its suggested new functions: system
control and transmission service. The expanded expense accounts
contained in the transmission function provide the requisite
transparency concerning the activities and related costs incurred by
public utilities, including RTOs, in providing transmission service for
ratemaking and other Commission purposes. Moreover, the account
structure appropriately herein adequately separates market service and
transmission service activities.
    50. Finally, we clarify that, to the extent that RTOs and non-RTO
public utilities perform the same activities for load dispatch,
scheduling and system control, then the costs of those activities
should be accounted for in the same manner and recorded in the same
accounts. For example, if an RTO incurs costs to manage the region-wide
reliability coordination function it would record those costs in
Account 561.1. Likewise, if a non-RTO public utility happens to incur
costs to manage the reliability coordination function for third
parties, it would also record those costs in Account 561.1.
2. Accounts for System Planning and Standards Development
i. Accounting NOPR
    51. In the NOPR, the Commission proposed to add a new Account
561.5, Long-Term Reliability Planning and Standards Development, to
record the costs incurred by RTOs for performing long-term system
planning and standards development.\43\
---------------------------------------------------------------------------

    \43\ NOPR at P 60-62.
---------------------------------------------------------------------------

ii. Commenters
    52. Some commenters request clarification of the Commission's
proposed changes.\44\ These commenters suggest that the definition
provided in the NOPR does not provide a definitive basis to identify
the costs to be recorded in this account because planning can be
interpreted to have several meanings. National Grid requests that the
Commission recognize that the scope of costs covered by Account 561.5
is likely to vary from region to region and clarity should be provided
about the meaning of ``long-term system planning.'' They explain that
transmission planning occurs over several different time-scales such as
short-term planning to intermediate planning to long term planning.\45\
Indicated NYTOs request a waiver for transmission owners that are RTO
members to allow consolidated reporting of de minimus amounts or
alternatively guidance on the specific expenses to be recorded in the
account.\46\
---------------------------------------------------------------------------

    \44\ See, e.g., National Grid at 9-10.
    \45\ National Grid at 9-10.
    \46\ See Indicated NYTO at 9-10.
---------------------------------------------------------------------------

    53. Other commenters support the proposed changes but believe the
Commission should require additional accounts to offer more
transparency and comparability. Specifically one commenter believes
that Account 561.5 should be augmented by additional accounts for the
portion of system planning, development and maintenance expenses that
relate to market design initiatives and activities of RTOs, as opposed
to control area operation.\47\
---------------------------------------------------------------------------

    \47\ See City of Santa Clara, California at 21-22.
---------------------------------------------------------------------------

    54. Finally, one commenter believes that the structure of this new
account allows for inclusion of generation-related costs such as
resource planning.
iii. Commission Conclusion
    55. As the Commission explained in the NOPR, the existing USofA
does not provide a specific expense account to record expenses for
system planning and development activities. The Commission will adopt
Account 561.5 as proposed as modified and discussed below. Commenters
raise questions about the scope of planning costs that are to be
recorded in Account 561.5 and how to record costs incurred relative to
the different transmission planning time-scales, such as short-term,
intermediate-term, and long-term. We will modify the instructions to
Account 561.5 to allow inclusion of all transmission system planning
time-scale planning costs, not just long-term planning. We will
therefore modify the title of the account to Account 561.5,
Reliability, Planning and Standards Development, to reflect the fact
that planning costs other than long-term are to be recorded in Account
561.5.
    56. RTOs are directed to report costs of system planning,
development, and maintenance expenses in Account 561.5. We clarify to
the extent that public utilities and licensees that are not RTOs
perform similar activities; they should also include the costs that
they incur for system planning and standards development in Account
561.5. We also clarify that all system planning and standards
development costs recorded in this account are to be transmission
related.
    57. The Commission declines at this time to augment Account 561.5
with additional accounts for the portion of system planning,
development and maintenance expenses that relate to market design
initiatives and activities of RTOs, as opposed to control area
operation. We have created a new regional market expense function and
all market planning and development costs shall be recorded in the
appropriate market expense account based on the nature of the planning
and development costs incurred.
3. Proposed Accounts for Study Costs
i. Accounting NOPR
    58. The USofA does not specially provide accounts for recording
costs incurred to perform generation interconnect and transmission
service studies. Therefore, the Commission

proposed to create Account 561.6, Transmission Service Studies, to
record the costs incurred by public utilities and licensees, including
RTOs, to conduct studies for transmission service requests. The
Commission also proposed to add a new Account 561.7, Generation
Interconnection Studies, to record the costs incurred by public
utilities and licensees, including RTOs to conduct studies for
generator service requests.\48\
---------------------------------------------------------------------------

    \48\ NOPR at P 63.
---------------------------------------------------------------------------

    59. Additionally, in order to provide more disclosure concerning
the costs of interconnect study activities being performed by public
utilities and licensees, including RTOs, the Commission proposed to add
a new schedule to the quarterly and annual financial reports that will
provide more specifics concerning the costs of these activities.\49\
---------------------------------------------------------------------------

    \49\ Id. at P 64.
---------------------------------------------------------------------------

ii. Commenters
    60. Commenters were of divergent views regarding the Commission's
proposal to record costs to perform generation interconnect and
transmission service studies in Account 561.6 and Account 561.7.
Commenters state that it is not clear whether the proposed shift in
accounting treatment of study costs could affect the billable or
capital treatment of the underlying study costs. Commenters state that
the costs of transmission service studies and generator interconnection
studies are largely reimbursed by customers or folded into the capital
accounting for transmission projects or upgrades, and would only be
expensed in rare circumstances.\50\ One commenter requests that the
Commission clarify that the new expense accounts for study costs are
not intended to cover all study costs, but only those costs that are
neither reimbursed by customers nor capitalized. Alternatively, this
commenter requests clarification that utilities may still charge out or
capitalize such study costs as they have in the past.\51\ Another
commenter requests that the Commission exempt RTO member utilities from
the proposed USofA changes for study costs because it provides little
additional information. Alternatively, this commenter requests a waiver
to eliminate reporting study costs in Account 561.6 and Account 561.7
because the costs are largely reimbursed by the RTO and will appear in
the RTO financial reports. Additionally, this commenter requests that
the cost of transmission service and generator interconnect studies be
treated as capital expenditures.\52\
---------------------------------------------------------------------------

    \50\ National Grid at 10-12, Indicated NYTOs at 6-10.
    \51\ National Grid at 10-12.
    \52\ Indicated NYTOs at 6-10.
---------------------------------------------------------------------------

iii. Commission Conclusion
    61. The Commission will adopt the proposed accounts for recording
generation interconnection and transmission service study costs as
clarified below. We clarify that Accounts 561.6 and 561.7 are only to
be used to record the costs incurred by public utilities, including
RTOs, to conduct studies for transmission service requests and
generator service requests, respectively, when the costs are not
directly reimbursable by a specific customer and the costs are
otherwise charged to expense under the USofA.
    62. Additionally, we clarify that the Commission did not propose
any change and does not do so now related to the recording of the costs
of conducting transmission and generation interconnect studies in
Account 186, Miscellaneous Debits, by public utilities, including RTOs,
pending reimbursement by the entity requiring the service. We further
clarify that the Commission did not intend to change any capitalization
requirements related to study costs. Public utilities are to continue
to follow the Commission's existing rules and regulations for cost
capitalization.
4. Accounts for RTO Billings
i. Accounting NOPR
    63. In the NOPR, the Commission proposed to create three new sub-
accounts in order to provide greater transparency for the payments made
by public utilities and licensees to RTOs. The three new proposed sub-
accounts are Account 561.4, Scheduling, System Control and Dispatching
Services; Account 561.8, Reliability Planning and Standards Development
Services; Account 575.7, Market Facilitation, Monitoring and Compliance
Services.\53\ The proposed new sub-accounts will be used by public
utilities and licensees to record their share of costs billed to them
by an RTO. Additionally, the Commission proposed that each RTO include
in its monthly settlement statements a breakdown of the allocation of
that RTO's operational costs within each of the three sub-accounts
discussed below.
---------------------------------------------------------------------------

    \53\ NOPR at P 65-68.
---------------------------------------------------------------------------

ii. Commenters
    64. Commenters generally agree that non-RTO public utilities should
record in separate sub-accounts the charges paid to RTOs and suggest
that the Commission add more sub-accounts to separately disclose
additional costs incurred by non-RTO public utilities.\54\
---------------------------------------------------------------------------

    \54\ See City of Santa Clara, California at 25-26, EEI at 7-8.
---------------------------------------------------------------------------

    65. One commenter seeks clarification of the Commission's intent
with respect to proposed Account 575.7 Market Facilitation, Monitoring
and Compliance Services.\55\ This commenter questions if the Commission
intends that only costs billed to utilities by the RTOs be included in
this account, not including costs by utilities performing functions
that meet the description of the account. The commenter explains that
decisions made regarding rate recovery of Balancing Authority costs by
transmission owners are likely to depend heavily on how relevant costs
are recorded and requests that the Commission clarify that Account
575.7 is only applicable to costs billed to utilities by RTOs.
---------------------------------------------------------------------------

    \55\ First Energy at 17.
---------------------------------------------------------------------------

    66. Finally, one commenter requests that the Commission not adopt
an absolute rule that information on the three new cost sub-accounts be
part of the settlement statements.\56\ This commenter believes it will
be expensive to include such cost breakdowns in monthly customer
settlement statements. This commenter states that RTOs have
sophisticated billing software that is not easy to modify and that a
number of RTOs would have to make expensive and time-consuming changes
to their billing systems in order to incorporate the required cost
information directly into monthly settlement statements. This commenter
suggests that a more flexible approach would recognize the reality that
different RTOs have different software capabilities and allow each
entity to comply with the Commission's requirement in their own
efficient way.
---------------------------------------------------------------------------

    \56\ See ISO/RTO Council at 3-4.
---------------------------------------------------------------------------

iii. Commission Conclusion
    67. The Commission will adopt the new accounts for RTO billings
proposed in the NOPR with the modification discussed below. As the
Commission explained in the NOPR, these new accounts will allow each
RTO member to record its share of the RTO's total monthly operating
costs in these new sub-accounts. The Commission will also require each
RTO provide a breakdown of the allocation of that RTO's operational
costs within each of the three sub-accounts. However, the Commission
will not require RTOs to include this information in its monthly
settlement statements because of software costs to implement changes to

the RTO billing systems. Instead, the Commission will permit RTOs to
use another format to provide the information to its members. However,
RTOs are nevertheless directed to provide a breakdown of the cost
allocation to the three new sub-accounts on the date the billings are
issued.
    68. The Commission also clarifies that Account 575.7 is to be used
only for costs billed to utilities by RTOs for market administration,
monitoring and compliance services.
5. Account for Revenue From Transmission of Electricity
i. Accounting NOPR
    69. In the NOPR, the Commission proposed to add a new sub-account
to Account 456, Other Electric Revenues, in order to provide greater
transparency by transmission owners for the revenues received for use
of their transmission facilities.\57\
---------------------------------------------------------------------------

    \57\ NOPR at P 73-74.
---------------------------------------------------------------------------

ii. Commenters
    70. Commenters were generally supportive, but request that the
Commission provide additional clarification.\58\ One commenter requests
that the Commission provide even more transparency regarding the
particular sources of those revenues and how they relate to common
ratemaking categories. This commenter suggests the Commission implement
accounting for transmission revenues that would enable customers and
the Commission to monitor whether previously accepted rates generate
more than an appropriate level of revenues. This commenter requests
that the Commission remedy its accounting and reporting, in this
proceeding, to keep pace with standard ratemaking practice so that Form
1 information provides accounting data for direct ratemaking use.\59\
Another commenter requests the Commission clarify that non-RTO public
utilities should use the new Account 456.1 for transmission service
revenues and existing Account 456 for miscellaneous revenues.
---------------------------------------------------------------------------

    \58\ TAPS at 6-8, International Transmission at 7.
    \59\ TAPS at 6-8.
---------------------------------------------------------------------------

iii. Commission Conclusion
    71. The Commission will adopt the new sub-account as proposed in
the NOPR. The new Account 456.1, Revenues From Transmission of
Electricity of Others, will include revenues the transmission owner
receives for the transmission of electricity over its transmission
facilities. This new account will provide greater transparency with
respect to the revenues received by transmission owners for use of
their transmission facilities. We also clarify that revised Account 456
is to be used for recording non-transmission miscellaneous operating
revenues.
6. Accounting for Settlement Amounts
i. Accounting NOPR
    72. In the NOPR, the Commission proposed that public utilities or
licensees that conduct energy transactions through an RTO that requires
participants to bid their generation into the market and buy generation
to supply their native load report these transactions on a net basis in
Account 555, Purchased Power.\60\ The Commission also invited comment
as to what circumstances would be appropriate for a public utility or
licensee to reflect these types of transactions on a net basis, and
under what circumstances would it be appropriate for a public utility
or licensee to reflect these types of transactions as distinct
purchases and sales.
---------------------------------------------------------------------------

    \60\ NOPR at P 75-79.
---------------------------------------------------------------------------

ii. Commenters
    73. Two commenters do not support the netting of transactions that
flow through RTO energy markets.\61\ One of these commenters argues
that for accounting and tax purposes, purchased power should, on
financial statements, represent only purchased power. This commenter
also asserts that its members that are subject to Rural Utilities
Service (RUS) oversight need to be able to report gross amounts of
energy sales to RUS. This commenter further asserts that it will be
difficult for cooperatives to determine income for income tax purposes
if only net transactions are reported.\62\ The other commenter argues
that showing only the net position of a market participant may
understate the use of RTO energy markets and mask situations where a
utility is a net seller during one period but a net buyer in another
period. This commenter also notes that netting would not reveal the
effects of time and location-specific variation in energy prices,
yielding only incomplete results that are unlikely to be
meaningful.\63\
---------------------------------------------------------------------------

    \61\ See APPA at 2, NRECA at 4.
    \62\ NRECA at 5.
    \63\ APPA at 2.
---------------------------------------------------------------------------

    74. Most other commenters, however, generally agree that these
transactions should be reported on a net basis.\64\ One commenter
submits that reporting these types of transactions on a gross basis
might give an inaccurate picture of an entity's size and its actual
revenue-generating activities.\65\ This commenter suggests that
accounting for transactions settled through RTO markets on a net basis
more accurately reflects what similarly situated utilities would be
doing in the absence of RTO markets. This commenter also suggests that
accounting on a gross basis would cause it to incur an artificially
large gross receipts tax liability which would act as a deterrent to
participation in RTO markets. This commenter further suggests that
accounting for these transactions on a net basis is in accord with
traditional accounting principles regarding whether to record
transactions on a gross or net basis.
---------------------------------------------------------------------------

    \64\ See First Energy at 15, MGE at 2, Wisconsin Electric at 3,
EEI at 6, APS at 3, Cinergy at 4, NYTOs at 12, SCE at 1.
    \65\ See MGE at 3.
---------------------------------------------------------------------------

    75. Some commenters support netting, but believe that it is
inappropriate to report net sales in Account 555.\66\ These commenters
assert that net sellers of generation should report the transactions in
Account 447, Sales for Resale, and that net purchasers should report
the transactions in Account 555, Purchase Power. One commenter notes
that consistent with the reporting methodology of its RTO it reports
sales and purchases of power on an hourly net position basis. For each
hour that the company is a net seller of power, the commenter states
that it reports the net amount in Account 447; conversely, if it is net
buyer of power, it reports the net amount in Account 555. In each
monthly reporting period, the commenter notes that the hourly Account
447 and/or Account 555 net amounts are aggregated and separately
reported in Account 447 and 555, respectively.
---------------------------------------------------------------------------

    \66\ EEI at 6, First Energy at 16, Wisconsin Electric at 4.
---------------------------------------------------------------------------

    76. Some commenters also recommend that the Commission allow
companies flexibility in determining net sales and/or purchases during
the relevant reporting period and for using the appropriate account or
accounts to display its net sales and/or purchases.\67\ One of these
commenters suggests that some companies may choose to net their
purchases and sales for the entire reporting period, while others may
reflect separately net purchases when the company was a net buyer and
net sales when it was a net seller.
---------------------------------------------------------------------------

    \67\ EEI at 7, First Energy at 16.
---------------------------------------------------------------------------

    77. On the other hand, one commenter suggests that the Commission
define a uniform method for the calculation of the gross amount of
sales versus purchases, whether it be

by the hour, day, week or month.\68\ This commenter argues that,
without such a standard, a wide range of interpretation and reporting
is likely to result.
---------------------------------------------------------------------------

    \68\ NRECA at 3.
---------------------------------------------------------------------------

    78. Another commenter asserts that netting should be allowed for
transactions in all RTO markets.\69\ This commenter suggests that the
Commission clarify that netting of purchases from and sales into an RTO
market is appropriate and allowed not only for transactions in an RTO
that requires participants to offer all resources to and buy all power
from the RTO, but for transactions in any RTO that offers an energy
market in which participants may choose to offer all generation to and
buy all power from the energy market. This commenter also suggests that
the Commission clarify that purchases from and sales to one or more RTO
markets may be netted against one another.
---------------------------------------------------------------------------

    \69\ MGE at 3.
---------------------------------------------------------------------------

    79. Finally, one commenter recommends that the Commission's
Electronic Quarterly Reports (EQR) and annual reports be revised to
match the accounting methodology using the Commission's USofA with the
required reporting format.\70\ While another commenter notes that there
is a disconnect between the reporting of transactional data in the EQRs
and reporting of the data in the FERC Form 1, stemming from how the
data are defined in those two contexts. This commenter recommends that
when the Commission next entertains revisions to one or the other of
the forms, the Commission should discuss this issue with reporting
entities to determine if some clarification aimed at conformity would
be appropriate.\71\
---------------------------------------------------------------------------

    \70\ Wisconsin Electric at 4.
    \71\ EEI at 7.
---------------------------------------------------------------------------

iii. Commission Conclusion
    80. Recording RTO energy market transactions on a net basis is
appropriate as purchase and sale transactions taking place in the same
reporting period to serve native load are done in contemplation of each
other and should be combined. Netting accurately reflects what
participants would be recording on their books and records in the
absence of the use of an RTO market to serve their native load.
Recording these transactions on a gross basis, in contrast, would give
an inaccurate picture of a participant's size and revenue producing
potential. The Commission will, therefore, adopt the proposed
accounting for RTO energy market transactions with certain
modifications and clarifications as discussed below. The Commission
does expect public utilities, however, to maintain detailed records for
auditing purposes of the gross sale and purchase transactions that
support the net energy market amounts recorded on their books.
    81. Additionally, we clarify that transactions are to be netted
based on the RTO market reporting period in which the transaction takes
place. For example, if the RTO market in which the transaction takes
place uses an hourly period for determining energy market charges and
credits, then non-RTO public utilities purchasing and selling energy in
the market must net transactions on an hourly basis. Requiring
participants to net transactions over the RTO market's reporting period
leads to consistent and comparable energy market information for
decision making purposes by the Commission and others.
    82. Further, we clarify that the netting of purchases and sales in
an RTO energy market is appropriate not only for transactions where
participants are required to bid their generation into the market and
buy generation from the market to supply their native load, but also in
cases where an RTO offers an energy market in which participants may
choose to offer all generation to and buy all power from the energy
market.
    83. We also clarify that if a participant is a net seller, rather
than a net buyer, during a given market reporting period it must credit
such net sales to Account 447, Sales for Resale, instead of Account
555, Purchased Power.
    84. Finally, one purpose of this rule is to establish uniform
accounting requirements for the purchase and sale of energy in RTO
markets. The purpose of reporting of gross information in EQRs, in
contrast, is to provide the Commission and the public with a more
complete picture of wholesale market activities which affect
jurisdictional services and rates, thereby helping to monitor for any
market power and to ensure that customers are protected from improper
conduct. These are not necessarily the same criteria and principles
that should be used in establishing uniform accounting requirements. In
any event, the reporting of wholesale market activity in EQRs falls
outside the scope of this rule.
7. Ministerial Filings
    85. Some commenters argue that certain revisions to the USofA will
adversely affect the Attachment O formula rate which is used by the
vast majority of the transmission owners in the Midwest ISO and other
formula rates that rely on the USofA and Form 1 data for the rate
inputs.\72\ Specifically, for the Midwest ISO, new accounts or
renumbered accounts may cause disruptions in the operation of the
Attachment O formula rate, especially if there is no parallel revision
to Attachment O to reflect these changes. Some commenters therefore
request that the Commission clarify that it will accept ``ministerial''
filings in order to conform these formula rates to the final revisions
of the USofA.\73\
---------------------------------------------------------------------------

    \72\ See FirstEnergy at 13, International Transmission at 4, EEI
at 10.
    \73\ See FirstEnergy at 1-2, 13-15, International Transmission
at 3-4.
---------------------------------------------------------------------------

    86. In particular, FirstEnergy, among others, has expressed concern
that the Commission ensure that the revisions to its accounting and
financial reporting requirements will not provide an opportunity for
challenges to Commission-approved formula rates nor shall the
Commission entertain such challenges to these previously-accepted
rates.\74\ Therefore, the Commission should state that it will accept
``ministerial'' filings necessary to conform to the Final Rule all
Commission accepted formula rates that rely on Form 1 inputs.
FirstEnergy further argues that the Commission should provide a
specific timeline to allow such filings but coordinate the respective
effective dates of the rate filings and reporting changes to ensure
that there is no gap in cost recovery.\75\ International Transmission
requests that the Final Rule establish a compliance filing process,
rather than allow a Federal Power Act section 205 filing,\76\ so that
there will be no challenges to ministerial filings in order for public
utilities to revise the formula rate templates.\77\
---------------------------------------------------------------------------

    \74\ International Transmission at 3-4, FirstEnergy at 14.
    \75\ FirstEnergy at 14.
    \76\ 16 U.S.C. 824d (2000).
    \77\ International Transmission at 4.
---------------------------------------------------------------------------

Commission Conclusion
    87. We will allow revisions to tariffs to conform to the changes
adopted here, but pursuant to section 205. We will, however, consider
only comments that address the specific revisions necessary to comply
with these accounting and reporting revisions. By narrowly focusing the
scope of the filings and of the comments to only those changes
necessary to conform to this Final Rule, public utilities can be
assured that commenters cannot otherwise and inappropriately challenge
the reasonableness of their Commission-approved and accepted formula
rates.
    88. We also find that any necessary revisions to formula rates in
order to

conform to the Final Rule should not increase rates. The requisite
changes to Attachment O, for example, would be the result of the new
accounts and would solely reflect accounting changes adopted in this
Final Rule. Such changes also should not involve substantive changes to
the way the formula rates operate or the way the charges are
calculated.
8. Cost Oversight
    89. The Commission received multiple comments regarding cost
oversight in response to the accounting and financial reporting NOPR.
Commenters assert that the restructuring of the electric industry will
only benefit consumers if transmission organizations are subject to
greater efficiency and accountability.\78\ As the National Rural
Electric Cooperative Association (NRECA) states, ``[t]he absence of
common standards and rules currently hampers meaningful examination of
the cost-effectiveness of the products and services that RTOs/ISOs
offer.'' \79\
---------------------------------------------------------------------------

    \78\ See, e.g., ELCON at 1, IESO at 2.
    \79\ See NRECA at 2.
---------------------------------------------------------------------------

    90. Commenters have also included general suggestions to the
Commission, which they argue, would not only enhance and facilitate
transparency and comparability of RTO finances, but could also be an
integral first step towards controlling RTO operational costs. Among
other things, commenters have suggested that the Commission require
RTOs to include a detailed analysis of their business risks and
opportunities as part of their periodic financial reporting.\80\
---------------------------------------------------------------------------

    \80\ Indicated NYTOs at 2, 5-6.
---------------------------------------------------------------------------

    91. A few commenters also urge the Commission to continue its
efforts in reviewing the cost oversight and accountability in the
budgeting and expenditure process that RTOs utilize.\81\ Revision of
the USofA represents only a partial solution in providing adequate
transparency and accountability in RTO financial reporting.
---------------------------------------------------------------------------

    \81\ See, e.g., NEPOOL Participants Committee at 1-5.
---------------------------------------------------------------------------

    92. Commenters have expressed concern that the Commission's
proposed revisions fall short in meeting the goal of ensuring that the
costs of the RTOs are legitimate and reasonable.\82\ Cinergy has
therefore, for example, proposed that RTOs annually file with the
Commission a formula cost assignment template which supports the
projected RTO costs by billing schedule for a twelve month period. This
report, Cinergy explains, would include detailed projected direct costs
and a proposed assignment/allocation of overhead costs to the specific
schedule. This would provide parties with an opportunity to comment and
prior Commission approval would be required before the RTO could
proceed with the expenditure.
---------------------------------------------------------------------------

    \82\ See, e.g., Cinergy and Midwest ISO Transmission Owners.
---------------------------------------------------------------------------

    93. Midwest ISO Transmission Owners argue that the proposed
revisions to the USofA lack before-the-fact review of costs. They
contend that while after-the-fact review of costs is being done if an
RTO has a formula rate, it does not adequately respond to the needs of
these not-for-profit entities, as an entity's ``not-for-profit status
complicates a prudence review after the costs are incurred.'' \83\
Midwest ISO Transmission Owners therefore suggest that, in order to
keep the Commission and RTO members, as well as interested state
commission, abreast of estimated and actual expenditures and to provide
RTO members due process, the Commission should require approval before
the RTO incurs significant costs and also require regular reporting
after costs have been incurred.
---------------------------------------------------------------------------

    \83\ Midwest ISO Transmission Owners at 5, citing Midwest
Independent Transmission System Operators, Inc., 101 FERC ] 61,221
(2002).
---------------------------------------------------------------------------

Commission Conclusion
    94. We recognize that there are divergent views as to the best way
to accomplish the goals of this initiative. The accounting and form
changes adopted herein add visibility and uniformity to the accounting
and financial reporting for the costs of transmission and market
operation plant, and the expenses incurred and revenue received in
providing transmission and market services. The changes provide
comparability among RTOs and non-RTO public utilities that perform
region-wide transmission and market operations, and minimize
inconsistent reporting by RTOs and non-RTO public utilities. Further,
these revisions allow the Commission to better understand transactions
and events that affect RTOs and their members and non-RTO public
utilities.
    95. The Commission expects the changes in financial reporting to
lead to improvements in cost recovery practices by providing more
details concerning the costs of certain functions and increased
assurance that the costs are legitimate and reasonable costs of
providing service and assigned to the correct period for recovery in
rates. We believe the changes we are adopting herein are an important
first step. The concerns raised with regard to RTO cost oversight,
including the budgeting process, the expenditure process, and the
analysis of RTO business risks and opportunities are beyond the scope
of this proceeding. However, cost oversight practices are an important
aspect of the initiative we began with the NOI and we intend to address
those matters in the near future.
9. Other Matters
    96. The Commission noted in the NOPR that the derivative and asset
retirement accounts established under Order Nos. 627 and 631 were not
included in the Chart of Account listings contained in the USofA.\84\
The Commission here takes this opportunity to update the account
listing to include the accounts established under these orders.
---------------------------------------------------------------------------

    \84\ NOPR at P 80.
---------------------------------------------------------------------------

IV. Effective Date

i. Accounting NOPR

    97. In the NOPR, the Commission proposed that the aforementioned
accounting and financial reporting changes and updates would become
effective on January 1, 2006.\85\
---------------------------------------------------------------------------

    \85\ Id. at P 82.
---------------------------------------------------------------------------

ii. Commenters

    98. Most of the commenters suggest the Commission instead adopt a
January 1, 2007 effective date. Some of the commenters believe non-RTO
public utilities face a substantial burden of implementation because of
other obligations and functions performed by these companies.\86\ One
commenter explains that it has Sarbanes-Oxley Act concerns about any
proposal that would require changes, reconfigurations or modifications
to its general ledger computer systems and reporting structures, and/or
the methodology of the reporting of RTO-related revenue and cost
transactions. This commenter requests that the Commission provide
sufficient time to implement, internally test and have any necessarily
validations by external auditors of such changes or modifications.\87\
Another commenter expresses similar concerns and requests that the
Commission provide a minimum of three months to adjust their accounting
and reporting systems. This commenter explains that the easiest time
for companies to implement changes in the start of a fiscal year,
typically the calendar year.\88\ Other commenters indicate that more
time is needed to allow for more coordination, discussion and
consideration of the complexities of all

the issues.\89\ Another commenter submits that the rule take effect on
the proposed date unless it places an undue burden on the industry as a
whole or on some public utilities; in which case, the commenter
recommends that RTOs submit pro forma financial statements conforming
to the new rules on the proposed date.\90\
---------------------------------------------------------------------------

    \86\ See EEI at 11-12, SoCal ED at 4, First Energy at 11-13.
    \87\ First Energy at 11-13.
    \88\ EEI at 11.
    \89\ See National Grid at 13-14, Indicated NYTOs at 11-12.
    \90\ See APPA at 7-8.
---------------------------------------------------------------------------

    99. Commenters generally were in agreement that the Commission
should not require comparative analyses of the new data for earlier
reporting periods. Commenters contend that it would be unduly
burdensome for FERC Form 1 and 3-Q filers to go back in time to try to
capture retroactive prior period information for the new sub-
accounts.\91\
---------------------------------------------------------------------------

    \91\ See EEI at 12.
---------------------------------------------------------------------------

iii. Commission Conclusion
    100. The accounting and form changes adopted herein add visibility
and uniformity to the accounting and financial reporting for the costs
of transmission and market operation plant, and the expenses incurred
and revenue received in providing transmission and market services. The
changes provide comparability among RTOs and non-RTO public utilities
that perform region wide transmission and market operations, and
minimize inconsistent reporting by RTOs and non-RTO public utilities.
Further, these revisions allow the Commission to better understand
transactions and events that affect RTOs and their members and non-RTO
public utilities.
    101. The Commission also expects the changes in financial reporting
to lead to improvements in cost recovery practices by providing more
details concerning the costs of certain functions and increased
assurance that the costs are legitimate and reasonable costs of
providing service and assigned to the correct period for recovery in
rates.
    102. For the above reasons, the Commission orders that the
aforementioned accounting and financial reporting changes and updates
become effective on January 1, 2006. The Commission believes it is
imperative to obtain as quickly as possible adequate transparency of
transactions and business functions among and between RTOs and their
member public utilities as well as non-RTO public utilities to allow
for prudent choices to be made on issues such as optimizing the
efficiency of business functions. Hence, the Commission adopts a
January 1, 2006 effective date as originally proposed in the NOPR.
    103. The Commission clarifies that it has no intention of requiring
public utilities to report prior period information in the newly-
created accounts for FERC Form 1 and 3-Q purposes. Public utilities
should report prior period information in the accounts originally used,
except for Account 561, Load Dispatching. Since Account 561 is being
replaced by newly-created sub-accounts, public utilities should report
amounts reported in Account 561 for 2005 in Account 561.2 \92\ for the
2006 Form 1 filed in April 2007 and for the Form 3-Qs filed in 2006.
This approach will alleviate any burden associated with reporting prior
period information.
---------------------------------------------------------------------------

    \92\ This is for reporting purposes only and no amounts should
be reclassified for accounting purposes.
---------------------------------------------------------------------------

V. Changes to the FERC Quarterly and Annual Report Forms

    104. The changes adopted herein will require revising the existing
schedules in the FERC Forms 1, 1-F and 3-Q filed with the Commission.
Appendix B contains samples of the updated or new schedules that will
be included in these reports and will be available on e-Library.\93\
---------------------------------------------------------------------------

    \93\ Appendix B will not be published in the Federal Register.
---------------------------------------------------------------------------

VI. Information Collection Statement

    105. The following collections of information referenced in this
Final Rule have been submitted to the Office of Management and Budget
(OMB) for review under section 3507(d) of the Paperwork Reduction Act
of 1995.\94\ OMB's regulations require OMB to approve certain
information collection requirements imposed by agency rule.\95\ Upon
approval of a collection of information, OMB will assign an OMB control
number and expiration date. Respondents subject to the filing
requirements of this Final Rule will not be penalized for failing to
respond to these collections of information unless the collections of
information display a valid OMB control number or the Commission had
provided a justification as why the control number should be displayed.
---------------------------------------------------------------------------

    \94\ See 44 U.S.C. 3507(d) (2000).
    \95\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    106. The following burden estimates are for complying with this
final rule as follows:

----------------------------------------------------------------------------------------------------------------
                                                     Number of       Number of       Hours per
                 Data collection                    respondents      responses       response          Total
----------------------------------------------------------------------------------------------------------------
1 Form 1 (RTOs).................................               6               1              35             210
2 Form 1 (Non-RTOs).............................             214               1              11           2,354
3 Form 1-F......................................              33               1              11             363
4 Form 3-Q (RTOs)...............................               6               3              30             540
5 Form 3-Q (Non-RTOs)...........................             247               3              15          11,115
                                                 -----------------
    Totals......................................  ..............  ..............  ..............          14,582
----------------------------------------------------------------------------------------------------------------

    Information Collection Costs: The Commission has projected the
average annualized cost of all respondents to be the following: 14,582
hour = $905,280 for respondents. No capital startup costs are estimated
to be incurred by respondents.
    Annualized Costs (Operations & Maintenance): The costs for
performing the prepared schedules are rolled into the total costs for
completing the Commission's annual and quarterly financial reports.
    Title: FERC Form 1, ``Annual report of Major electric utilities,
licensees, and others''
    FERC Form 1-F, ``Annual report for Nonmajor public utilities and
licensees''
    FERC Form 3-Q, ``Quarterly financial report of electric utilities,
licensees, and natural gas companies''.
    Action: Information collections.
    OMB Control Nos.: 1902-0021; 1902-0029; and 1902-0205.
    Respondents: Businesses or other for profit.
    Frequency of responses: Annually and quarterly.
    Necessity of the Information: This Final Rule revises the
Commission's regulations to reflect changes that are occurring in the
electric industry due to the availability of open-access transmission
service and increasing

competition in the wholesale bulk power industry. The addition of these
new accounts is intended to standardize accounting for transactions and
events affecting public utilities and licensees, including independent
system operators and regional transmission organizations that file
financial reports with the Commission. The accounting regulations
currently found in the USofA and related financial reporting
requirements capture financial information along traditional primary
business functions but do not provide sufficient detailed information
concerning RTOs and, in particular, the costs incurred by these
organizations as well as non-RTO public utilities that engage in
similar activities. The addition of these accounts, and related changes
in reporting, are intended to improve the transparency, completeness
and consistency of accounting practices for the cost of assets, the
expenses incurred in providing services, along with revenues collected.
Without specific instructions and accounts for recording and reporting
the above transactions and events, inconsistent and incomplete
accounting and reporting will result.
    Internal Review: The Commission has reviewed the requirements
pertaining to the USofA and to the financial reports it prescribes and
determined that the proposed revisions are necessary because the
Commission needs to establish uniform accounting and reporting
requirements for the costs of utility assets and the expenses incurred
for providing services as part of utility operations.
    107. These requirements conform to the Commission's plan for
efficient information collection, communication, and management within
the electric industry. The Commission has assured itself, by means of
internal review, that there is specific, objective support for the
burden estimates associated with the information requirements.
    108. Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street, NE., Washington, DC 20426 (Attention:
Michael Miller, Office of the Executive Director, Phone<PHONE_NUMBER>,
fax:<PHONE_NUMBER>, e-mail: michael.miller@ferc.gov).
    109. For submitting comments concerning the collection of
information(s) and the associated burden estimates, please send your
comments to the contact listed above and to the Office of Management
and Budget, Office of Information and Regulatory Affairs, Washington,
DC 20503, Attention: Desk Officer for the Federal Energy Regulatory
Commission; Phone:<PHONE_NUMBER>, fax:<PHONE_NUMBER>.

VII. Environmental Analysis

    110. 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.\96\ No
environmental consideration is necessary for the promulgation of a rule
that addresses information gathering, analysis, and dissemination,\97\
and also that addresses accounting.\98\ This Final Rule addresses
accounting. In addition, this Final Rule involves information
gathering, analysis, and dissemination. Therefore, the Final Rule falls
within categorical exemptions provided in the Commission's regulations.
Consequently, neither an environmental impact statement nor an
environmental assessment is required.
---------------------------------------------------------------------------

    \96\ See Regulations Implementing the National Environmental
Policy Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats.
& Regs. ] 30,783 (1987).
    \97\ See 18 CFR 380.4(a)(5).
    \98\ See 18 CFR 380.4(c)(16).
---------------------------------------------------------------------------

VIII. Regulatory Flexibility Act

    111. The Regulatory Flexibility Act of 1980 (RFA) \99\ generally
requires a description and analysis of the effect that the final rule
will have on small entities or a certification that the rule will not
have a significant economic impact on a substantial number of small
entities.
---------------------------------------------------------------------------

    \99\ See 5 U.S.C. 601-612 (2000).
---------------------------------------------------------------------------

    112. The Commission concludes that this rule would not have such an
impact on a substantial number of small entities. Most companies
regulated by the Commission do not fall within the RFA's definition of
a small entity; \100\ this rule applies principally to public utilities
that own, control, or operate facilities for transmitting electric
energy in interstate commerce and not electric utilities per se. The
Commission also concludes that this rule will not impose a significant
burden on industry since the information is already being captured by
their accounting systems and generally being reported at a consolidated
business level.
---------------------------------------------------------------------------

    \100\ See 5 U.S.C. 601(3) citing to section 3 of the Small
Business Act, 15 U.S.C. 632. Section 3 of the Small Business Act
defines a ``small-business concern'' as a business which is
independently owned and operated and which is not dominant in its
field of operation. The Small Business Size Standards component of
the North American Industry Classification System defines a small
electric utility as one that, including its affiliates, is primarily
engaged in generation, transmission, and/or distribution of electric
energy for sale and whose total electric output for the preceding
fiscal years did not exceed 4 million MWh. 13 CFR 121.201.
---------------------------------------------------------------------------

IX. Document Availabilty

    113. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through the Commission's Home Page (http://www.ferc.gov) and

in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Room 2A,
Washington, DC 20426.
    114. From the Commission's Home Page on the Internet, this
information is available in the Commission's management system, e-
Library. The full text of this document is available on e-Library in
PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in e-Library, type the docket
number excluding the last three digits of this document in the docket
number field.
    115. User assistance is available for e-Library and the
Commission's website during normal business hours from our Help line at
(202) 502-8222 or the Public Reference Room at<PHONE_NUMBER>, Press 0,
TTY<PHONE_NUMBER>. E-Mail the Public Reference Room at
<EMAIL_ADDRESS>

Effective Date and Congressional Notification

    This Final Rule will take effect January 1, 2006. The Commission
has determined with the concurrence of the Administrator of the Office
of Information and Regulatory Affairs of the Office of Management and
Budget, that this rule is not a major rule within the meaning of
section 251 of the Small Business Regulatory Enforcement Fairness Act
of 1996. The Commission will submit the Final Rule to both houses of
Congress and the General Accounting Office.

List of Subjects in 18 CFR Part 101

    Electric power, electric utilities, Reporting and recordkeeping
requirements, Uniform System of Accounts.

    By the Commission.
Magalie R. Salas,
Secretary.

0
In consideration of the foregoing, the Commission amends Part 101,
Chapter I, Title 18, Code of Federal Regulations, as follows.

PART 101--UNIFORM SYSTEM OF ACCOUNTS PRESCRIBED FOR PUBLIC
UTILITIES AND LICENSES SUBJECT TO THE PROVISIONS OF THE FEDERAL
POWER ACT

0
1. The authority citation for part 101 continues to read as follows:

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352, 7651-7651o.

0
2. In part 101, Definitions, redesignate definitions 30-39 as
definitions 31-40 and add new definition 30. Regional market to the
list to read as follows:
* * * * *
    30. Regional market means an organized energy market operated by a
public utility, whether directly or through a contractual relationship
with another entity.

0
3. In part 101, Balance Sheet Chart of Accounts, Accounts 175, 176,
219, 230, 244, and 245 are added to the list:

Balance Sheet Chart of Accounts

ASSETS AND OTHER DEBITS

* * * * *

3. CURRENT AND ACCRUED ASSETS

* * * * *
    175 Derivative instrument assets.
    176 Derivative instrument assets-Hedges.
* * * * *

LIABILITIES AND OTHER CREDITS

5. PROPRIETARY CAPITAL

* * * * *
    219 Accumulated other comprehensive income.
* * * * *

7. OTHER NONCURRENT LIABILITIES

* * * * *
    230 Asset retirement obligations.

8. CURRENT AND ACCRUED LIABILITIES

* * * * *
    244 Derivatives instrument liabilities.
    245 Derivative instrument liabilities-Hedges.
* * * * *

0
4. In part 101, Balance Sheet Accounts, Account 108, paragraph C is
revised to read as follows:
* * * * *
    108 Accumulated provision for depreciation of electric utility
plant (Major only).
* * * * *
    C. For general ledger and balance sheet purposes, this account
shall be regarded and treated as a single composite provision for
depreciation. For purposes of analysis, however, each utility shall
maintain subsidiary records in which this account is segregated
according to the following functional classification for electric
plant:
    (1) Steam production,
    (2) Nuclear production,
    (3) Hydraulic production,
    (4) Other production,
    (5) Transmission,
    (6) Distribution,
    (7) Regional Transmission and Market Operation, and
    (8) General.
    These subsidiary records shall reflect the current credits and
debits to this account in sufficient detail to show separately for each
such functional classification:
    (a) The amount of accrual for depreciation,
    (b) The book cost of property retired,
    (c) Cost of removal,
    (d) Salvage, and
    (e) Other items, including recoveries from insurance.
    Separate subsidiary records shall be maintained for the amount of
accrued cost of removal other than legal obligations for the retirement
of plant recorded in Account 108, Accumulated provision for
depreciation of electric utility plant (Major only).
* * * * *
0
5. In part 101, Electric Plant Chart of Accounts, Accounts 317, 326,
337, 347, 359.1, and 374 are added to the list:

Electric Plant Chart of Accounts

* * * * *

2. PRODUCTION PLANT

A. STEAM PRODUCTION

* * * * *
    317 Asset retirement costs for steam production plant.

B. NUCLEAR PRODUCTION

* * * * *
    326 Asset retirement costs for nuclear production plant (Major
only).
* * * * *

C. HYDRAULIC PRODUCTION

* * * * *
    337 Asset retirement costs for hydraulic production plant.

D. OTHER PRODUCTION

* * * * *
    347 Asset retirement costs for other production plant.

3. TRANSMISSION PLANT

* * * * *
    359.1 Asset retirement costs for transmission plant.

4. DISTRIBUTION PLANT

* * * * *
    374 Asset retirement costs for distribution plant.

0
6. In part 101, Electric Plant Chart of Accounts, 5. General Plants, is
redesignated as 6. General Plants and a new section 5 with primary
plant account listing is added as follows:

5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT

    380 Land and land rights.
    381 Structures and improvements.
    382 Computer hardware.
    383 Computer software.
    384 Communication Equipment.
    385 Miscellaneous Regional Transmission and Market Operation
Plant.
    386 Asset Retirement Costs for Regional Transmission and Market
Operation Plant.
    387 [Reserved]

0
7. In part 101, Electric Plant Accounts, new primary plant accounts
380, 381, 382, 383, 384, 385, and 386 are added to read as follows:

Electric Plant Accounts

5. Regional Transmission and Market Operation Plant

* * * * *

380 Land and Land Rights

    This account shall include the cost of land and land rights used in
connection with regional transmission and market operations.

381 Structures and Improvements

    This account shall include the cost in place of structures and
improvements used for regional transmission and market operations.

382 Computer Hardware

    This account shall include the cost of computer hardware and
miscellaneous information technology equipment to provide scheduling,
system control and dispatching, system planning, standards development,
market monitoring, and market administration activities. Records shall
be maintained identifying to the maximum extent practicable computer
hardware owned and used for: (1) Scheduling, system control and
dispatching, (2) system planning and standards development, and (3)
market monitoring and market administration activities.

Items

1. Personal computers
2. Servers
3. Workstations
4. Energy Management System (EMS) hardware
5. Supervisory Control and Data Acquisition (SCADA) system hardware
6. Peripheral equipment
7. Networking components

383 Computer Software

    This account shall include the cost of off-the-shelf and in-house
developed software purchased and used to provide scheduling, system
control and dispatching, system planning, standards

development, market monitoring, and market administration activities.
Records shall be maintained identifying to the maximum extent
practicable the cost of software used for:
    (1) Scheduling, system control and dispatching,
    (2) System planning and standards development, and
    (3) Market monitoring and market administration activities.

Items

1. Software licenses
2. User interface software
3. Modeling software
4. Database software
5. Tracking and monitoring software
6. Energy Management System (EMS) software
7. Supervisory Control and Data Acquisition (SCADA) system software
8. Evaluation and assessment system software
9. Operating, planning and transaction scheduling software
10. Reliability applications
11. Market application software

384 Communication Equipment

    This account shall include the cost of communication equipment
owned and used to acquire or share data and information used to control
and dispatch the system.

Items

1. Fiber optic cable
2. Remote terminal units
3. Microwave towers
4. Global Positioning System (GPS) equipment
5. Servers
6. Workstations
7. Telephones

385 Miscellaneous Regional Transmission and Market Operation Plant

    This account shall include the cost of regional transmission and
market operation plant and equipment not provided for elsewhere,

386 Asset Retirement Costs for Regional Transmission and Market
Operation Plant

    This account shall include asset retirement costs on regional
control and market operation plant and equipment.

0
8. In part 101, Electric Plant Chart of Accounts, under newly
redesignated 6. General Plant, a new Account 399.1 is added to the
list.
    399.1 Asset retirement costs for general plant.

0
9. In part 101, Operating Revenue Chart of Accounts, new Accounts
456.1, 457.1 and 457.2 are added to the other operating revenue listing
as follows:

Operating Revenue Chart of Accounts

* * * * *

2. OTHER OPERATING REVENUES

    456.1 Revenues from transmission of electricity of others.
    457.1 Regional transmission service revenues.
    457.2 Miscellaneous revenues.

0
10. In part 101, Income Accounts, Account 456, Item 5 is removed, and
Item 6 is redesignated as Item 5.

0
11. In part 101, Income Accounts, new revenue accounts 456.1, 457.1,
and 457.2 are added to read as follows:

Operating Revenue Accounts

* * * * *

456.1 Revenues From Transmission of Electricity of Others

    This account shall include revenues from transmission of
electricity of others over transmission facilities of the utility.

457.1 Regional Transmission Service Revenues

    This account shall include revenues derived from providing
scheduling, system control and dispatching services. Include also in
this account reimbursements for system planning, standards development,
and market monitoring and market compliance activities. Records shall
be maintained so as to show: (1) The services supplied and revenues
received from each customer and (2) the amounts billed by tariff or
specified rates.

457.2 Miscellaneous Revenues

    This account shall include revenues and reimbursements for costs
incurred by regional transmission service providers not provided for
elsewhere. Records shall be maintained so as to show: (1) The services
supplied and revenues received from each customer, and (2) the amounts
billed by tariff or specified rates.

0
12. In part 101, Operation and Maintenance Expense Chart of Accounts,
3. Distribution Expenses is redesignated as 4. Distribution Expenses;
4. Customer Accounts Expenses is redesignated as 5. Customer Accounts
Expenses; 5. Customer Service and Informational Expenses is
redesignated as 6. Customer Service and Informational Expenses; 6.
Sales Expense is redesignated as 7. Sales Expenses; and 7.
Administrative and General Expenses is redesignated as 8.
Administrative and General Expenses.

0
13. In part 101, Operation and Maintenance Expense Chart of Accounts, a
new Regional Market Expenses function is added and new Accounts 575.1
575.2, 575.3, 575.4, 575.5, 575.6, 575.7, 575.8, 576.1, 576.2, 576.3,
576.4 and 576.5 are added as follows:

Operation and Maintenance Expense Chart of Accounts

* * * * *

3. REGIONAL MARKET EXPENSES

Operation

    575.1 Operation Supervision.
    575.2 Day-ahead and real-time market facilitation.
    575.3 Transmission rights market facilitation.
    575.4 Capacity market facilitation.
    575.5 Ancillary services market facilitation.
    575.6 Market monitoring and compliance.
    575.7 Market facilitation, monitoring and compliance services.
    575.8 Rents.

Maintenance

    576.1 Maintenance of structures and improvements.
    576.2 Maintenance of computer hardware.
    576.3 Maintenance of computer software.
    576.4 Maintenance of communication equipment.
    576.5 Maintenance of miscellaneous market operation plant.

0
14. In part 101, Operation and Maintenance Expense Chart of Accounts,
the listing of transmission expenses is revised as follows:

Operation and Maintenance Expense Chart of Accounts

* * * * *

2. TRANSMISSION EXPENSES

Operation

    560 Operation supervision and engineering.
    561.1 Load dispatch--Reliability.
    561.2 Load dispatch--Monitor and operate transmission system.
    561.3 Load dispatch--Transmission service and scheduling.
    561.4 Scheduling, system control and dispatch services.
    561.5 Reliability planning and standards development.
    561.6 Transmission service studies.
    561.7 Generation interconnection studies.
    561.8 Reliability planning and standards development services.
    562 Station expenses (Major only).
    563 Overhead line expenses (Major only).
    564 Underground line expenses (Major only).
    565 Transmission of electricity by others (Major only).
    566 Miscellaneous transmission expenses (Major only).
    567 Rents.
    567.1 Operation supplies and expenses (Nonmajor only).

Maintenance

    568 Maintenance supervision and engineering (Major only).

    569 Maintenance of structures (Major only).
    569.1 Maintenance of computer hardware.
    569.2 Maintenance of computer software.
    569.3 Maintenance of communication equipment.
    569.4 Maintenance of miscellaneous regional transmission plant.
    570 Maintenance of station equipment (Major only).
    571 Maintenance of overhead lines (Major only).
    572 Maintenance of underground lines (Major only).
    573 Maintenance of miscellaneous transmission plant (Major
only).
    574 Maintenance of transmission plant (Nonmajor only).

0
15. In part 101, Operation and Maintenance Expense Accounts, the first
paragraph of Account 556 instruction is revised to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

556 System Control and Load Dispatching (Major Only)

    This account shall include the cost of labor and expenses incurred
in load dispatching activities for system control. Utilities having an
interconnected electric system or operating under a central authority
which controls the production and dispatching of electricity may
apportion these costs to this account and transmission expense Accounts
561.1 through 561.4, and Account 581, Load Dispatching-Distribution.

0
16. In part 101, Operation and Maintenance Expense Accounts, Account
561, Load Dispatching (Major only) is removed.

0
17. In part 101, Operation and Maintenance Expense Accounts, new
expense accounts 561.1, 561.2, 561.3, 561.4, 561.5, 561.6, 561.7,
561.8, 569.1, 569.2, 569.3, 575.1, 575.2, 575.3, 575.4, 575.5, 575.6,
575.7, 575.8, 576.1, 576.2, 576.3, 576.4 and 576.5 are added to read as
follows:

Operation and Maintenance Expense Accounts

* * * * *

561.1 Load Dispatch--Reliability

    This account shall include the cost of labor, materials used and
expenses incurred by a regional transmission service provider or other
transmission provider to manage the reliability coordination function
as specified by the North American Electric Reliability Council (NERC)
and individual reliability organizations. These activities shall
include performing current and next day reliability analysis. This
account shall include the costs incurred to calculate load forecasts,
and performing contingency analysis.

561.2 Load Dispatch--Monitor and Operate Transmission System

    This account shall include the costs of labor, materials used and
expenses incurred by a regional transmission service provider or other
transmission provider to monitor, assess and operate the power system
and individual transmission facilities in real-time to maintain safe
and reliable operation of the transmission system. This account shall
also include the expense incurred to manage transmission facilities to
maintain system reliability and to monitor the real-time flows and
direct actions according to regional plans and tariffs as necessary.

Items

1. Receive and analyze outage requests
2. Reschedule outage plans
3. Monitor solution quality field data values, providing model updates
to NERC and coordinating network model changes across all systems
4. Conduct operating training related to NERC certification
5. Monitor generation resources and communicate expected dispatch
actions
6. Ensure ancillary service requirements are met
7. Directing switching
8. Controlling system voltages
9. Obtaining reports on the weather and special events
10. Preparing operating reports and data for billing and budget
purposes

561.3 Load Dispatch--Transmission Service and Scheduling

    This account shall include the costs of labor, materials used and
expenses incurred by a regional transmission service provider or other
transmission provider to process hourly, daily, weekly and monthly
transmission service requests using an automated system such as an Open
Access Same-Time Information System (OASIS). It shall also include the
expenses incurred to operate the automated transmission service request
system and to monitor the status of all scheduled energy transactions.

561.4 Scheduling, System Control and Dispatching Services

    This account shall include the costs billed to the transmission
owner, load serving entity or generator for scheduling, system control
and dispatching service. Include in this account service billings for
system control to maintain the reliability of the transmission area in
accordance with reliability standards, maintaining defined voltage
profiles, and monitoring operations of the transmission facilities.

561.5 Reliability, Planning and Standards Development

    This account shall include the cost of labor, materials used and
expenses incurred for the system planning of the interconnected bulk
electric transmission systems within a planning authority area.

Items

    1. Developing and maintaining transmission system models to
evaluate transmission system performance.
    2. Maintaining and applying methodologies and tools for the
analysis and simulation of the transmission systems for the assessment
and development of transmission expansion plans.
    3. Assessing, developing and documenting transmission expansion
plans.
    4. Maintaining transmission system models (steady-state, dynamics,
and short circuit).
    5. Collecting transmission information and transmission facility
characteristics and ratings.
    6. Notifying participants of any planned transmission changes that
may impact their facilities.
    7. Developing and reporting on transmission expansion plans for
assessment and compliance with reliability standards.
    8. Developing reliability standards for the planning and operation
of the interconnected bulk electric transmission systems that serve the
United States, Canada, and Mexico.
    9. Developing criteria and certification procedures for reliability
authorities, transmission operators and others.
    10. Outside services employed.

    Note: The cost of supervision, customer records and collection
expenses, administrative and general salaries, office supplies and
expenses, property insurance, injuries and damages, employee pension
and benefits, regulatory commission expenses, general advertising,
and rents shall be charged to the customer accounts, service, and
administrative and general expense accounts contained in the Uniform
System of Accounts.

561.6 Transmission Service Studies

    This account shall include the cost of labor, materials used and
expenses incurred to conduct transmission services studies for proposed
interconnections with the transmission system. Detailed records shall
be

maintained for each study undertaken and all reimbursements received
for conducting such a study.

561.7 Generation Interconnection Studies

    This account shall include the cost of labor, materials used and
expenses incurred to conduct generation interconnection studies for
proposed interconnections with the transmission system. Detailed
records shall be maintained for each study undertaken and all
reimbursements received for conducting such a study.

561.8 Reliability Planning and Standards Development Services

    This account shall include the costs billed to the transmission
owner, load serving entity, or generator for system planning of the
interconnected bulk electric transmission system. Include also the
costs billed by the regional transmission service provider for system
reliability and resource planning to develop long-term strategies to
meet customer demand and energy requirements. This account shall also
include fees and expenses for outside services incurred by the regional
transmission service provider and billed to the load serving entity,
transmission owner or generator.
* * * * *

569.1 Maintenance of Computer Hardware

    This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of computer hardware serving the
transmission function.

569.2 Maintenance of Computer Software

    This account shall include the cost of labor, materials used and
expenses incurred for annual computer software license renewals, annual
software update services and the cost of ongoing support for software
products serving the transmission function.

Items

1. Telephone support
2. Onsite support
3. Software updates and minor revisions

569.3 Maintenance of Communication Equipment

    This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of communication equipment serving
the transmission function.

569.4 Maintenance of Miscellaneous Regional Transmission Plant

    This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of miscellaneous regional
transmission plant serving the transmission function.
* * * * *

575.1 Operation Supervision

    This account shall include the cost of labor and expenses incurred
in the general supervision and direction of the regional energy
markets.

575.2 Day-Ahead and Real-Time Market Administration

    This account shall include the cost of labor, materials used and
expenses incurred to facilitate the Day-Ahead and Real-Time markets.
This account shall also include the costs incurred to manage the real-
time deployment of resources to meet generation needs and to provide
capacity adequacy verification. Include in this account the costs
incurred to maintain related sections of the tariff, market rules,
operating procedures, and standards and coordinating with neighboring
areas.

Items

1. Consultant fees and expenses
2. System record and report forms
3. Meals, traveling and incidental expenses

    Note: The cost of supervision, customer records and collection
expenses, administrative and general salaries, office supplies and
expenses, property insurance, injuries and damages, employee pension
and benefits, regulatory commission expenses, general advertising,
and rents shall be charged to the customer accounts, service, and
administrative and general expense accounts contained in the Uniform
System of Accounts.

575.3 Transmission Rights Market Administration

    This account shall include the cost of labor, materials used and
expenses incurred to manage the allocation and auction of transmission
rights.

575.4 Capacity Market Administration

    This account shall include the cost of labor, materials used and
expenses incurred to manage the allocation of capacity rights.

575.5 Ancillary Services Market Administration

    This account shall include the cost of labor, materials used and
expenses incurred to manage all other ancillary services market
functions.

575.6 Market Monitoring and Compliance

    This account shall include the cost of labor, materials used and
expenses incurred to review market data and operational decisions for
compliance with market rules. It shall also include the costs incurred
to interface with external market monitors.

575.7 Market Administration, Monitoring and Compliance Services

    This account shall include the costs billed to the transmission
owner, load serving entity or generator for market administration,
monitoring and compliance services.

575.8 Rents

    This account shall include all rents of property of others used,
occupied, or operated in connection with market administration and
monitoring. (See operating expense instruction 3.)

576.1 Maintenance of Structures and Improvements

    This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of structures used in market
administration and monitoring. (See operating expense instruction 2.)

576.2 Maintenance of Computer Hardware

    The account shall include the cost of labor, materials used and
expenses incurred in the maintenance of computer hardware used in
market administration and monitoring.

576.3 Maintenance of Computer Software

    This account shall include the cost of labor, materials used and
expenses incurred for annual computer software license renewals, annual
software update services and the cost of ongoing support for software
products used in market administration and monitoring.

Items

1. Telephone support
2. Onsite support
3. Software updates and minor revisions

576.4 Maintenance of Communication Equipment

    This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of communication equipment used in
market administration and monitoring.

576.5 Maintenance of Miscellaneous Market Operation Plant

    This account shall include the cost of labor, materials used and
expenses

incurred in the maintenance of miscellaneous market operation plant
used in market administration and monitoring.

    Note: The following appendices, A and B, will not appear in the
Code of Federal Regulations.

Appendix A--List of Commenters

1 American Public Power Association (APPA)
2 Arizona Public Service Company (APS)
3 Cinergy Services, Inc. (Cinergy) \101\
---------------------------------------------------------------------------

    \101\ Cinergy Services filed comments on behalf of its
franchised utility affiliates, The Cincinnati Gas & Electric
Company, PSI Energy, Inc., and The Union Light, Heat and Power
Company (collectively, Cinergy)
---------------------------------------------------------------------------

4 City of Santa Clara, California/dba Silicon Valley Power (City of
Santa Clara)
5 Electricity Consumers Resource Council (ELCON)
6 The Independent Electricity System Operator of Ontario (IESO)
7 Indicated New York Transmission Owners (Indicated NYTOs) \102\
---------------------------------------------------------------------------

    \102\ Indicated NYTOs includes: Central Hudson Gas & Electric
Corporation; Consolidated Edison Company of New York, Inc.; LIPA;
New York Power Authority; New York Electric & Gas Corporation;
Orange and Rockland Utilities, Inc.; and Rochester Gas and Electric
Corporation.
---------------------------------------------------------------------------

8 International Transmission Company (International Transmission)
9 The Iowa Utilities Board (Iowa Board)
10 ISO/RTO Council \103\
---------------------------------------------------------------------------

    \103\ ISO/RTO Council includes: The Alberta Electric System
Operator; California Independent System Operators, Inc.; Electric
Reliability Council of Texas; the Independent Electricity System of
Ontario, Inc.; ISO New England, Inc.; Midwest Independent
Transmission System Operators, Inc; New York Independent System
Operators, Inc.; PJM Interconnection, L.L.C.; and Southwest Power
Pool.
---------------------------------------------------------------------------

11 FirstEnergy Service Company (FirstEnergy) \104\
---------------------------------------------------------------------------

    \104\ FirstEnergy filed on behalf of its electric utility
operating company affiliates: Ohio Edison Company; The Toledo Edison
Company; the Cleveland Electric Illuminating Company; Pennsylvania
Power Company; American Transmission System, Inc; Jersey Central
Power & Light Company; Pennsylvania Electric Company; and
Metropolitan Edison Company.
---------------------------------------------------------------------------

12 Madison Gas & Electric Company (MGE)
13 Massachusetts Municipal Wholesale Electric Company (MMWEC)
14 Midwest ISO Transmission Owners \105\
---------------------------------------------------------------------------

    \105\ The Midwest ISO Transmission Owners for this filing
consist of: Ameren Services Company, as agent for Union Electric
Company d/b/a AmerenUE, Central Illinois Public Service Company d/b/
a AmerenCIPS, Central Illinois Light Co. d/b/a AmerenCilco, and
Illinois Power Company d/b/a AmerenIP; Alliant Energy Corporate
Services, Inc. on behalf of its operating company affiliate
Interstate Power and Light Company (f/k/a IES Utilities Inc. and
Interstate Power Company); American Transmission Systems,
Incorporated, a subsidiary of FirstEnergy Corp.; Aquila, Inc. d/b/a
Aquila Networks (f/k/a Utilicorp United, Inc.); City Water, Light &
Power (Springfield, IL); Great River Energy; Hoosier Energy Rural
Electric Cooperative, Inc.; Indiana Municipal Power Agency;
Indianapolis Power & Light Company; LG&E Energy LLC (for Louisville
Gas and Electric Company and Kentucky Utilities Company); Minnesota
Power (and its subsidiary Superior Water, L&P); Montana-Dakota
Utilities Co.; Northern Indiana Public Service Company; Northern
States Power Company and Northern States Power Company (Wisconsin),
subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric
Company; Otter Tail Corporation d/b/a Otter Tail Power Company;
Southern Illinois Power Cooperative; Southern Indiana Gas & Electric
Company (d/b/a Vectren Energy Delivery of Indiana); and Wabash
Valley Power Association, Inc.
---------------------------------------------------------------------------

15 National Rural Electric Cooperative Association (NRECA)
16 National Grid USA
17 The New England Power Pool Participants Committee (NEPOOL
Participants Committee)
18 NiSource Inc. (NiSource)
19 Southern California Edison Company (SCE)
20 The Transmission Agency of Northern California (TANC)
21 Transmission Access Policy Study Group (TAPS)
22 Wisconsin Electric Power Company (Wisconsin Electric)

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[FR Doc. 05-24388 Filed 12-29-05; 8:45 am]

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