[Federal Register: September 29, 2004 (Volume 69, Number 188)]
[Proposed Rules]
[Page 58112-58115]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr29se04-27]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Parts 35, 41, 101, 141
[Docket No. RM04-12-000]
Financial Reporting and Cost Accounting, Oversight and Recovery
Practices for Regional Transmission Organizations and Independent
System Operators
September 16, 2004.
AGENCY: Federal Energy Regulatory Commission.
ACTION: Notice of inquiry.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
inviting comments on its accounting and financial reporting
requirements for and oversight of regional transmission organization
(RTO) and independent system operator (ISO) costs.
DATES: Comments on this NOI are due on November 4, 2004.
ADDRESSES: Comments may be filed electronically via the eFiling link on
the Commission's Web site at http://www.ferc.gov. Commentors unable to
file comments electronically must send an original and 14 copies of
their comments to: Federal Energy Regulatory Commission, Office of the
Secretary, 888 First Street NE., Washington, DC 20426. Refer to the
Procedure for Comments section of the preamble for additional
information on how to file comments.
FOR FURTHER INFORMATION CONTACT:
Mark Hegerle (Technical Information), Office of Markets, Tariffs &
Rates--Central, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426, (202) 502-8287, Mark.Hegerle@ferc.gov.
Mark Klose (Accounting Information), Office of Executive Director--
Regulatory Accounting Policy Division, Federal Energy Regulatory
Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-
8283, Mark.Klose@ferc.gov.
Lodie White (Legal Information), Office of General Counsel--Markets,
Tariffs & Rates, Federal Energy Regulatory Commission, 888 First
Street, NE., Washington, DC 20426, (202) 502-6193,
Lodie.White@ferc.gov.
SUPPLEMENTARY INFORMATION:
Notice of Inquiry
Introduction
1. The Federal Energy Regulatory Commission (Commission) is issuing
this Notice of Inquiry to seek comments on its accounting and financial
reporting requirements for and oversight of regional transmission
organization (RTO) and independent system operator (ISO) costs.
Specifically, the Commission is undertaking a review of:
(a) Whether changes are needed to the Uniform System of Accounts
Prescribed for Public Utilities and Licensees Subject to the
Provisions of the Federal Power Act (USofA), (18 CFR part 101), to
better account and report RTO and ISO financial information to the
Commission, in order to provide greater transparency of transactions
and business functions affecting these entities and their member
transmission-owning public utilities;
(b) Whether RTOs and ISOs have appropriate incentives to be cost
efficient; and
(c) Whether the Commission's rate review methods for RTOs and
ISOs are sufficient.
Background
2. In Order No. 888,\1\ the Commission encouraged but did not
require the formation of ISOs--independent entities that administer
regional transmission tariffs and control the transmission facilities
of their member transmission-owning utilities. Rather, Order No. 888
delineated eleven principles defining the operations and structure of a
properly functioning ISO. Likewise, in Order No. 2000,\2\ the
Commission encouraged utilities to voluntarily join RTOs, and detailed
certain functions an RTO must perform and characteristics that an RTO
should have.\3\ However, in neither rule did the Commission promulgate
specific accounting rules or rate review principles for the new
entities. The Commission instead chose to rely on existing rules and
policies applicable to traditional public utilities, i.e., principally
investor-owned utilities (IOUs).
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\1\ 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, et al. v. 225 F.3d 667 (D.C.
Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
\2\ 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, et al. v. FERC, 272
F.3d 607 (D.C. Cir. 2001).
\3\ ISOs and RTOs are, in many respects, similar, with one major
difference being that RTOs must meet more stringent independence and
scope and configuration standards.
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3. Over the past seven years, beginning in 1997, the Commission
issued a series of orders approving several ISOs and RTOs which have
since commenced operations. PJM Interconnection, LLC (PJM), ISO New
England, Inc. (ISO-NE), and Midwest Independent Transmission System
Operator, Inc. (Midwest ISO) were first approved (or conditionally
approved) as ISOs and later as RTOs; New York Independent System
Operator, Inc. (NYISO) and California Independent System Operator, Inc.
(CAISO) were approved as ISOs. The Commission has also conditionally
approved Southwest Power Pool, Inc. (SPP), which currently operates a
regional transmission tariff, as an RTO. The Commission also
conditionally approved a number of other RTOs and ISOs which have not
commenced operations.\4\
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\4\ RTO West (now Grid West), WestConnect, GridFlorida,
GridSouth, and SeTrans.
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4. Each of these entities developed independent of one another,
using somewhat different business models, software, accounting methods,
and rate designs to accomplish the same ultimate goal of providing
open-access (non-discriminatory) regional transmission service. In
addition, some of these entities administer centrally-dispatched,
competitive energy markets. These differences have made comparisons
between entities difficult and raised questions concerning the
Commission's current accounting and financial reporting rules and our
current rate review practices for RTOs and ISOs.
5. Nevertheless there are similarities among RTOs and ISOs as well.
Each RTO/ISO administers a regional transmission tariff and performs
system monitoring and planning, as well as
[[Page 58113]]
transmission scheduling--functions that formerly were performed by the
transmission-owning utilities that now take transmission service under
the RTO's or ISO's tariff. While there may be some needed redundancy
with respect to certain functions, such as system reliability
monitoring, because an RTO/ISO, with its regional focus and reach,
takes over certain functions previously performed by the transmission-
owning public utilities, ratepayers should, over time, expect to see
economic synergies resulting from the formation of RTOs.\5\
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\5\ For example, Order No. 2000 noted one entity's observation
that there may be transmission functions performed by individual
company control centers, within existing control areas, or within
existing reliability councils, that may be better and/or more
efficiently performed by an RTO.
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Differences Between RTOs and Investor-Owned Utilities
6. There are several significant differences between RTOs/ISOs and
vertically integrated public utilities. As noted above, each RTO/ISO
offers transmission service over a wide region of the country, covering
multiple IOU and other transmission systems. Many also run energy
markets and congestion management systems through central dispatch of
the generation located in their footprint. However, unlike IOUs, RTOs
and ISOs do not own the transmission and generation facilities under
their control. In fact, they are required to be independent from any
market participant.\6\
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\6\ A market participant is defined in relevant part as any
entity that, either directly or through an affiliate, sells or
brokers electric energy, or provides ancillary services to the RTO
or any other entity (e.g., a member transmission-owning utility),
which has economic or commercial interests that would be
significantly affected by the RTO's actions or decisions. See 18 CFR
35.34(b)(2) (2004).
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7. RTO and ISO costs are largely associated with sophisticated
system control and communications hardware and software designed to
oversee the transmission grid, and, for many, to run energy markets,
congestion management systems, and transmission scheduling systems. In
contrast, an IOU's costs are dominated by the costs of generation,
transmission, and distribution facilities.
8. In addition, because RTOs/ISOs provide transmission service and
may operate wholesale markets, they do not provide retail electric
service, and, therefore, fall under the exclusive jurisdiction of the
Commission. This means that RTOs and ISOs, unlike vertically integrated
IOUs, are not subject to direct oversight by state commissions.
9. Moreover, while the Commission has not mandated any particular
business model for RTOs and ISOs, all current RTOs and ISOs are not-
for-profit entities.\7\ Each RTO and ISO is required to have an
independent board of directors and to consult with an advisory
committee made up of all classes of market participants prior to taking
action. However, the advisory committee has no ability to block an
action of the RTO/ISO; it can only offer non-binding advice on budget
and other matters. Moreover, with for-profit entities, shareholders
face a risk of lower earnings if costs are found to be imprudent and
ineligible for rate recovery. The not-for-profit status of RTOs/ISOs
makes cost review more difficult. As the Commission has previously
observed, with respect to one of these RTOs, ``Midwest ISO's non-profit
status complicates a prudence review after the costs are incurred.''
\8\
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\7\ One exception is that PJM earns money for its members when
it sells software and technology to other transmission providers.
Nevertheless, like the other RTOs, PJM does not have shareholders
and passes through all of its costs of operation to its market
participants.
\8\ Midwest Independent Transmission System Operator, 101 FERC ]
61,221 at P 35 (2002), order on reh'g, 103 FERC ] 61,035 (2003).
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Current RTO Accounting, Financial Reporting and Cost Recovery Practices
10. Despite their differences, RTOs/ISOs are public utilities under
the Federal Power Act and, like traditional public utilities, must
follow the USofA.\9\ However, the USofA was developed for traditional
public utilities, i.e., public utilities that provide electric
generation, transmission, and distribution service. The accounting
rules contained in the USofA provide for capturing financial
information along these primary functional business lines.\10\ However,
meaningful functional business segments or service lines for RTOs and
ISOs seem quite different. Meaningful business lines for RTOs might
include ``grid reliability,'' ``ancillary services,'' or ``energy
markets,'' to suggest a few possibilities. But because RTOs use the
Commission's existing USofA to capture and classify costs, their
financial statements and other reports prepared from their accounting
records may not provide sufficient information about their costs and
the relationship to services provided or other business activities.
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\9\ See 18 CFR Part 101.
\10\ The Commission has explained that RTOs and ISOs are public
utilities, and as such, they are required to follow the USofA and
file Form No. 1. See PJM Interconnection, L.L.C. et al., 107 FERC ]
61,087 (2004).
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11. Likewise, the current USofA may not provide sufficient
transparency with respect to changes in RTO- and ISO-member
transmission-owning public utilities' costs to reflect that the RTO/ISO
is performing all or a portion of certain functions that were
previously performed by the transmission-owning utilities.
12. Differences also exist among RTOs/ISOs with respect to
operations, rate design, and accepted rate review methodologies. For
example, RTOs/ISOs, while progressing at differing paces, perform
similar functions with respect to overseeing the transmission grid and
running markets. However, rather than building on the work of others,
each RTO/ISO has developed, or contracted with vendors to develop,
proprietary software to run its complex systems. The cost of each
RTO's/ISO's software package, while largely designed to do similar
tasks, varied considerably.
13. With respect to rate design differences, as an example, NYISO
has just one charge to recover all of its costs to administer its
transmission tariff, energy markets, and congestion management system,
including its auction of transmission congestion contracts (comparable
to firm transmission rights (FTRs)).\11\ However, ISO-NE and Midwest
ISO have three charges, PJM five, and CAISO seven to recover comparable
costs. Some use formula rates with true-ups; others calculate stated
rates for the following calendar year. There are also differences among
the RTOs/ISOs with respect to the billing determinants used to
calculate similar charges.
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\11\ NYISO also has separate charges for unbudgeted costs, and
start-up and formation costs.
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14. RTOs/ISOs develop their proposed rates through a collaborative
process with their respective advisory committee processes. In general,
the RTO/ISO determines the cost side of the equation based on the level
of expenditures budgeted to accomplish the RTO's/ISO's functions,\12\
and works with its stakeholders through the advisory committee process
to arrive at a proposed allocation methodology, which is filed with the
Commission (under section 205 of the FPA).\13\ The Commission has
largely relied on each advisory committee process as a check on RTO
expenditures and has focused primarily on the review of the cost
allocation and rate design methodologies. In addition, the Commission
required one RTO,
[[Page 58114]]
Midwest ISO, to file its annual budget and progress reports on
expenditures related to market development for informational
purposes.\14\ The Commission reasoned that the informational filings
would ``provide a sufficient opportunity to review and compare the
proposed costs with the actual costs and allow the Commission to
monitor Midwest ISO's cost containment efforts.'' \15\
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\12\ The costs incurred by the RTO/ISO are tied to the services
it performs on behalf of its market participants. The RTO/ISO would
not, therefore, take an additional functions without an approving
vote of its advisory committee or a directive by the Commission.
\13\ 15 U.S.C. 824d (2000).
\14\ See, e.g., Midwest Independent Transmission System
Operator, 101 FERC ] 61,221 (2002), order on reh'g, 103 FERC ]
61,035 (2003)
\15\ Id., 101 FERC ] 61,221 at P 36.
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15. Nevertheless, in all cases, RTOs/ISOs are typically allowed
recovery of all expenditures; they do not absorb losses and instead
pass through all costs that they incur (e.g., NYISO has a separate
charge for unbudgeted expenses; Midwest ISO's Schedule 10 charge, while
capped at $0.15/MWh, allows for the deferral, with interest, of any
costs which would cause the rate to exceed the cap during one period to
be recovered during a later period when actual costs for that period
are less than the capped rate).
The Subject of the Notice of Inquiry
16. The Commission wants to explore whether changes to RTO/ISO
accounting, financial reporting, and cost recovery practices are
necessary to ensure the rates charged by RTOs/ISOs and their member
transmission-owning public utilities are just and reasonable. Rate
review mechanisms, including the accounting and financial reporting
requirements contained in quarterly and annual financial reports
applicable to traditional public utilities may no longer be
sufficiently descriptive to reflect RTO/ISO operations due to their
structure and business functions. Secondarily, current financial
reporting by RTOs/ISOs and their member transmission-owning public
utilities owners may not provide the Commission and others sufficient
transparency of financial trends and emerging issues.
17. As noted above, the Commission's expectation has been that the
RTO/ISO would spend only for the benefit of its market participants.
The RTO/ISO looked to stakeholders for advice on whether to pursue
particular tariff or market design changes which, of course, would
necessitate agreement on spending to bring those changes to fruition.
However, RTO/ISO stakeholders (including member transmission-owning
utilities) have alleged in various forums that this process provides an
insufficient check, noting that they only see the budget after it is
finalized and they have no veto power. In this regard, member
transmission-owning utilities subject to state commission regulation
complain that the absence of sufficient oversight of RTO/ISO spending
results in their being forced to justify before their state commissions
the prudence of RTO/ISO expenditures.
Questions for Response
18. The Commission encourages any and all comments regarding the
topics broadly discussed above. In addition the Commission seeks
responses to the following specific questions:
A. Accounting and Financial Reporting Issues for RTOs/ISOs
1. Are the individual account descriptions and instructions
under the existing USofA adequate for the functions typically
performed by RTOs/ISOs? If not, what changes should be made to the
account descriptions and instructions under the existing USofA to
accommodate the RTO/ISO business model? Are the changes so extensive
that an entirely separate USofA should be developed to accommodate
RTOs/ISOs?
2. Under the existing USofA costs are accounted for as electric
production, transmission, distribution or general plant. What other
accounts and functional classifications should be provided for RTO/
ISO transactions and events? For example, are additional revenue,
expense or detailed fixed asset accounts needed?
3. Should the Commission develop a new financial reporting
format for the functions typically performed by RTOs/ISOs? If so
what financial information and financial-related information should
be reported? If not, how may the existing annual and quarterly
financial reports be changed or modified to report relevant RTO/ISO
transactions and events?
4. Is additional accounting and financial reporting guidance
needed for market operation and market monitoring functions of RTOs/
ISOs? If so what transactions and events require additional
accounting and financial reporting guidance?
5. Is there sufficient detailed financial and financial-related
information being provided to users of RTO/ISO data? If not, what
additional information would the users of the information find
helpful and why? For example, if detailed information technology
cost data is necessary, would it also be helpful for the RTO/ISO to
include the cost driver of the data (e.g., quantity of desktop
computers in relationship to the number of employees)?
6. Currently the quarterly and annual Commission financial
reports include a schedule that requires respondents to report data
concerning the transmission of electricity for others. Should RTOs/
ISOs report transmission of electric for others for its Commission-
jurisdictional members or should those individual members report the
information in their individual filings? If the RTO/ISO should
report the information, what information should be reported and how
should it be shown in the filing?
B. Accounting and Financial Reporting Issues for Public Utilities and
Licensees That Are Members of an RTO/ISO
1. Are the individual account descriptions and instructions
under the existing USofA useful and applicable for classifying
revenues received from RTOs/ISOs? If not, what changes should be
made to the account descriptions and instructions under the existing
USofA to accommodate these transactions and events?
2. Are the individual account descriptions and instructions
under the existing USofA useful and applicable for classifying costs
related to providing various services such as ancillary services,
energy markets, or costs associated with transmission congestion? If
not, what changes should be made to the existing USofA to
accommodate these transactions and events?
3. What additional detailed information should be collected or
disclosed in the quarterly and annual Commission financial reports
of individual utilities to provide greater transparency of RTO
transactions and events?
4. What additional disclosures should be made in the quarterly
and annual Commission financial reports of individual utilities to
describe the economic effects resulting from the respondent
transmitting public utility participating in an RTO?
5. Does the Commission's USofA and existing financial reporting
requirements for public utility members of RTO/ISOs provide
regulators with adequate information to clearly identify which
functions are performed by the RTO/ISO and which are performed by
the member transmission-owning public utilities, and to ensure that
costs are not being double recovered through either Commission-
jurisdictional or state-jurisdictional rates? Are they adequate to
determine how RTO/ISO costs billed to public utility members should
enter into the determination of retail rates? If not, what changes
to the Commission's accounting and reporting rules should be made?
C. Cost Management
1. Do not-for-profit RTOs/ISOs currently have the appropriate
incentives to contain costs? If not, what are the right incentives
(and why would they be the right incentives) and how should they be
implemented?
2. Should the Commission revisit the means by which RTO/ISO
rates are reviewed, particularly with respect to cost incurrence? If
so, what means should the Commission employ to ensure that RTOs'/
ISOs' expenditures are prudent and their rates are just and
reasonable? Would a ``best practices'' or ``benchmark'' approach,
where one RTO/ISO's expenditures in a particular cost category are
measured against those of other RTOs/ISOs, be sufficient?
3. What is the appropriate role for the Commission with respect
to overseeing RTO/ISO software costs? Should an RTO/ISO be required
to justify contracting for the development of new software rather
than using or modifying ``off-the-shelf'' software developed for a
comparable application for or by another RTO/ISO? To what extent
would
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the use of standardized or at least compatible software in
neighboring RTO/ISO markets reduce the cost of doing business across
RTO/ISO boundaries? How would any such standardization be
accomplished?
4. To what degree should an RTO/ISO's stakeholder/advisory
committee be involved in reviewing or shaping the RTO/ISO's budget
and spending decisions? Are there independence considerations that
should prevent or limit such review by market participants?
5. Should the Commission allow differences between RTOs/ISOs
with regard to cost allocation and rate design to recover the
operation and capital costs for each of their functions (e.g.,
tariff administration and markets for energy, ancillary service, and
FTRs)? If so, how should the various rates be designed, i.e., what
are the correct billing determinants for each service?
6. Should the compensation of senior RTO/ISO management be
linked to specific performance measures, including cost reductions?
Procedure for Comments
19. The Commission invites interested persons to submit comments,
and other information on the matters, issues and specific questions
identified in this notice. Comments are due November 4, 2004. Comments
must refer to Docket No. RM04-12-000, and must include the commentor's
name, the organization they represent, if applicable, and their
address.
20. To facilitate the Commission's review of the comments,
commentors are requested to provide an executive summary of their
position. Commentors are requested to identify each specific question
posed by the NOI that their discussion addresses and to use appropriate
headings. Additional issues the commentors wish to raise should be
identified separately. The commentors should double space their
comments.
21. Comments may be filed on paper or electronically via the
eFiling link on the Commission's Web site at http://www.ferc.gov . The
Commission accepts most standard word processing formats and commentors
may attach additional files with supporting information in certain
other file formats. Commentors filing electronically do not need to
make a paper filing. Commentors that are not able to file comments
electronically must send an original and 14 copies of their comments
to: Federal Energy Regulatory Commission, Office of the Secretary, 888
First Street NE., Washington, DC 20426.
22. All comments will be placed in the Commission's public files
and may be viewed, printed, or downloaded remotely as described in the
Document Availability section below. Commentors are not required to
serve copies of their comments on other commentors.
Document Availability
23. 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.
24. From the Commission's Home Page on the Internet, this
information is available in the Commission's document management
system, eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number (excluding the last three digits) in the docket number field.
25. User assistance is available for eLibrary and the Commission's
Web site during normal business hours. For assistance, please contact
the Commission's Online Support at 1-866-208-3676 (toll free) or 202-
502-6652 (e-mail at FERCOnlineSupport@ferc.gov or the Public Reference
Room at 202-502-8371, TTY 202-502-8659 (e-mail at
public.referenceroom@ferc.gov)
By direction of the Commission.
Magalie R. Salas,
Secretary.
[FR Doc. 04-21760 Filed 9-28-04; 8:45 am]
BILLING CODE 6717-01-P