[Federal Register Volume 71, Number 109 (Wednesday, June 7, 2006)]
[Proposed Rules]
[Pages 33102-33135]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 06-4903]
[[Page 33101]]
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Part III
Department of Energy
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Federal Energy Regulatory Commission
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18 CFR Part 35
Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and
Ancillary Services by Public Utilities; Proposed Rule
Federal Register / Vol. 71, No. 109 / Wednesday, June 7, 2006 /
Proposed Rules
[[Page 33102]]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM04-7-000]
Market-Based Rates for Wholesale Sales of Electric Energy,
Capacity and Ancillary Services by Public Utilities
May 19, 2006.
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Notice of proposed rulemaking.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
proposing to amend its regulations to revise Subpart H to Part 35 of
Title 18 of the Code of Federal Regulations governing market-based
rates for public utilities pursuant to the Federal Power Act (FPA). The
Commission is proposing to codify and, in certain respects, revise its
current standards for market-based rates for sales of electric energy,
capacity, and ancillary services. The Commission is proposing to retain
several of the core elements of its current standards for granting
market-based rates. However, we propose certain revisions to these
standards and seek comment on other issues. The Commission also
proposes to streamline certain aspects of its filing requirements to
reduce the administrative burdens on applicants, customers and the
Commission.
DATES: Comments are due August 7, 2006. Reply comments are due
September 6, 2006. Comments should be double spaced and include an
executive summary.
ADDRESSES: You may submit comments, identified by Docket No. RM04-7-
000, by one of the following methods:
Agency Web Site: http://www.ferc.gov. Follow the
instructions for submitting comments via the eFiling link found in the
Comment Procedures Section of the preamble.
Mail: Commenters unable to file comments electronically
must mail or hand deliver an original and 14 copies of their comments
to: Federal Energy Regulatory Commission, Office of the Secretary, 888
First Street, NE., Washington, DC 20426. Please refer to the Comment
Procedures Section of the preamble for additional information on how to
file paper comments.
FOR FURTHER INFORMATION CONTACT: Kelly A. Perl (Technical Information),
Office of Energy Markets and Reliability, Federal Energy Regulatory
Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-
6421. Elizabeth Arnold (Legal Information), Office of the General
Counsel, Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502-8818.
SUPPLEMENTARY INFORMATION:
I. Introduction
II. Background and Overview
III. Discussion
A. Horizontal Market Power
1. Current Policy
2. Proposal
B. Vertical Market Power
1. Current Policy
2. Proposal
C. Affiliate Abuse/Reciprocal Dealing
1. Power Sales Restrictions
2. Market-Based Rate Code of Conduct for Affiliate Transactions
Involving Power Sales and Brokering, Non-Power Goods and Services
and Information Sharing
D. Mitigation
1. Current Policy
2. Proposal
E. Implementation Process
1. Current Practice
2. Proposal
F. Market-Based Rate Power Sales Tariff
G. Miscellaneous Issues
1. Waivers
2. Foreign Sellers
3. Change in Status
4. Third-Party Providers of Ancillary Services
IV. Information Collection Statement
V. Environmental Analysis
VI. Regulatory Flexibility Act Analysis
VII. Comment Procedures
VIII. Document Availability
I. Introduction
1. Pursuant to sections 205 and 206 of the Federal Power Act
(FPA),\1\ the Commission is proposing to amend its regulations to
revise Subpart H to Part 35 of Title 18 of the Code of Federal
Regulations to govern market-based rate authorizations for wholesale
sales of electric energy, capacity and ancillary services by public
utilities, including modifying all existing market-based authorizations
and tariffs so they will be expressly conditioned on or revised to
reflect certain new requirements proposed herein. The major components
of this Notice of Proposed Rulemaking (NOPR) are summarized in the next
section.
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\1\ 16 U.S.C. 824d, 824e (2000).
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II. Background
2. In 1988, the Commission began considering proposals for market-
based pricing of wholesale power sales. The Commission acted on market-
based rate proposals filed by various wholesale suppliers on a case-by-
case basis. Over the years, the Commission developed a four-prong
analysis used to assess whether a seller should be granted market-based
rate authority: (1) Whether the seller and its affiliates lack, or have
adequately mitigated, market power in generation; (2) whether the
seller and its affiliates lack, or have adequately mitigated, market
power in transmission; (3) whether the seller or its affiliates can
erect other barriers to entry; and (4) whether there is evidence
involving the seller or its affiliates that relates to affiliate abuse
or reciprocal dealing.
3. The courts have reviewed the Commission's market-based rate
program and found that it satisfies the FPA. The FPA requires that all
rates demanded by public utilities for the sale of electric energy at
wholesale be found `just and reasonable.' \2\ The United States Supreme
Court has explained that the just and reasonable standard ``does not
compel the Commission to use any single pricing formula.'' \3\ The
United States Court of Appeals for the D.C. Circuit has long held that
``when there is a competitive market the [Commission] may rely upon
market-based prices in lieu of cost-of-service regulation to assure a
``just and reasonable'' result.'' \4\ The Commission's authorization of
market-based rates has been found to satisfy the just and reasonable
standard of the FPA.\5\
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\2\ Louisiana Energy and Power v. FERC, 141 F.3d 364, 365 (D.C.
Cir. 1998) (citing 16 U.S.C. 824d(a)) (Louisiana Energy).
\3\ Mobil Oil Exploration v. United Distribution Co., 498 U.S.
211, 224 (1991).
\4\ Elizabethtown Gas Company v. FERC, 10 F.3d 866, 870 (D.C.
Cir. 1993) (Elizabethtown Gas), (citing Tejas Power Corp. v. FERC,
908 F.2d 998, 1004 (D.C. Cir. 1990)).
\5\ See Louisiana Energy; Elizabethtown Gas; Consumers Energy
Company v. FERC, 367 F.3d 915, 923 (D.C. Cir. 2004).
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4. The Commission initiated the instant rulemaking proceeding in
April 2004 to consider ``the adequacy of the current four-prong
analysis and whether and how it should be modified to assure that
prices for electric power being sold under market-based rates are just
and reasonable under the Federal Power Act.'' \6\ At that time, the
Commission noted that much has changed in the industry since the four-
prong analysis was first developed and posed a number of questions that
would be explored through a series of technical conferences. The
comments from these technical conferences are considered in this
NOPR.\7\
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\6\ Market-Based Rates for Public Utilities, 107 FERC ] 61,019
at P 1 (2004) (initiating rulemaking proceeding).
\7\ A summary of the comments submitted in this proceeding is
attached as Appendix E. A list of the commenters is included in
Appendix D.
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5. On April 14, 2004, the Commission issued an order modifying the
then-existing generation market power
[[Page 33103]]
analysis and its policy governing market power mitigation, on an
interim basis.\8\ The April 14 Order adopted a policy that would
provide sellers a number of procedural options, including two
indicative generation market power screens (an uncommitted pivotal
supplier analysis and an uncommitted market share analysis), and the
option of proposing mitigation tailored to the particular circumstances
of the seller that would eliminate the ability to exercise market
power. The order also explained that sellers could choose to adopt
cost-based rates.
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\8\ AEP Power Marketing, Inc., 107 FERC ] 61,018 (April 14
Order), order on reh'g, 108 FERC ] 61,026 (2004) (July 8 Order).
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6. On July 8, 2004, the Commission acted on requests for rehearing
of the April 14 Order, reaffirming the basic analysis, but clarifying
and modifying certain instructions for performing the generation market
power analysis. The Commission clarified, among other things, the types
of data on which sellers and intervenors may rely, and that adjustments
may be allowed in certain circumstances. The Commission also clarified
that mitigation would be imposed in all markets where a seller is found
to have generation market power.
7. The Commission believes it is now appropriate to revise and
codify the standards for market-based rates for wholesale sales of
electric energy, capacity and ancillary services. Refining and
codifying effective standards for market-based rates will help
customers by ensuring that they are protected from the exercise of
market power. It will also provide greater certainty to sellers seeking
market-based rate authority.
8. The regulations proposed herein would adopt in most respects the
Commission's current standards for granting market-based rates. We
believe these standards have, with the exceptions noted below, allowed
the Commission to distinguish between applicants that have market power
and those that do not. For example, the current interim horizontal
(generation) market power screens \9\ have allowed the Commission to
identify a number of smaller applicants that do not have generation
market power. The Commission authorized these applicants to obtain or
retain market-based rate authority, which benefits customers by
encouraging new entry and by providing them with the greater
flexibility in product offerings that market-based rate approval
conveys. The current screens also have allowed the Commission to more
accurately identify instances where certain larger sellers may possess
market power. If an applicant fails our screens, this does not,
however, constitute a definitive finding of market power. Rather, our
current standards allow any applicant that fails these screens to
demonstrate that it lacks market power in generation using the
delivered price test (DPT).\10\ The DPT has provided appropriate
flexibility in allowing the Commission to consider the differing
factual situations of particular sellers, such as those that have a
responsibility for serving native load customers. The Commission
proposes to continue to apply the DPT in such a flexible manner.
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\9\ As discussed below, the Commission proposes to henceforth
refer to the generation market power analysis as the horizontal
market power analysis.
\10\ See April 14 Order at P 106 (``The [DPT] defines the
relevant market by identifying potential suppliers based on market
prices, input costs, and transmission availability, and calculates
each suppliers' economic capacity and available economic capacity
for each season/load condition. The results of the [DPT] can be used
for pivotal supplier, market share and market concentration
analyses.'').
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9. In cases where the applicant has failed the DPT, or has
otherwise chosen to adopt default cost-based mitigation or to propose
other cost-based mitigation (e.g., cost-based rates) or tailored
mitigation, our current policies protect customers by ensuring that
applicants with market power in a given area have that market power
mitigated. We recognize, however, that there has been uncertainty
regarding the rate methodologies to use in developing cost-based market
power mitigation and the effectiveness of the existing cost-based
mitigation. We therefore seek comment in this rulemaking on several
issues relating to cost-based market power mitigation, including: (i)
Whether there should be a standard methodology for determining cost-
based ceiling rates and the appropriate methodology for sales of less
than one week; (ii) whether selective discounting should be allowed for
sellers that have been found to have market power, or that accept a
presumption of market power, and are offering power under cost-based
rates; and (iii) whether a mitigated seller that seeks to sell excess
power generated within a mitigated market should be required to first
offer its available capacity at cost-based rates to customers within
the mitigated market.
10. We also propose certain modifications to the horizontal
(generation) market power screens to reflect our experience in applying
them and the comments received in this proceeding. First, the
Commission proposes to modify the treatment of newly-constructed
generation to avoid a situation in which all generation becomes exempt
from our market power analyses as new generation is constructed and
older (pre-1996) generation is retired. Second, although we propose to
retain the default relevant geographic market (control area), we
provide guidance as to the factors the Commission will consider in
evaluating whether, in a particular case, to adopt an expanded
geographic market instead of relying on the default geographic market.
Third, we propose to change the native load proxy for the market share
screens from the minimum peak day in the season to the average peak
native load, averaged across all days in the season, and to clarify
that native load can only include load attributable to native load
customers as that term is defined insection 33.3(d)(4)(i) of the
Commission's regulations.\11\ Fourth, we propose to allow applicants
the option of using seasonal capacity instead of nameplate
capacity,\12\ and to retain the snapshot in time approach for the
screens but to allow ``known and measurable'' changes (sometimes
referred to as foreseeable and reasonably certain at the time of
filing) for the DPT.
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\11\ 18 CFR 33.3(d)(4)(i) (2005).
\12\ Nameplate capacity is the full-load continuous rating of a
generator, prime mover, or other electric power production equipment
under specific conditions as designated by the manufacturer.
Installed generator nameplate rating is usually indicated on a
nameplate physically attached to the generator.
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11. With regard to vertical market power and, in particular,
transmission market power, the Commission proposes to continue the
current policy under which an open access transmission tariff (OATT) is
deemed to mitigate a seller's transmission market power.\13\ However,
in recognition of the fact that OATT violations may nonetheless occur,
we propose that violation(s) of the OATT may be cause to revoke market-
based rate authority in addition to any other applicable remedies, such
as civil penalties. We also note that concerns regarding the adequacy
of the current OATT will be addressed in Docket No. RM05-25-000,
Preventing Undue Discrimination and Preference in Transmission Service.
We are today issuing a Notice of Proposed
[[Page 33104]]
Rulemaking to reform the OATT in that docket.
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\13\ 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., Regulations Preambles January 1991-June 1996 ] 31,036 (1996),
order on reh'g, Order No. 888-A, 62 FR 12,274 (March 14, 1997), FERC
Stats. & Regs., Regulations Preambles July 1996-December 2000 ]
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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12. With regard to vertical market power and, in particular, other
barriers to entry, we propose to continue our current approach but
provide clarification of what types of factors we would examine and we
propose to combine the other barriers to entry analysis with the rest
of our vertical market power analysis.
13. With regard to affiliate abuse, the Commission proposes to
discontinue referring to affiliate abuse as a separate ``prong'' of our
analysis and instead proposes to codify in our regulations an explicit
requirement that any seller with market-based rate authority must
comply with the affiliate sales restrictions and other affiliate
provisions.\14\ The Commission proposes to address affiliate abuse by
requiring that the conditions set forth in the proposed regulations be
satisfied on an ongoing basis as a condition of obtaining and retaining
market-based rate authority. The Commission proposes to retain its
policy that sales of power between a franchised public utility and any
of its non-regulated power sales affiliates \15\ must be pre-approved
by the Commission. To demonstrate that an affiliate sale is just,
reasonable and not unduly discriminatory, an applicant has several
options, including pricing that sale at a market index that meets
certain standards, conducting an auction that reflects certain
guidelines, or otherwise meeting the standards set forth in Edgar.\16\
An affiliate sale that has not been pre-approved under these standards
will constitute a tariff violation. In addition, we reaffirm that the
Commission currently requires that sales made under market-based rate
tariffs, including those made to affiliates, must be reported in an
Electric Quarterly Report (EQR). With regard to affiliate transactions
under a market-based rate tariff, we reaffirm that we either grant or
deny authorization to make affiliate sales. To the extent that we
authorize an affiliate transaction, we reaffirm that, consistent with
the Commission's regulations,\17\ any such agreement shall not be filed
with the Commission.
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\14\ In the case of non-exempt wholesale generator (EWG) public
utilities, for matters arising under Part II of the FPA, the term
``affiliate'' is defined as that term is used in section 358.3(b)
and (c) (formerly section 161.2) of the Commission's regulations.
Section 358.3(b) defines ``affiliate'' as ``another person which
controls, is controlled by, or is under common control with, such
person.'' Section 358.3(c) states that ``control (including the
terms `controlling,' `controlled by,' and `under common control
with') * * * includes, but is not limited to, the possession,
directly or indirectly and whether acting alone or in conjunction
with others, of the authority to direct or cause the direction of
the management or policies of a company. A voting interest of 10
percent or more creates a rebuttable presumption of control.'' The
term ``affiliate'' in the case of EWG public utilities is defined as
``any company, 5 percent or more of the outstanding voting
securities of which are owned, controlled or held with power to
vote, directly or indirectly, by such company.'' See Repeal of the
Public Utility Holding Company Act of 1935 and Enactment of the
Public Utility Holding Company Act of 2005, Order No. 667-A, 71 FR
28446 (May 16, 2006), FERC Stats. & Regs. ] 31,096 (2006). (To be
codified at 18 CFR section 366.1 (2006).)
\15\ By ``non-regulated'' power sales affiliate, the Commission
is referring to non-traditional power sellers including a power
marketer, EWG, qualifying facilities (QFs), or other power seller
affiliate, whose power sales are not regulated on a cost basis under
the FPA.
\16\ Boston Edison Company Re: Edgar Electric Energy Co., 55
FERC ] 61,382 (1991) (Edgar) (Describing types of evidence that can
be used to demonstrate lack of affiliate abuse.)
\17\ See 18 CFR 35.1(g) (2005).
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14. We also propose certain reforms to streamline the
administration of the market-based rate program. As discussed more
fully below, in an effort to streamline and simplify the market-based
rate program in general, while maintaining a high degree of oversight,
the Commission proposes several changes and clarifications. Significant
areas of modification involve the three-year updated market power
analysis (triennial review or updated market power analysis) that all
sellers with market-based rate authority are required to file, and the
development of a market-based rate tariff of general applicability.
15. With regard to updated market power analyses, the Commission's
current general practice is to require an updated market power analysis
to be submitted within three years from the date of the Commission
order granting the seller market-based rate authority or accepting the
previous triennial review. The Commission proposes to modify that
general practice and put in place a structured, systematic review to
assist the Commission in analyzing sellers in markets based on a
coherent and consistent set of data. In particular, the Commission
proposes to modify the requirements for filing updated market power
analyses in two ways. First, the Commission proposes to establish two
categories of sellers with market-based rate authorization. The first
category, Category 1 (approximately 550 sellers), would consist of
power marketers and power producers that own or control 500 MW or less
of generating capacity in aggregate and that are not affiliated with a
public utility with a franchised service territory. In addition,
Category 1 sellers must not own or control transmission facilities,
other than limited equipment necessary to connect individual generating
facilities to the transmission grid, (or must have been granted waiver
of the requirements of Order No. 888 because such facilities are
limited and discrete and do not constitute an integrated grid \18\) and
must present no other vertical market power issues. Category 1 sellers
would not be required to file a regularly scheduled triennial review.
The Commission would monitor any market power concerns for these
sellers through the change in status reporting requirement,\19\ and
through ongoing monitoring by the Commission's Office of Enforcement.
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\18\ See, e.g., Black Creek Hydro, Inc., 77 FERC ] 61,232
(1996).
\19\ See 18 CFR 35.27(c) (2005) (reporting requirement for any
change reflecting a departure from the characteristics the
Commission relied upon in granting market-based rate authority).
Failure to timely file a change in status report would constitute a
tariff violation.
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16. The second category, Category 2 (approximately 600 sellers),
would include all sellers that do not qualify for Category 1. Category
2 sellers, in addition to the change in status reports, would be
required to file regularly scheduled triennial reviews.\20\ To ensure
greater consistency in the data used to evaluate Category 2 sellers,
the Commission proposes to require each Category 2 seller to file
updated market power analyses for its relevant geographic markets
(default and any proposed alternative markets) on a schedule that will
allow examination of the individual seller at the same time that the
Commission examines other sellers in these relevant markets and
contiguous markets within a region from which power could be imported.
The Commission would continue to make findings on an individual seller
basis, but would have before it a complete picture of the uncommitted
capacity and simultaneous import capability into the relevant
geographic markets under review.
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\20\ Failure to timely file a triennial review would constitute
a tariff violation.
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17. A second significant change is our proposal to adopt a market-
based rate tariff of general applicability (MBR tariff), applicable to
all sellers authorized to sell electric energy, capacity or ancillary
services at wholesale at market-based rates. Further, the Commission
proposes that, rather than each entity having its own MBR tariff, which
can result in dozens of tariffs for each corporate family with
potentially conflicting provisions, each corporate family would have
only one tariff, with all affiliates with market-based rate authority
separately
[[Page 33105]]
identified in the tariff. This will reduce the administrative burden
and confusion that occurs when there are multiple, and potentially
conflicting, tariffs in a single corporate family. Our intent to
streamline the terms of an MBR tariff is not to reduce the flexibility
of sellers and customers in negotiating the terms of individual
transactions. Rather, this flexibility will continue to exist. The
purpose of a tariff of general applicability that requires the seller
to comply with the applicable provisions of the market-based rate
regulations is simply to codify, on a consistent basis, the basic
requirements of market-based rate authorization.
III. Discussion
A. Horizontal Market Power
1. Current Policy
a. Test for Generation Market Power.
18. In the April 14 Order, the Commission adopted two indicative
screens for assessing generation market power that provide a rebuttable
presumption of whether market power exists for a utility applying to
obtain or retain market-based rate authority. Sellers that do not pass
the initial screens are, among other things, allowed to provide
additional evidence for Commission consideration. Such an approach
allows the Commission to concentrate its efforts on sellers that may
possess generation market power while screening out those sellers that
do not pose such concerns.
19. The Commission uses two indicative screens for assessing
whether a particular seller raises any generation market power
concerns, each with its own specific focus and attributes: a pivotal
supplier analysis based on uncommitted capacity at the time of the
market's annual peak demand; and a market share analysis of uncommitted
capacity applied on a seasonal basis. If a seller passes both screens,
there is a rebuttable presumption that the seller does not possess
market power in generation. However, the Commission allows intervenors
to present evidence to rebut the presumption. On the other hand, if a
seller fails either screen, this creates a rebuttable presumption that
market power exists in generation.\21\ In this instance, the seller
may: (1) File a more robust market power study, the DPT; \22\ (2) file
a mitigation proposal tailored to its particular circumstances that
would eliminate the ability to exercise market power; or (3) inform the
Commission that it will either adopt the default cost-based rates
discussed in the April 14 Order or propose other cost-based rates and
submit cost support for such rates. Before the Commission considers the
DPT, the seller must be found to have failed one (or both) of the two
indicative screens or so concede.\23\ Accordingly, the DPT is
considered as an alternative study to support the grant or continuation
of market-based rate authority. In all cases, the seller or intervenors
may present evidence such as historical wholesale sales data to support
their opinion of whether the seller does or does not possess market
power.
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\21\ In such a case, the Commission will institute a section 206
proceeding and such a seller's rates prospectively will be made
subject to refund until a final determination of market power is
made or the seller accepts a presumption of market power and so
mitigates. April 14 Order, 107 FERC ] 61,018 at n. 10.
\22\ The only additional market power study allowed is the DPT.
However, the Commission allows such sellers to present evidence,
based on historical wholesale sales data, in support of a contention
that, notwithstanding the results of the two indicative screens,
they do not possess market power.
\23\ April 14 Order, 107 FERC ] 61,018 at P 37.
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20. Section 35.27(a) of the Commission's regulations states that
``any public utility seeking authorization to engage in sales for
resale of electric energy at market-based rates shall not be required
to demonstrate any lack of market power in generation with respect to
sales from capacity for which construction has commenced on or after
July 9, 1996.'' \24\ Sellers meeting the criteria of section 35.27(a)
of our regulations, as clarified in LG&E Capital,\25\ may provide
evidence demonstrating that they satisfy this section of our
regulations rather than submit a generation market power analysis.
However, if a seller sites generation in an area where it or its
affiliates own or control other generation assets, the seller must
provide an analysis regarding whether its new capacity (i.e., post-July
9, 1996), when added to existing capacity, raises generation market
power concerns.
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\24\ 18 CFR 35.27(a) (2005).
\25\ LG&E Capital Trimble County LLC, 98 FERC ] 61,261 (2002)
(LG&E Capital).
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21. Alternatively, a seller may forego submitting a generation
market power analysis and accept a presumption of market power and go
directly to mitigation by proposing case-specific mitigation that
eliminates the ability to exercise market power, or agreeing to the
default rates discussed below. Under such circumstances there will be a
presumption of market power in all of the default relevant markets.
22. If a seller's proposed mitigation \26\ does not eliminate its
ability to exercise market power, then the seller may not charge
market-based rates in the geographic area(s) where market power is
found, and the seller is subject to cost-based default rates or other
cost-based rates that the seller proposes and the Commission approves.
The Commission's default rates are as follows: (1) Sales of power of
one week or less must be priced at the seller's incremental cost plus a
10 percent adder; (2) sales of power of more than one week but less
than one year must be priced at an embedded cost ``up to'' rate
reflecting the costs of the unit or units expected to provide the
service; and (3) new contracts for sales of power for one year or more
must be priced at a rate not to exceed the embedded cost of service,
and the contract must be filed with the Commission for review.
Mitigated sellers must first receive Commission approval for each long-
term power sale prior to transacting.\27\
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\26\ Proposals for alternative mitigation in these circumstances
could include cost-based rates or other mitigation that the
Commission may deem appropriate. For example, an applicant could
propose to transfer operational control of enough generation to a
third party such that the applicant would satisfy our generation
market power concerns.
\27\ The Commission notes here that, to the extent a party
believes market power is being exerted in the course of negotiating
a long-term purchase, such party may file a complaint pursuant to
section 206 of the FPA.
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b. Additional Requirement for Transmission Owners.
23. In addition, a seller that owns, operates or controls
transmission is required to conduct simultaneous transmission import
capability studies for its home control area and each of its directly-
interconnected first-tier control areas consistent with the
requirements set forth in the April 14 Order, as clarified in Pinnacle
West Capital Corp., 110 FERC ] 61,127 (2005). These studies are used in
the pivotal supplier screen, market share screen, and DPT to
approximate the transmission import capability. When centering the
generation market power analysis on the transmission providing
utility's first-tier control area (i.e., markets), the transmission-
providing seller should use the methodologies consistent with its
implementation of its Commission-approved OATT, thereby making a
reasonable approximation of simultaneous import capability that would
have been available to suppliers in surrounding first-tier markets
during each seasonal peak. The transfer capability should also include
any other limits (such as stability, voltage, Capacity Benefit Margin,
or
[[Page 33106]]
Transmission Reliability Margin) as defined in the tariff and that
existed during each seasonal peak. The ``contingency'' model should use
the same assumptions used historically by the transmission provider in
approximating its control area import capability.
24. A seller may provide a streamlined application to show that it
passes the indicative screens. Thus, with respect to simultaneous
import capability, if a seller can show that it passes the screens for
each relevant geographic market without considering imports, no such
simultaneous import analysis needs to be provided. Further, the
Commission recognizes that certain sellers will not have the ability to
perform a simultaneous import capability study. Accordingly, if a
seller demonstrates that it is unable to perform a simultaneous import
capability study for the control area in which it is located, the
seller may propose to use a proxy amount for transmission limits. Such
proposals are considered on a case-by-case basis.
c. Relevant Geographic Markets.
25. The default relevant geographic markets under both screens are
first, the control area market where the seller is physically located,
and second, the markets directly interconnected to the seller's control
area market (first-tier control area markets).\28\ In this default
analysis, the Commission considers only those supplies that are located
in the market being considered (relevant market) and those in first-
tier markets to the relevant market. Sellers located in and a member of
regional transmission organizations (RTO)/independent system operators
(ISO) \29\ that perform functions such as single central commitment and
dispatch with a single energy market and Commission-approved market
monitoring and mitigation may consider the geographic region under the
control of the RTO/ISO as the default relevant geographic market for
purposes of completing their analyses.\30\ Currently, these markets are
operated by PJM Interconnection, LLC (PJM), ISO New England, Inc. (ISO-
NE), New York Independent System Operator, Inc. (NYISO), Midwest
Independent Transmission System Operator (Midwest ISO) and California
Independent System Operator Corporation (CAISO). For sellers whose
assets are physically located geographically within the RTO/ISO
boundaries, there is only one default relevant market for those assets,
and that is the RTO/ISO in which they are located and are a member.
Likewise, where a generator is interconnecting to a non-affiliate owned
transmission system, there is only one relevant market, the control
area in which the generator is located.
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\28\ For applications by sellers with no physical generation
assets (such as power marketers) and that are affiliated with
generation asset owning utilities, the Commission evaluates the
affiliate generation owner's market power when evaluating whether to
grant market-based rate authority for the power marketer.
\29\ We note that the membership status described is such that
the seller that owns transmission facilities other than limited
equipment necessary to connect individual generating facilities to
the transmission grid has turned over operational control of those
transmission assets to the RTO/ISO.
\30\ LG&E Energy Marketing, Inc., 111 FERC ] 61,153 (2005)
(noting that where applicants are members of the Midwest ISO and
their control area is within the Midwest ISO geographic footprint,
the default relevant geographic market for the generation market
power analyses is the Midwest ISO).
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26. The Commission allows sellers and intervenors to present
additional sensitivity runs as part of their market power studies to
show that some other geographic market should be considered as the
relevant market in a particular case. For example, sellers or
intervenors can present evidence that the relevant market is broader
(or more limited) than a particular control area. However, applicants
presenting evidence that the relevant market is larger or smaller than
the default relevant market must first complete the screens based on
the default market as discussed above. To the extent some other
geographic market is studied, the proponent of using that alternative
market must adhere to including all monitored lines/constraints and
critical contingencies that were historically applied during the
seasonal peaks in assessing available transmission for non-affiliate
transmission customers (i.e., consistent with Open Access Same-Time
Information System (OASIS)). Sellers and intervenors may also provide
evidence that, because of internal transmission limitations (e.g., load
pockets), the relevant market is smaller than the control area.
d. Performance of the Indicative Screens.
27. Both the pivotal supplier analysis and the market share
analysis recognize utilities' obligations to serve native load. Because
utilities generally use the same generating units to make off-system
wholesale sales and to serve native load, and because the amount of
generation needed to serve native load can vary from hour to hour, some
reasonable proxy is needed to represent the amount of generation that
is needed to serve native load. Accordingly, the pivotal supplier
analysis, for both sellers and competing suppliers, uses the average of
the daily native load peaks during the month in which the annual peak
demand day occurs as a proxy for native load obligation. The market
share analysis for both sellers and competing suppliers uses the native
load obligation on the minimum peak demand day for a given season.
28. In the pivotal supplier screen, a market participant's
uncommitted capacity is determined by adding the total nameplate
capacity of generation owned or controlled through contract and firm
purchases, less operating reserves, native load commitments and long-
term firm sales. To calculate the net uncommitted supply available to
compete at wholesale, the wholesale load proxy (annual peak load less
the native load proxy discussed above) is deducted from total
uncommitted capacity in the market.\31\ If the seller's uncommitted
capacity is equal to or greater than the net uncommitted supply, then
the seller fails the pivotal supplier analysis, which creates a
rebuttable presumption of market power.
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\31\ April 14 Order, 107 FERC ] 61,018 at P 99.
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29. In the market share analysis, uncommitted capacity is defined
similarly to the pivotal supplier screen, with the additional deduction
for planned outages that were done in accordance with good utility
practice. Under the market share analysis, a seller that has less than
a 20 percent market share in the relevant market for all seasons is
considered to satisfy the market share analysis.\32\ A seller with a
market share of 20 percent or more in the relevant market for any
season has a rebuttable presumption of market power but can present
historical evidence to show that the seller satisfies the Commission's
generation market power concerns.\33\
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\32\ The 20 percent threshold is consistent with section 4.134
of the U.S. Department of Justice 1984 Merger Guidelines issued June
14, 1984, reprinted in Trade Reg. Rep. P13,103 (CCH 1988): ``The
Department [of Justice] is likely to challenge any merger satisfying
the other conditions in which the acquired firm has a market share
of 20 percent or more.''
\33\ The other evidence the Commission will consider is
historical sales and/or access to transmission to move supplies
within, out of, and into a control area market.
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30. In addition, any seller, regardless of size, has the option of
making simplifying assumptions in its analysis where appropriate. In
performing all screens, sellers are required to prepare them as
designed,\34\ and must use the most recently available unadjusted 12
[[Page 33107]]
months' historical data as a snapshot in time.\35\ Sellers filing
abbreviated studies may request waiver of the full data requirements.
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\34\ Sellers presenting evidence that the relevant market is
larger or smaller than the default relevant market (i.e., control
area) must first complete the screens based on the default relevant
geographic market.
\35\ The Commission clarified on rehearing that it will allow
adjustments necessary to perform the screens if the seller fully
justifies the need for and methodology used for the adjustment and
files all workpapers supporting the adjustments and documenting the
source data used. July 8 Order, 108 FERC ] 61,026 at P 119.
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e. The Delivered Price Test (DPT).
31. Sellers failing one or more of the initial screens will have a
rebuttable presumption of market power. If such a seller chooses not to
proceed directly to mitigation, it must present a more thorough
analysis using the Commission's DPT.\36\ The DPT is used to analyze the
effect on competition for transfers of jurisdictional facilities in
section 203 proceedings,\37\ using the framework described in Appendix
A of the Merger Policy Statement as revised in Order No. 642.\38\ The
DPT is an established test that has been used routinely to analyze
market power in the merger context for many years, and it has been
affirmed by the courts.\39\
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\36\ April 14 Order, 107 FERC ] 61,018 at P 105-12.
\37\ 16 U.S.C. 824b (2000).
\38\ Inquiry Concerning the Commission's Merger Policy Under the
Federal Power Act: Policy Statement, Order No. 592, 61 F.R. 68595
(1996), FERC Stats. & Regs., Regulations Preambles July 1996-
December 2000 ] 31,044 (1996), reconsideration denied, Order No.
592-A, 62 F.R. 33341 (1997), 79 FERC ] 61,321 (1997) (Merger Policy
Statement); see also Revised Filing Requirements Under Part 33 of
the Commission's Regulations, Order No. 642, 65 F.R. 70984 (2000),
FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ]
31,111 (2000), order on reh'g, Order No. 642-A, 66 F.R. 16121
(2001), 94 FERC ] 61,289 (2001).
\39\ See, e.g., Wabash Valley Power Associates, Inc. v. FERC,
268 F. 3d 1105 (D.C. Cir. 2001).
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32. The DPT defines the relevant market by identifying potential
suppliers based on market prices, input costs, and transmission
availability, and calculates each supplier's economic capacity and
available economic capacity for each season/load period.\40\ The
results of the DPT are used for pivotal supplier, market share and
market concentration analyses. Using the economic capacity for each
supplier, sellers are required to provide pivotal supplier, market
share and market concentration analyses. Examining these three measures
with the more robust output from the DPT allows sellers to present a
more complete view of the competitive conditions and their positions in
the relevant markets.
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\40\ Super-peak, peak, and off-peak, for Winter, Shoulder and
Summer periods and an additional highest super-peak for the Summer.
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33. Under the DPT, to determine whether a seller is a pivotal
supplier in each of the season/load periods, sellers are required to
compare the load in the relevant market to the amount of competing
supply. The seller will be considered pivotal if the sum of the
competing suppliers' economic capacity is less than the load level plus
a reserve requirement for the relevant period. The analysis using
available economic capacity to account for sellers' and competing
suppliers' native load commitments is also required.
34. Each supplier's market share is calculated based on economic
capacity, the DPT's analog to installed capacity. The market shares for
each season/load period reflect the costs of the seller's and competing
suppliers' generation, thus giving a more complete picture of the
seller's ability to exercise market power in a given market.
35. Sellers preparing a DPT also must calculate the market
concentration using the Hirschman-Herfindahl Index (HHI) based on
market shares.\41\ For the DPT, a showing of an HHI less than 2,500 in
the relevant market for all season/load periods for sellers that have
also shown that they are not pivotal and do not possess more than a 20
percent market share in any of the season/load periods would constitute
a showing of a lack of market power, absent compelling contrary
evidence. We will, however, consider all relevant facts and
circumstances in reviewing a DPT, (including native load obligations),
and we will balance the record evidence in determining whether or not
the seller has generation market power. Thus, even sellers that exceed
the foregoing thresholds may receive market-based rates under
appropriate circumstances.\42\
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\41\ The HHI is the sum of the squared market shares. For
example, in a market with five equal size firms, each would have a
20 percent market share. For that market, HHI = (20)2 +
(20)2 + (20)2 + (20)2 +
(20)2 = 400 + 400 + 400 + 400 + 400 = 2,000.
\42\ See, e.g., Kansas City Power & Light Co., 113 FERC ] 61,074
at P 30-35 (2005) (Kansas City); Acadia Power Partners, LLC, 113
FERC ] 61,073 at P 40-45 (2005) (Acadia).
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36. Sellers and intervenors may present evidence such as historical
wholesale sales data, which can be used to calculate market shares and
market concentration and to refute or support the results of the DPT.
The Commission encourages sellers to present the most complete analysis
of competitive conditions in the market as the data allow. In this
regard, the Commission allows the introduction of such evidence beyond
the most recent 12 months. The use of unadjusted historical sales and
transmission data will provide an accurate depiction of actual market
activity. Therefore, the Commission requires sellers submitting
historical sales and transmission data as evidence to submit the actual
data.
37. The FPA requires that all rates charged by public utilities for
the transmission or sale for resale of electric energy be just and
reasonable.\43\ Thus, where a market-based rate seller is found to have
market power in generation (e.g., after reviewing a seller's DPT), it
is incumbent upon the Commission to either reject such rates or to
ensure that adequate mitigation measures are in place to ensure that
the rates are just and reasonable. The Commission provides default
cost-based rates to ensure that wholesale rates are just and
reasonable. If a seller does not pass the generation market power
screens, or foregoes the screens entirely, the Commission sets the just
and reasonable rate at the default cost-based rate unless it approves
different mitigation based on case-specific circumstances.
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\43\ 16 U.S.C. 824d(a) (2000).
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38. For sellers that have a presumption of market power in
generation (e.g. those failing one or both of the indicative screens),
the Commission will institute a section 206 proceeding and the seller's
rates will prospectively be made subject to refund.\44\ For sellers
already charging market-based rates, market-based rates will not be
revoked and cost-based rates will not be imposed until the Commission
issues an order making a definitive finding that the seller has market
power in generation (typically, after the Commission has ruled on a DPT
analysis) or, where the seller accepts a presumption of market power,
an order is issued addressing whether default cost-based rates or case-
specific cost-based rates are to be applied. The Commission will revoke
the market-based rate authority in all geographic markets where a
seller is found to have market power in generation.\45\
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\44\ The refund floor would be the default cost-based rates or,
if applicable, any case-specific cost-based rates proposed by the
seller and accepted by the Commission. Accordingly, the seller has
certainty as to its potential refund obligation, if any. April 14
Order, 107 FERC ] 61,018 at n. 143.
\45\ The seller has the option of withdrawing its market-based
rate request in whole or in part.
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2. Proposal
39. The Commission adopted the indicative generation market power
screens in the April 14 Order for interim purposes, and instituted the
instant rulemaking proceeding to, among other things, review of these
screens and, as a whole, the horizontal market power portion of the
Commission's four-prong analysis. The Commission has gained
[[Page 33108]]
considerable experience with the analysis since the April 14 Order and
believes that in general the current screens work well to identify the
subset of sellers that require additional review. Therefore, we propose
to continue to use the screens adopted in the April 14 Order as well as
the overall approach to analyzing generation market power set forth in
the April 14 Order, including the procedural options available to
sellers and the use of the DPT. However, commenters have raised some
valid concerns and, accordingly, the Commission proposes certain
modifications to the screens as adopted in the April 14 Order, such as
adjustments to the native load proxy. Furthermore, while reaffirming
the screens, we propose that henceforth these screens should be
referred to as our horizontal market power analysis. In particular, our
horizontal analysis will include, as discussed in the April 14 Order,
the two indicative screens and the DPT as necessary.
a. Indicative Screens and DPT Criteria.
40. Because the indicative screens are intended only to identify
the sellers that require further review, we propose to retain the 20
percent threshold for the wholesale market share screen. The screens
are indicative, not definitive. Indeed, pursuant to the horizontal
market power analysis where an applicant is seeking to obtain or retain
market-based rate authority, the Commission will not make a definitive
finding that a seller has market power unless and until the more robust
analysis, the DPT, is considered. Instead, where a seller fails one of
the indicative screens, a section 206 proceeding is instituted to more
closely examine a seller's potential for exercising horizontal market
power and does not mean a definitive finding has been made. Failure to
pass either of the indicative screens creates a rebuttable presumption
of market power. A seller that fails the initial screens is given 60
days from the date of issuance of an order finding a screen failure to:
(1) File a DPT analysis; (2) file a mitigation proposal tailored to its
particular circumstances that would eliminate the ability to exercise
market power; or (3) inform the Commission that it will adopt the
default cost-based rates or propose other cost-based rates and submit
cost support for such rates.\46\
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\46\ April 14 Order, 107 FERC ] 61,018 at P 208.
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41. Some commenters argue that the 20 percent threshold is too low;
others argue that it is too high. The Commission believes that the 20
percent threshold strikes the right balance in seeking to avoid both
``false negatives'' and ``false positives'' and proposes to continue
using 20 percent. Because the presumption of horizontal market power
established by the failure of the wholesale market share screen is
rebuttable, coupled with the adjustment to the native load proxy
discussed below, sellers should be assured that the 20 percent
threshold is not unnecessarily stringent.
42. We also propose to continue the use of annual peak load in the
pivotal supplier analysis and not to expand the pivotal supplier
analysis to include monthly assessments. The pivotal supplier analysis
examines the seller's market power during the annual peak. The hours
near that point in time are the most likely times that a seller will be
a pivotal supplier.
43. Similarly, for the DPT analysis, we propose to retain our
current threshold including 2,500 for HHIs, as well as our current
practice of weighing all the relevant factors in the analysis, in
determining whether a seller does or does not have horizontal market
power. We propose to continue to do so on a case-by-case basis,
weighing such factors as available economic capacity, economic
capacity, HHIs, and other historical wholesale sales data. The
thresholds are well-established and appropriate, allowing the
Commission to make a reasoned determination after reviewing all the
evidence in the record. The DPT does not function like the initial
screens in that the failure of either the economic capacity or
available economic capacity analyses does not result in an automatic
failure as a whole.\47\
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\47\ Kansas City, 113 FERC ] 61,074 at P 30; Acadia, 113 FERC ]
61,073 at P 40.
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b. Native Load.
44. To reduce the number of ``false positives'' in the wholesale
market share screen, however, we propose to adjust the native load
proxy. Many commenters have noted that the current native load proxy
for the market share screen is too limited and results in too much
uncommitted capacity attributable to the seller. The Commission stated
in the April 14 Order that by using the two screens together, the
Commission is able to measure market power both at peak and off-peak
times, and the ability to exercise market power both unilaterally and
in coordinated interaction with other sellers. In the April 14 Order,
the Commission adopted the native load proxy for the wholesale market
share screen in order to balance the concerns of market participants.
We now believe that the current proxy used in the market share screen
may be too conservative. Accordingly, the Commission proposes to change
the allowance for the native load deduction under the market share
screen from the minimum native load peak demand for the season to the
average native load peak demand for the season. This change makes the
deduction for the market share screen consistent with the deduction
allowed under the pivotal supplier screen. We propose to retain a
season-by-season analysis. For example, the proxy for summer would be
the average native load peak for June, July and August. The pivotal
supplier screen's native load proxy would remain unchanged from its
current proxy of the average of the daily native load peaks during the
month in which the annual peak day load occurs. We seek comments on our
proposal.
45. We believe there has been some inconsistency in the way in
which sellers have reflected native load in performing both the screens
and the DPT analysis. For this reason, we also propose to clarify that
for the horizontal market power analysis, native load can only include
load attributable to native load customers as defined in section
33.3(d)(4)(i) of the Commission's regulations,\48\ as it may be revised
from time to time. We seek comments on this proposal.
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\48\ 18 CFR 33.3(d)(4)(i) provides: Native load commitments are
commitments to serve wholesale and retail power customers on whose
behalf the potential supplier, by statute, franchise, regulatory
requirement, or contract, has undertaken an obligation to construct
and operate its system to meet their reliable electricity needs.
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c. Control and Commitment of Generation.
46. The Commission stated that uncommitted capacity is determined
by adding the total capacity of generation owned or controlled through
contract and firm purchases less, among other things, long-term firm
requirements sales that are specifically tied to generation owned or
controlled by the seller and that assign operational control of such
capacity to the buyer.\49\ The Commission further stated that long-term
firm load following contracts may be deducted to the extent that the
seller has included in its total capacity a corresponding generating
unit or long-term firm purchase that will be used to meet the
obligation even if such contracts are not tied to a specific generating
unit and do not convey operational control of the generation.\50\
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\49\ July 8 Order, 108 FERC ] 61,026 at P 65.
\50\ Id. at P 66.
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47. The Commission has stated that contracts can confer the same
rights of control of generation or transmission
[[Page 33109]]
facilities as ownership of those facilities.\51\ In short, if a seller
has control over certain capacity such that the seller can affect the
ability of the capacity to reach the relevant market, then that
capacity should be attributed to the seller when performing the
generation market power screens.\52\ The capacity associated with
contracts that confer operational control of a given facility to an
entity other than the owner must be assigned to the entity exercising
control over that facility, rather than to the entity that is the legal
owner of the facility.\53\
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\51\ Citizens Power and Light Corp., 48 FERC ] 61,210 at 61,777
(1989) (Citizens Power). See also Bechtel Power Corp., 60 FERC ]
61,156 (1992) (finding that an entity that was contractually engaged
to provide operation and maintenance services was not an
``operator'' of jurisdictional facilities because the entity did not
``operate'' the facilities at issue but rather, in essence, was
functioning merely as the owner's agent with respect to the
operation of the jurisdictional facilities); D.E. Shaw Plasma Power,
L.L.C., 102 FERC ] 61,265 at P 33-36 (2003) (D.E. Shaw) (finding
that a power marketer's ``investment adviser'' affiliate was a
public utility where it had sole discretion to determine the trades
to be entered into by the power marketer, as well as the power to
execute the contracts, and therefore operated jurisdictional
facilities rather than acted as merely an agent of the owner); R.W.
Beck Plant Management, Ltd., 109 FERC ] 61,315 at P 15 (2004) (R.W.
Beck) (finding R.W. Beck Plant Management, Ltd. (Beck) was a public
utility subject to the FPA in connection with its activities as
manager of public utility Central Mississippi Generating Company,
LLC because Beck effectively governed the physical operation of
certain jurisdictional transmission and interconnection facilities
and served as the decision-maker in determining sales of wholesale
power).
\52\ July 8 Order, 108 FERC ] 61,026 at P 65.
\53\ Reporting Requirement for Changes in Status for Public
Utilities with Market-Based Rate Authority, Order No. 652, 70 FR
8253 (Feb. 18, 2005), FERC Stats. & Regs., Regulations Preambles
January 2001-December 2005 ] 31,175 at P 47, order on reh'g, Order
No. 652-A, 111 FERC ] 61,413 (2005).
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48. In recent years, some owners have turned to third parties to
manage the day-to-day activities of running and dispatching plants and/
or selling output. Such third-party contractors, often referred to as
energy managers and/or asset managers, can be responsible for multiple
facilities through multiple energy management agreements. These
management agreements may, directly or indirectly, transfer control of
the capacity. The Commission is concerned that there may be instances
where, in effect, control of capacity has changed hands, but this
capacity has not been attributed to the correct seller for purposes of
calculating our market screens.
49. In cases examining whether an entity is a public utility, the
Commission has examined the totality of the circumstances in evaluating
whether the entity effectively has control over capacity that it
manages.\54\ Likewise, in providing guidance regarding events that
trigger a requirement to submit a notice of change in status, the
Commission has indicated that, to determine whether control has been
acquired, sellers should examine whether they can affect the ability of
capacity to reach the relevant market.\55\ Although this analysis is
inherently fact-dependent to some degree, the Commission is interested
in providing greater certainty and clarity in this area, which should
increase the uniformity in reporting capacity and reduce the
possibility of tariff violations. The Commission therefore seeks
comment on whether it should make certain generic findings, or create
certain generic presumptions, regarding the indicia of control.
Specifically, the Commission seeks comment on whether any of the
following functions should merit a finding or presumption of control
and, if so, on what basis: directing outages, fuel procurement, plant
operations, energy and capacity sales, and/or credit and liquidity
decisions. Alternatively, rather than focusing on these discrete items,
should the Commission establish a presumption of control for any entity
that has some discretion over the output of the plant(s) that it
manages? Would such an approach promote greater certainty and better
align the test with the ultimate goal of attributing plant capacity to
those who control its output? If the Commission adopted such a
presumption, how should it address instances where discretion over
plant output may be shared between more than one party? We also propose
to clarify that, in the event we adopt any such presumptions, the
Commission would nonetheless allow individual sellers to rebut the
presumption on the basis of their particular facts and circumstances.
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\54\ D.E. Shaw, 102 FERC ] 61,265 at P 33-36; R.W. Beck, 109
FERC ] 61,315 at P 15.
\55\ Order No. 652, FERC Stats. & Regs. ] 31,175 at P 47.
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50. The Commission also proposes to clarify that an entity (such as
an asset manager or other such entity) that controls generation from
which jurisdictional power sales are made is required to have a rate on
file with the Commission. If the rate authority sought is market-based
rate authority, then that entity is subject to the same conditions and
requirements as any other like seller (e.g., the entity must provide a
horizontal and vertical market power analysis and include in its
horizontal analysis all assets it owns or controls in the relevant
market). If such an entity controls an asset from which jurisdictional
power sales are being made and such entity does not have a rate on
file, it is violating section 205 of the FPA.\56\ We wish to emphasize,
however, that our intent is not to limit or stifle the provision of
energy management services. These services can provide benefits to
customers and the marketplace. Rather, our intent is to provide greater
certainty and clarity as to when such arrangements confer control so
that the capacity being controlled is properly reported and the entity
assuming such control has received the necessary authorizations under
the FPA for providing jurisdictional services.
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\56\ 18 U.S.C. 824d (c) (2000).
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d. Relevant Geographic Market.
51. The Commission proposes to continue to use its current approach
with regard to the relevant geographic market. The default relevant
geographic market is the control area where the seller is physically
located and the control areas directly interconnected to that control
area (with the exception of a generator interconnecting to a non-
affiliate owned or controlled transmission system, in which case the
relevant market is only the control area in which the seller is
located). The Commission also proposes to continue to designate the
RTO/ISO in which a seller is located and is a member as the default
relevant geographic market for RTO/ISOs with sufficient market
structure and a single energy market, and not require sellers to
consider, as part of the relevant market, markets first-tier to the
RTO/ISO in which the seller is located and is a member.\57\ We believe
that designating a default relevant geographic market provides sellers
and intervenors a measure of certainty regarding the relevant market.
We note that the default market seems to be acceptable to most sellers
as there have been relatively few sellers who have proposed to expand
or contract the default relevant geographic market.
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\57\ April 14 Order, 107 FERC ] 61,018 at P 187.
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52. We note that the North American Electric Reliability Council
(NERC) no longer uses the designation of control area since it approved
the ``NERC Reliability Functional Model'' on February 10, 2004. We seek
comment as to whether or not the adoption of the NERC functional model
should change the criteria for specifying the default relevant
geographic market, and if so, in what way it should be specified and
how readily available is the relevant data.
53. The Commission proposes to continue to provide flexibility by
[[Page 33110]]
allowing sellers and intervenors to present evidence that the market is
smaller or larger than the default market. To that end, we propose to
provide guidance regarding the demonstration that a relevant geographic
market is larger than a default geographic market by identifying the
types of factors the Commission will consider in evaluating whether to
adopt an expanded geographic market in a particular case instead of
relying on the default geographic market (generally, the control area).
54. Reaching beyond the default market in which an entity is
located can mean addressing additional physical and other challenges
than when trading within that market. When assessing an expanded
geographic market pursuant to the horizontal analysis, the Commission
looks for assurance that no frequently recurring physical impediments
to trade exist within the expanded market that would prevent competing
supply in the expanded area from reaching wholesale customers. Any
proposal to use an expanded market (i.e., a market other than the
default geographic market) should include a demonstration regarding
whether there are frequently binding transmission constraints during
historical seasonal peaks examined in the screens and at other
competitively significant times that prevent competing supply from
reaching the customers within the expanded market. In this regard, we
propose to require that a demonstration be made based on historical
data. In addition, we would require that a sensitivity analysis be
performed analyzing under what circumstance(s) transmission constraints
would bind.
55. The Commission also considers whether there is other evidence
that would support the existence of an expanded market. In deciding
whether customers may be considered as part of an expanded geographic
market, the Commission will also consider evidence that they can access
the resources outside of the default geographic market on similar terms
and conditions as those inside the default geographic market.
56. Such evidence submitted to show that the applicant's customers
have access to resources outside of their control area at terms and
conditions similar to those at which they can access resources inside
the control area could be empirical or it could point to factors that
indicate a single market. For example, the Commission has previously
stated that the operation of a single central unit commitment and
dispatch function for the proposed geographic market would be an
indicator of a single market. However, there are other ways to
demonstrate that two or more control areas are indeed a single market.
For example, other evidence of a single market could include a
demonstration that: there is a single transmission rate; there is a
common OASIS platform for scheduling transmission service across
separate control areas; there is a correlation of price movements
between the areas being considered as an expanded geographic market or
other information regarding wholesale transactions in the proposed
single market. Evidence of active trading throughout the proposed
geographic market would also be considered.
57. In determining whether two or more control areas are a single
market the Commission would weigh, on a case-by-case basis, all the
factors presented. As discussed above, there are several factors the
Commission would consider once it has been established that
historically there were no physical impediments to trade, and no one
factor or factors would be dispositive. Rather, all factors will be
considered and as a whole will indicate whether there exists a single
market.
58. We seek comment on our proposed guidance and, in particular,
whether there are other factors the Commission should consider when
assessing a proposed expanded market. Are there any factor(s) that
should be given more weight or are essential in determining the scope
of the market (e.g., are there any factors that, if not satisfactorily
addressed, would preclude the need to consider any other factors)?
Should the Commission apply the same criteria when determining whether
the geographic market is smaller than the default geographic market?
59. In addition, as discussed previously, the Commission proposes
to designate the RTO/ISO in which the seller is located and is a member
as the default relevant geographic market for RTO/ISOs with sufficient
market structure and a single energy market. We believe the added
protections provided in structured markets with market monitoring,
market power mitigation and transparency generally result in a market
where attempts to exercise market power would be sufficiently
mitigated.
60. In the April 14 Order, the Commission identified PJM, ISO-NE,
NYISO, and CAISO as meeting the criteria for being considered a single
market for purposes of performing the generation market power
screens.\58\ The Commission also stated that, applicants can
incorporate the mitigation they are subject to in ISO/RTO markets as
part of their market power analysis. For example, if a market power
study showed that an applicant had local market power, the applicant
could point to RTO mitigation rules as evidence that this market power
has been adequately mitigated. In a later order,\59\ the Commission
found that the Midwest ISO also met the criteria for being considered a
single market for purposes of performing the generation market power
screens.
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\58\ Id. at 187.
\59\ Alliant Energy Corporate Services, Inc., 109 FERC ] 61,289
at P 31 (2004).
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61. However, our experience with corporate mergers and acquisitions
indicates that these same RTOs have, at times, been divided into
smaller submarkets for study purposes because frequently binding
transmission constraints prevent some potential suppliers from selling
into the destination market.\60\ Therefore, the Commission seeks
comment on its approach under the market-based rate program of
considering the entire geographic region under control of the RTO/ISO,
with a sufficient market structure and a single energy market, as the
default relevant geographic market for the horizontal market power
analysis. In particular, should the Commission continue its approach of
considering the entire geographic region as the default relevant
market? Should the Commission consider the entire geographic region for
purposes of the indicative screens but consider RTO/ISO submarkets for
purposes of the DPT. In addition, should the Commission adopt general
criteria to define submarkets? If so, what criteria should the
Commission adopt?
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\60\ Examples of these submarkets include ISO-NE's Southwest
Connecticut, NYISO's East of Central East (Zones F through K), PJM-
East (roughly New Jersey, Southeastern Pennsylvania and the Delmarva
Peninsula), Midwest ISO excluding Wisconsin-Upper Michigan (WUMS),
and CAISO's SP15.
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62. Lastly, if the Commission determines that an RTO/ISO submarket
is the appropriate default geographic region in a particular case and
an applicant is found to have market power within that submarket,
should the Commission consider mitigation in addition to existing RTO
market monitoring and mitigation?
e. Use of Historical Data.
63. We propose to retain the ``snapshot in time'' approach for the
screens, i.e., sellers must use the most recently available unadjusted
12 months' historical data.\61\ Historical
[[Page 33111]]
data are more objective, readily available, and less subject to
manipulation than future projections; therefore, the Commission will
continue to preclude adjustments to historical data with regard to the
indicative screens, with the following exception. We propose to
continue to permit sellers to make adjustments to data that are
necessary to perform the screens provided that the applicant fully
justifies the need for the adjustments, justifies the methodology used,
provides all workpapers in support, and documents the source data. For
example, an adjustment could be allowed where needed data is available
only for a region that is not identical to the seller's control area in
order to put it in a form that can be used in the analysis as
designed.\62\
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\61\ In accordance with the proposed filing schedule discussed
below, data for the indicative screens must track the calendar year
previous to the year designated for filing.
\62\ July 8 Order, 108 FERC ] 61,026 at P 119.
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64. However, we propose in the DPT analysis to allow applicants and
intervenors to account for changes in the market that are known and
measurable at the time of filing.\63\ This proposal mirrors the
Commission's approach in connection with its merger analysis. In Order
No. 642, we stated that we intend to consider current and reasonably
foreseeable regional developments as part of our merger analysis. In
the Merger Policy Statement, we adopted the U.S. Department of Justice/
Federal Trade Commission Horizontal Merger Guidelines \64\ as the
analytical framework for analyzing the effect on competition. Those
guidelines ``address the issue of changing market conditions by stating
that `[t]he Agency will consider reasonably predictable effects of
recent or ongoing changes in market conditions in interpreting market
concentration and market share data.' '' \65\ Examples of known and
measurable changes in the market that would be allowed include new
long-term contracts, expiration of long-term contracts, planned and
imminent plant deactivations/retirements, and planned and imminent
plant additions, regardless of ownership. Sellers who elect to adjust
historical data to reflect known and measurable changes would be
required to perform the analysis using the most recent historical data
and then provide a sensitivity analysis including adjustments for all
known and measurable changes in the market and not just those
advantageous to the seller.\66\ Applicants and intervenors proposing
known and measurable changes to be considered in the DPT analysis will
bear the burden of proof for their adjustments to historical data. We
seek comments on whether the Commission should provide a limitation on
the time period past the historical test period for which sellers can
account for changes, what that time period should be, and how flexible
or inflexible that limitation should be. In addition, we seek comments
on exactly what types of changes should be allowed and under what
circumstances.\67\
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\63\ See 18 CFR 35.13(a) (2005).
\64\ U.S. Department of Justice and Federal Trade Commission,
Horizontal Merger Guidelines (1997) (DOJ/FTC Guidelines).
\65\ Oklahoma Gas and Electric Company and NRG McClain LLC, 105
FERC ] 61,297 (2003) (OG&E), citing the DOJ/FTC Guidelines, Sec.
1.521.
\66\ See Western Resources, Inc., 65 FERC ] 61,106 (1993).
\67\ For example, in OG&E, the Commission accepted one change as
known and measurable and rejected another. Specifically, the
Commission found that the expiration of a long-term power sales
contract within a year was a known and measurable change and should
be part of the base case analysis (105 FERC ] 61,297 at P 33). In
the same order, the Commission found that an upgrade of a
transmission facility that was identified by the Southwest Power
Pool as a persistent limiting facility, but was not under
construction or even in the planning stage, was not ``a foreseeable
and reasonably certain change in the market'' and therefore should
not be part of the base case analysis (id. at P 32).
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f. Reporting Format.
65. As suggested by a commenter, we propose to require all sellers
to submit the results of their indicative screen analysis in a uniform
format to the maximum extent practicable. This format will promote
consistency and will aid the Commission in the decision-making process.
Sellers must cross reference the inputs with the data and workpapers
they otherwise submit including those in accordance with Appendix G of
the April 14 Order. Use of a uniform format for reporting results is
not intended to limit other workpapers the seller may wish to submit.
The format we propose to adopt can be found in Appendix C. We seek
comments on this proposal.
g. Exemption for New Generation (Section 35.27(a) of the
Commission's Regulations).
66. Section 35.27(a) of the Commission's regulations states:
Notwithstanding any other requirements, any public utility
seeking authorization to engage in sales for resale of electric
energy at market-based rates shall not be required to demonstrate
any lack of market power in generation with respect to sales from
capacity for which construction has commenced on or after July 9,
1996.\68\
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\68\ 18 CFR 35.27(a) (2005).
67. The Commission clarified in the April 14 Order that some
sellers with capacity built after July 9, 1996 (section 35.27(a)
exemption) may avoid submitting a horizontal market power analysis if
they meet the requirements of section 35.27(a) of the Commission's
regulations. The Commission stated that, as it indicated in Order No.
888, it will consider whether a seller citing section 35.27(a)
nevertheless possesses horizontal market power if specific evidence is
presented by an intervenor, and a seller still must study whether its
new capacity, when added to existing capacity, raises horizontal market
power concerns.\69\ As the Commission stated in Order No. 888, the
evaluation of market-based rates for existing capacity will include
consideration of new capacity.\70\
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\69\ April 14 Order, 107 FERC ] 61,018 at P 115, 116.
\70\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,657.
---------------------------------------------------------------------------
68. Under current procedures, if all the generation owned or
controlled by an applicant for market-based rate authority and its
affiliates in the relevant control area is new generation, such
applicant is not required to provide a horizontal market power analysis
because of the exemption under section 35.27(a).\71\
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\71\ April 14 Order, 107 FERC ] 61,018 at P 38.
---------------------------------------------------------------------------
69. Although we remain committed to encouraging new entry of
generation, we are concerned that the continued use of the section
35.27(a) exemption may become too broad. Over time, this exemption
would encompass all market participants as all pre-July 9, 1996
generation is retired. For this reason, some commenters suggest that
the Commission should eliminate the exemption altogether.\72\
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\72\ American Public Power Association (APPA) Comments (March
15, 2005) at P 35.
---------------------------------------------------------------------------
70. We agree with these commenters that our current practice will
have unintended adverse consequences over time and therefore should be
reformed. Accordingly, we propose to eliminate the express exemption
provided in section 35.27(a), but to do so in a manner that will not
act as a disincentive for the construction of new generation. As
explained further below, this change will not affect many sellers,
given that they already are required to include all new capacity when
submitting a market analysis for their pre-1996 generation. Further,
our proposal will assure that all generation is treated on an equal
footing, such that market participants with similar market shares in
the same geographic market are not treated differently based solely on
the vintage of their assets.
71. Under this proposal, the Commission would require that all new
applicants seeking market-based rate authority on or after the
effective date of
[[Page 33112]]
the final rule issued in this proceeding, whether or not all of their
and their affiliates' generation was built after July 9, 1996, must
provide a horizontal market power analysis of their generation. Because
the Commission allows an applicant to make simplifying assumptions,
where appropriate, and therefore to submit a streamlined analysis, the
Commission believes that any additional burden imposed by the proposed
elimination of the section 35.27(a) exemption will be minimal.\73\
---------------------------------------------------------------------------
\73\ April 14 Order, 107 FERC ] 61,018 at P 117. In the April 14
Order, the Commission explained that appropriate simplifying
assumptions are those assumptions that do not affect the underlying
methodology utilized by the generation market power screens. For
example, if an applicant passes our generation market power screens
by only considering the control area market's host utility as a
competitor, the Commission foresees no benefit from completing a
study to include other competitors. Similarly, if an applicant would
pass the screens without considering competing supplies from
adjacent control areas, the applicant need not include such imports
in its studies. With regard to a new generator, such an applicant
may base its horizontal market power analysis on the most recently
approved study for the control area in which it is located.
---------------------------------------------------------------------------
72. Further, with regard to triennial reviews, the Commission's
proposal to eliminate the section 35.27(a) exemption would require
that, in its triennial review, a seller must perform a horizontal
market power analysis of all of its generation regardless of when it
was built, thus eliminating any special treatment of generation built
after July 9, 1996. However, as discussed above, because the Commission
allows for a streamlined analysis, including simplifying assumptions,
where appropriate, any additional burden imposed by the proposed
elimination of the section 35.27(a) exemption will be minimal. In
addition, the Commission anticipates that those entities that otherwise
would have relied on the exemption will, in most cases, qualify as
Category 1 sellers and thus no longer be required to file triennial
reviews.
73. By proposing to eliminate the express exemption set forth in
section 35.27(a), we are not proposing to require sellers with market-
based rate authority to submit a new horizontal market power analysis
(i.e., perform the generation market power screens) each time that they
add a new generating unit. Rather, a seller with market-based rate
authority would be required to file a ``change in status'' report under
Order No. 652 notifying the Commission of the acquisition of additional
generation,\74\ the same requirement that exists today. Such sellers
are not required to file a market power analysis of their generation
with their change in status filing, nor do we propose they should.\75\
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\74\ Order No. 652, FERC Stats. & Regs. 31,175 at P
68. The threshold of additional generation that triggers the
reporting requirement is a net increase of 100 MW or more. See Order
No. 652-A, 111 FERC ] 61,413 at P 24-25.
\75\ Further, in the event the seller acquires existing
generation, it may also need to seek approval therefor consistent
with the provisions of section 203 of the FPA as amended. 16 U.S.C.
824b (2000). Energy Policy Act of 2005 Sec. Sec. 261 et seq., Pub.
L. 109-58, 199 Stat. 594 (2005) (EPAct 2005).
---------------------------------------------------------------------------
74. Thus, our proposal to eliminate section 35.27(a) should not
impose significant additional burdens on new generation or otherwise
deter new entry. We seek comments on this proposal.
h. Nameplate Capacity.
75. Based on our experience, we propose to allow sellers the option
of using seasonal capacity instead of nameplate capacity as currently
required. The seller must be consistent in its choice and use one or
the other measure of capacity ratings throughout the analysis. The use
of seasonal capacity ratings we believe more accurately reflects the
seasonal real power capability and is not inconsistent with industry
standards, and therefore it may be more convenient for sellers to
acquire and compile the associated data. In addition, we do not think
the use of such ratings will materially impact results. We seek comment
on this proposal, including comment as to whether this information is
publicly available to all market participants.
i. Transmission Imports.
76. We propose to continue our use of limiting capacity that can be
imported into a relevant market to the results of a simultaneous
transmission import capability study, and to reaffirm several aspects
of the requirements regarding how to properly construct a simultaneous
transmission import capability study for use in the indicative screens
and the DPT.
77. The simultaneous transmission import capability study is
intended to provide a reasonable simulation of historical conditions.
In particular, the simultaneous transmission import capability study is
not the theoretical maximum import capability or a best import case
scenario. It is a benchmark of historical operating conditions and
practices of the applicable transmission provider (e.g., modeling the
system in a reliable and economic fashion as it would have been
operated in real time). The analysis should not deviate from OASIS
practice during each historical seasonal peak. Appendix E of the April
14 Order states that the power flow cases should represent the
transmission provider's tariff provisions and all firm/network
reservations held by seller/affiliate resources during the most recent
seasonal peaks. We propose to reaffirm that ``all'' means both short-
and long-term firm/network reservations.
78. In addition to the power flow cases, as noted in Appendix E of
the April 14 Order, the seller must supply supporting documentation,
and this documentation should include the operational practices
historically used, reliability margins, and all firm/network
reservations held by the seller or its affiliates that are modeled in
the cases. The simultaneous transmission import capability study must
reasonably reflect the transmission provider's OASIS practices and the
techniques used must have been historically available to customers. We
propose to continue to use the instructions set forth in the April 14
Order.
79. Further, the April 14 Order required simultaneous transmission
import capability studies to include firm point-to-point and network
transmission reservations. Firm/network reservations should be
subtracted from the simultaneous transmission import capability if they
are not historically modeled in the power flow case. In all cases,
sellers are required to provide documentation of the firm/network
reservations.
80. We expect control area operators with market-based rate
authority to provide simultaneous transmission import capability
studies in a timely manner, consistent with the methodology described
in the April 14 Order, for their control area and directly
interconnected first-tier control areas in response to requests by
sellers seeking market-based rate authority.\76\ This includes all the
required data, documentation and workpapers to support the study.
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\76\ July 8 Order, 108 FERC ] 61,026 at P 124.
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81. We also propose to reaffirm certain aspects of an approximation
explained in Appendix E of the April 14 Order. The April 14 Order
allows directly interconnected first-tier control areas (to the market
being studied) to be considered when conducting the study. However, it
does not allow control areas that are second tier to the control area
being studied to be considered.
82. We propose to specify how the calculation of a seller's pro
rata share of simultaneous transmission import capability should be
performed. When studying its first-tier control area, the seller should
allocate imports (after taking into account firm reservations by
attributing them to the holders of the reservations including those
applicable to the seller) pro rata between the seller and its
competitors based on
[[Page 33113]]
uncommitted capacity. We seek comments on this proposal.
j. Procedural Issues.
83. The Commission notes that Order No. 662 \77\ issued June 21,
2005, addressed concerns that CEII claims in market-based rate filings
are overbroad. In response to commenters' concerns that intervenors
should have sufficient time to respond to market-based rate filings for
which CEII is claimed, the Commission stated that it is willing to
consider on a case-by-case basis requests for extensions of time to
prepare protests to market-based rate filings where an intervenor
demonstrates that it needs additional time to obtain and analyze CEII.
The Commission encouraged the parties in cases in which CEII is filed
to promptly negotiate a protective order in the proceeding governing
access to the CEII, or privately negotiate for the submitter to provide
the data to interested parties pursuant to an appropriate non-
disclosure agreement. The Commission seeks comments on whether CEII
designations remain a concern since issuance of that rule. The
Commission also seeks comments regarding whether the comment period
(generally 21 days from the date of filing) provided for parties to
file responses to the indicative screens and DPT analyses is
sufficient. If the Commission were to establish a longer period for
submitting comments in these cases, what would be an appropriate
comment period?
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\77\ Critical Energy Infrastructure Information, Order No. 662,
70 FR 37031 (June 28, 2005), FERC Stats. & Regs. ] 31,189 (June 21,
2005).
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B. Vertical Market Power
84. The Commission historically has considered transmission market
power and other barriers to entry as two separate parts of the four-
prong market-based rate analysis. However, as discussed below, the
examination of a seller's ability to engage in transmission market
power and a seller's ability to exclude competitors from the market by
erecting other barriers to entry through the control of inputs to
electric power production both involve the evaluation of potential
vertical market power. On this basis, in this NOPR the Commission
proposes to reformulate its market-based rate analysis to consider
issues relating to transmission market power and other barriers to
entry under the heading ``vertical market power.'' This proposal is
intended primarily to alter the way in which we characterize these
issues, rather than changing the fundamental nature of the analyses
that we perform.
1. Current Policy
Transmission
85. To the extent that a market-based rate seller, or any of its
affiliates, owns, operates, or controls transmission facilities, the
Commission has required the seller to have an OATT on file before
granting market-based rate authorization. The OATT was implemented in
1996 when the Commission issued Order No. 888 to remedy undue
discrimination or preference in access to the monopoly owned
transmission grid. Having a Commission-approved OATT on file satisfies
the Commission's concerns with regard to transmission market power. In
addressing our transmission market power concerns, a seller, including
its affiliates, that does not own, operate or control transmission
facilities should make an affirmative statement that neither it, nor
any of its affiliates, owns, operates or controls any transmission
facilities.\78\
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\78\ See, e.g., Citizens Power, 48 FERC ] 61,210.
---------------------------------------------------------------------------
86. The Commission issued a Notice of Inquiry in Preventing Undue
Discrimination and Preference in Transmission Services,\79\ that seeks
to explore whether, and if so, which, reforms are necessary to the
Order No. 888 pro forma OATT and to the individual public utility
OATTs, given the current state of the electric industry, the complaints
of customers regarding remaining undue discrimination, and the apparent
uncertainties and inconsistent application concerning various tariff
provisions that have arisen since implementation of Order No. 888. The
Commission is issuing a notice of proposed rulemaking in that
proceeding concurrently with this NOPR.
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\79\ See Preventing Undue Discrimination and Preference in
Transmission Service, 70 FR 55796 (Sept. 23, 2005), FERC Stats. &
Regs., Regulations Preambles January 2001-December 2005 ] 35,553
(2005) (OATT Reform Rulemaking).
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Other Barriers to Entry
87. Although the principal barriers to entry can be raised through
the ownership or control of transmission facilities, the Commission
also evaluates barriers to entry other than transmission (other
barriers to entry). In the early 1990s, the Commission considered
whether a seller or its affiliates could erect other barriers to entry
through ownership or control of sites for new capacity development, key
inputs to generation, or the transportation of key inputs to
generation.\80\ The Commission has also considered other barriers to
entry, such as: control of major engineering and consulting firms,\81\
control of fuel supplies, ownership or control of equipment,\82\ and
the control of transportation or distribution of fuel supplies in the
relevant markets.\83\
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\80\ See Doswell Limited Partnership, 50 FERC ] 61,251 at 61,758
(1990) (Doswell); Commonwealth Atlantic Limited Partnership, 51 FERC
] 61,368 at 62,244-45 (1990) (Commonwealth Atlantic), cited in
Entergy Services, Inc., 58 FERC ] 61,234 at n.85 (1992) (Entergy MBR
I).
\81\ See Wallkill Generating Company, L.P. (Wallkill), 56 FERC ]
61,067 (1991).
\82\ See Louisville Gas and Electric Company, 62 FERC ] 61,016
at 61,147 (1993) (LG&E); Entergy MBR I, 58 FERC at 61,759; Pacific
Gas and Electric Company, 53 FERC ] 61,145 at 61,505 (1990).
\83\ In Enron Power Marketing, Inc., 65 FERC ] 61,305 at 62,405
(1993), order on clarification and reh'g, 66 FERC ] 61,244 (1994),
the Commission determined that a power marketer may be affiliated
with an interstate natural gas pipeline because, under the
Commission's requirements, such pipelines must offer open-access
services on a non-discriminatory basis. See also Vantus Energy
Corporation, 73 FERC ] 61,099 at 61,316 (1995). In Idaho Power
Company, 110 FERC ] 61,219 at 61,816 (2005), the Commission
considered a utility's ownership and control of rail cars to
transport coal in its evaluation of the other barriers to entry
prong and held that there are many other companies from which rail
cars may be leased, and that the total number of cars that the
utility could be considered to control (less than 200) was
insignificant relative to the total number of such cars.
---------------------------------------------------------------------------
88. In particular, the Commission considered such things as a power
producer's ownership of building sites and its affiliation with or
ownership of interstate natural gas pipelines, engineering and
construction firms, or local natural gas distribution systems. For
example, in Wallkill, the Commission determined that affiliation with a
major engineering and construction firm could not be used to erect
barriers to entry because there were a large number of such firms
operating on a national basis. Further, in LG&E, the Commission found
that although LG&E did not own facilities used to transport natural
gas, its affiliate owned gas lines and gas storage facilities. In light
of this, the Commission stated that should LG&E or any of its
affiliates deny, delay, or require unreasonable terms, conditions, or
rates for gas services to a potential electric competitor, the electric
competitor could file a complaint with the Commission. The Commission
has made similar findings in subsequent cases where a seller or its
affiliates own or control any natural gas intrastate facilities or
distribution facilities, stating that should such seller or any of its
affiliates deny, delay, or require unreasonable terms, conditions, or
rates for fuel or services to a potential electric competitor in bulk
power markets, then the competitor may file a complaint with the
Commission that could result in the suspension of the seller's
authority to sell power at market-based
[[Page 33114]]
rates. The Commission has stated it will treat such denials, delays, or
requirement of unreasonable terms, conditions or rates for gas service
in the same manner as complaints by an electric competitor that an
entity has refused to transmit electricity.\84\
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\84\ LG&E, 62 FERC ] 61,016 at 61,148.
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2. Proposal
89. As discussed above, the Commission proposes to replace its
existing four-prong analysis (generation market power, transmission
market power, other barriers to entry, affiliate abuse/reciprocal
dealing) with an analysis that focuses on horizontal market power and
vertical market power. Accordingly, we propose that issues relating to
whether the seller and its affiliates lack transmission market power or
whether they can erect other barriers to entry be addressed together as
part of the vertical market power part of the analysis.
90. Regarding transmission issues, the current policy is that
having a Commission-approved OATT on file is sufficient to mitigate
transmission market power. However, the Commission has also recognized
that Order No. 888 did not eliminate all potential to engage in undue
discrimination and preference in the provision of transmission
service.\85\ For this and other reasons, the Commission has initiated a
Notice of Inquiry to address potential reforms to the current OATT.\86\
We believe that any concerns regarding the adequacy of the OATT should
be addressed in that proceeding. We therefore will propose to continue
to find that a Commission-approved OATT, as modified as a result of the
OATT Reform Rulemaking, will adequately mitigate transmission market
power.
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\85\ In Order No. 2000, the Commission found that
``opportunities for undue discrimination continue to exist that may
not be remedied adequately by [the] functional unbundling [remedy of
Order No. 888] * * *'' Regional Transmission Organizations, Order
No. 2000, FERC Stats. & Regs., Regulations Preambles July 1996-
December 2000 ] 31,089 at 31,105 (1999), order on reh'g, Order No.
2000-A, FERC Stats. & Regs., Regulations Preambles July 1996-
December 2000 ] 31,092 (2000), aff'd sub nom. Public Utility
District No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607
(D.C. Cir. 2001).
\86\ See Preventing Undue Discrimination and Preference in
Transmission Service, 70 FR 55796 (Sept. 23, 2005), FERC Stats. &
Regs., Proposed Regulations ] 35,553 (2005) (OATT Reform
Rulemaking). A notice of proposed rulemaking is being issued in that
proceeding concurrently with this NOPR.
---------------------------------------------------------------------------
91. Nevertheless, the finding that an OATT adequately mitigates
transmission market power rests on the assumption that individual
applicants comply with their OATTs. If they do not, violations of the
OATT may be cause to revoke market-based rate authority or to subject
the seller to another remedy the Commission may deem appropriate, such
as disgorgement of profits or civil penalties.\87\ There may be OATT
violations in circumstances that, after applying the factors in the
Enforcement Policy Statement, merit revocation or limitation of market-
based rate authority. However, before the Commission will consider
revoking an entity's market-based rate authority for a violation of the
OATT, there must be a nexus between the specific facts relating to the
OATT violation and the entity's market-based rate authority. The
Commission proposes that, if it determines, as a result of a
significant OATT violation, that the market-based rate authority of a
transmission provider will be revoked within a particular market, each
affiliate of the transmission provider that possesses market-based rate
authority will have it revoked in that market on the effective date of
revocation of the transmission provider's market-based rate authority.
We remind sellers that they must abide by the provisions of the OATT if
they do not want an adverse impact on their ability to charge market-
based rates.
---------------------------------------------------------------------------
\87\ See, e.g., The Washington Water Power Company, 83 FERC ]
61,282 (1998).
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92. The Commission also proposes to continue considering a seller's
ability to erect other barriers to entry, but to do so as part of the
vertical market power analysis. We propose that, in order for a seller
to demonstrate that it satisfies our vertical market power concerns,
with respect to other barriers to entry, it must demonstrate that it
and its affiliates cannot erect other barriers to entry. In this
regard, we propose to continue to require a seller to provide a
description of its affiliation, ownership or control of inputs to
electric power production (e.g., fuel supplies within the relevant
control area); ownership or control of gas storage or intrastate
transportation and distribution of inputs to electric power production;
and control of sites for new capacity development in the relevant
market. We also propose to require sellers to make an affirmative
statement that they have not erected barriers to entry into the
relevant market and that they cannot do so.
93. In addition, the Commission proposes to provide additional
regulatory certainty by clarifying which inputs to electric power
production the Commission will consider as other barriers to entry in
its vertical market power review, and seeks comments on this proposal.
The Commission proposes that the analysis continue to include the
consideration of ownership or control of sites for development of
generation in the relevant market, fuel inputs such as coal facilities
in the relevant market, and the transportation, storage or distribution
of inputs to electric power production such as intrastate gas storage
and distribution systems, and rail cars/barges for the transportation
of coal. The Commission also clarifies that applicants need not address
interstate transportation of natural gas supplies because such
transportation is regulated by this Commission.\88\ Our open access
regulations adequately prevent sellers from withholding interstate
pipeline capacity. Interstate pipelines are required to sell available
capacity at the approved maximum rates. In addition, interstate
pipeline capacity held by firm shippers that is not utilized or
released is available from the pipeline on an interruptible basis. As
to the commodity, Congress has found the natural gas market
competitive.\89\
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\88\ Pipeline Service Obligations and Revisions to Regulations
Governing Self-Implementing Transportation Under Part 284 of the
Commission's Regulations, Order No. 636, 57 FR 13267 (Apr. 16,
1992), FERC Stats. & Regs. Regulations Preambles January 1991-June
1996 ] 30,939 (Apr. 8, 1992).
\89\ Natural Gas Wellhead Decontrol Act of 1989, Pub. L. 101-60,
103 Stat. 157 (1989); Natural Gas Policy Act of 1978, section
601(a)(1), 15 U.S.C. 3431 (deregulating the wellhead price of
natural gas).
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94. Several commenters have suggested that a transmission planning
and expansion process can ameliorate vertical market power. The
Commission is seeking comments on the issues of transmission planning
and expansion in the notice of proposed rulemaking in the OATT Reform
Rulemaking that is being issued concurrently with this NOPR. We seek
comment on whether these planning and expansion efforts under the OATT
Reform Rulemaking will address commenters' concerns here.
95. The Commission seeks comment on whether other inputs to
electric power production should be considered as potential barriers to
entry and, if so, what criteria the Commission should use to evaluate
evidence that is presented. We also seek comment on whether the
exercise of buyer's market power by the transmission provider should be
considered a potential barrier to entry and, if so, what criteria the
Commission should use to evaluate evidence that is presented.
C. Affiliate Abuse
96. The fourth prong of the Commission's current market-based rate
analysis examines whether there is evidence involving the seller or its
[[Page 33115]]
affiliates that relates to affiliate abuse or reciprocal dealing.\90\
As the Commission has explained, ``[t]he Commission's concern with the
potential for affiliate abuse is that a utility with a monopoly
franchise may have an economic incentive to exercise market power
through its affiliate dealings.'' \91\ The Commission stated that
potential abuses include such practices as affiliates selling products
to a utility with a franchised service territory (franchised public
utility) at excessive prices, or a franchised public utility providing
inputs to an affiliate at preferentially low prices. Both of these
practices are examples of market power that is exercised to the
disadvantage of captive customers. The Commission also has explained
that there may be a potential for affiliate abuse through means such as
the pricing of non-power goods and services or the sharing of market
information.
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\90\ See Commonwealth Atlantic Limited Partnership, 51 FERC ]
61,368 at 62,245 (1990) (discussing potential for reciprocal dealing
if a buyer agrees to pay more for power from a seller in return for
that seller (or its affiliates) paying more for power from the buyer
(or its affiliates)).
\91\ Edgar, 55 FERC ] 61,382 at 62,167 n.56. See also TECO Power
Services Corp. and Tampa Electric Co., 52 FERC ] 61,191 at 61,697 n.
41 (1990) (``The Commission has determined that self-dealing may
arise in transactions between affiliates because affiliates have
incentives to offer terms to one another which are more favorable
than those available to other market participants.'').
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97. The Commission in the past has used two means to ensure that
affiliate abuse does not occur: restrictions on sales between a
franchised public utility and its affiliates, and requiring a code of
conduct that governs the relationship between franchised public
utilities and their affiliates.
1. Power Sales Restrictions
a. Current Policy.
98. The Commission currently prohibits power sales at market-based
rates between a franchised public utility and its affiliates without
first receiving authorization of the transaction under section 205 of
the FPA.\92\ In order to be granted market-based rate authorization, a
franchised public utility and all of its affiliates must include such a
prohibition in their market-based rate tariffs unless the Commission
has otherwise authorized the seller to transact with its affiliates.
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\92\ Aquila, Inc., 101 FERC ] 61,331 (2002).
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99. The Commission has stated its concern that a franchised public
utility and an affiliate may be able to transact in ways that transfer
benefits from the captive customers of the franchised public utility to
the affiliate and its shareholders.\93\ Where a franchised public
utility makes a power sale to an affiliate, the Commission is concerned
that such a sale could be made at a rate that is too low, in effect,
transferring the difference between the market price and the lower rate
from captive customers to the ``non-regulated'' affiliated entity.
Where an entity makes power sales to an affiliated franchised public
utility, the concern is that such sales not be made at a rate that is
too high, which would give an undue profit to the affiliated entity at
the expense of the franchised public utility's captive customers. The
Commission has found that a transaction between two non-traditional
utility affiliates (such as power marketers, EWGs, or QFs) does not
raise the same concern about cross subsidization because neither has a
franchised service territory and therefore has no captive customers. As
the Commission has explained, no matter how sales are conducted between
non-traditional affiliates, profits or losses ultimately affect only
the shareholders.\94\
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\93\ See, e.g., Heartland Energy Services Inc., 68 FERC ] 61,223
at 62,062 (1994) (Heartland).
\94\ FirstEnergy Generation Corporation, 94 FERC ] 61,177
(2001); USGen Power Services, L.P., 73 FERC ] 61,302 at 61,846
(1995).
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100. In determining whether to allow power sales affiliate
transactions, the Commission, over time, has adopted several methods,
all of which have focused on ensuring that captive customers are
adequately protected against affiliate abuse. We discuss these below.
101. In Edgar, the Commission described three types of evidence
that can be used to show that an affiliate power sales transaction is
above suspicion ensuring that the market is not distorted and captive
ratepayers are protected: (1) Evidence of direct head-to-head
competition between the affiliate and competing unaffiliated suppliers
in a formal solicitation or informal negotiation process; (2) evidence
of the prices non-affiliated buyers were willing to pay for similar
services from the affiliate; or (3) benchmark evidence that shows the
prices, terms, and conditions of sales made by non-affiliated
sellers.\95\ The Commission stated that when an entity presents
evidence regarding a competitive solicitation, the Commission requires
assurance that: (1) A competitive solicitation process was designed and
implemented without undue preference for an affiliate; (2) the analysis
of bids did not favor affiliates, particularly with respect to non-
price factors; and (3) the affiliate was selected based on some
reasonable combination of price and non-price factors.\96\
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\95\ Edgar, 55 FERC ] 61,382 at 62,168-69.
\96\ Id. at 62,168. A seller with market-based rate authority
would not necessarily be required to make a separate affirmative
showing of no market power in order to fulfill the Edgar standards
and receive authority to engage in an affiliate transaction.
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102. In subsequent cases, the Commission expanded on the
competitive solicitation prong of Edgar and has stated that it must
evaluate the bidding process and determine that, based on the evidence,
a proposed power sale between affiliates is the result of direct head-
to-head competition.\97\
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\97\ See, e.g., Rockland Electric Company, 102 FERC ] 61,097
(2003); Connecticut Light & Power Company and Western Massachusetts
Electric Company, 90 FERC ] 61,195 at 61,633-34 (2000); Aquila
Energy Marketing Corp., 87 FERC ] 61,217 at 61,857-58 (1999); MEP
Pleasant Hill, LLC, 88 FERC ] 61,027 at 61,059-60 (1999); Edgar, 55
FERC ] 61,382 at 62,167-69.
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103. The Commission has provided guidelines as to how the
Commission will evaluate whether a competitive solicitation process
satisfies the Edgar criteria. The underlying principle when evaluating
a competitive solicitation process under the Edgar criteria is that no
affiliate should receive undue preference during any stage of the
process.
104. In Allegheny, the Commission stated that the following four
guidelines will help the Commission determine if a competitive
solicitation process satisfies that underlying principle: It is
transparent; products are well defined; bids are evaluated comparably
with no advantage to affiliates; and it is designed and evaluated by an
independent entity.\98\ The Allegheny guidelines serve as one example
of evidence that a competitive solicitation has resulted in just and
reasonable rates; they do not constitute the only way in which an
applicant could demonstrate that a competitive solicitation was not
unduly discriminatory.
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\98\ See, e.g., Allegheny Energy Supply Company, LLC, 108 FERC ]
61,082 (2004) (Allegheny); Rockland Electric Company, 102 FERC ]
61,097 (2003); Conectiv Energy Supply, Inc., 91 FERC ] 61,076
(2000).
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105. The Commission has granted blanket authorization to make power
sales to affiliates pursuant to a market-based rate tariff subject to
certain conditions. For this blanket authorization, the Commission has
required that sales of power by a franchised public utility to an
affiliate be made at a rate no lower than the rate charged to non-
affiliates; the utility offering to sell power to an affiliate must
make the same offer, at the same time, to non-affiliated entities; and
the utility must post simultaneously the actual price charged to its
affiliate for all
[[Page 33116]]
transactions.\99\ These provisions were originally included as part of
Detroit Edison's cost-based rate tariff in response to a request by
Detroit Edison to sell power to its affiliated power marketer at
negotiated rates subject to a cost-based price cap. However, the
Commission's practice has been to allow such a provision in other
sellers' market-based rate tariffs. Utilities that request this blanket
authorization have been required to include those conditions in their
market-based rate tariffs.\100\
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\99\ Detroit Edison Co., 80 FERC ] 61,348 at 62,198 (1997).
\100\ See, e.g., Alliant Services Company, 85 FERC ] 61,344 at
62,335 (1998); Tucson Electric Power Company, 82 FERC ] 61,141 at
61,525 (1998).
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106. The Commission also has authorized sales when a ``non-
regulated'' affiliate seeks to sell power to an affiliated franchised
public utility where sufficient pricing safeguards were in place to
ensure that there was no room for manipulation.\101\ In Advanced
Resources, the Commission found adequate a plan where the power
marketer sold energy to its affiliated franchised public utility at the
lowest price paid by the franchised public utility to a non-affiliate
under certain standard supplier agreements. Specifically, the
Commission granted authorization because the price in these standard
supplier agreements was equal to the average price of power sold to the
franchised public utility through the PJM power exchange. Because the
price of the franchised public utility's purchases from the power
marketer was set equal to the price of the franchised public utility's
purchases from PJM, the Commission concluded there was no room for
manipulation.
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\101\ See, e.g., GPU Advanced Resources, Inc., 81 FERC ] 61,335
(1997) (Advanced Resources); FirstEnergy Trading & Power Marketing,
Inc., 84 FERC ] 61,214 at 62,037-38, reh'g denied, 85 FERC ] 61,311
(1998) (rejecting tariffs without prejudice to the applicants
submitting alternative proposals that delineate the nature of the
transactions to be undertaken and demonstrate that any proposed
safeguards mitigate the potential for affiliate abuse).
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107. The Commission also has allowed sales between affiliates
pursuant to a market-based rate tariff without imposing any price or
transaction conditions where there were no captive wholesale or retail
customers or where captive customers were adequately protected from
affiliate abuse.\102\ In these cases, the Commission found that captive
customers were protected through fixed rate contracts, retail rate
freezes, retail access, and an inability for the captive ratepayer to
be harmed through fuel adjustment clauses. The Commission also has
found that tying the price of an affiliate transaction to an
established, relevant market price or index mitigates affiliate abuse
concerns.\103\
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\102\ See, e.g., Consumers Energy Company, 94 FERC ] 61,180
(2001) (finding there are adequate safeguards including Consumer
Energy disallowing revenues for sales to CMS Marketing to be
factored into any rate calculations for wholesale customers,
existence of retail rate freeze, and phase in of retail choice);
FirstEnergy Corp., 94 FERC ] 61,182 at 61,630 (2001) (finding of
adequate safeguards based on FirstEnergy's commitment to hold
wholesale customers harmless from changes in cost, a retail rate
freeze in Ohio, and caps on retail rates in Pennsylvania); Exelon
Generation Company, L.L.C., 93 FERC ] 61,140 at 61,425 (2000), reh'g
denied, 95 FERC ] 61,309 (2001) (finding there are adequate
safeguards including retail access, rate freezes, rate caps, and
other mechanisms).
\103\ Brownsville Power I, L.L.C., 111 FERC ] 61,398 at P 10
(2005) (Brownsville); See also FirstEnergy Trading Servs., Inc., 88
FERC ] 61,067 at 61,156 (1999) (FirstEnergy Trading); Union Light,
Heat, and Power Co., 110 FERC ] 61,212 at P16 (2005) (affirming that
use of Midwest ISO Day 2 market prices meets the Edgar test and
mitigates concerns regarding transactions between affiliates); Idaho
Power Company, 95 FERC ] 61,147 (2001) (accepting use of the Dow
Jones Mid-Columbia Index and the Dow Jones Palo Verde Index for
affiliate sales); Pinnacle West Capital Corporation, 91 FERC ]
61,290 (2000) (allowing use of the lesser of the Palo Verde Index
and system incremental cost as a cap on the price for sales between
affiliates); DPL Energy, Inc., 90 FERC ] 61,200 (2000) (affirming
that use of the ``into Cinergy'' index price as a price cap for its
power sales to Dayton P&L mitigates affiliate abuse concerns);
Ameren Services Company, 86 FERC 61,212 (1999) (accepting use of
``into Cinergy'' for sales between affiliates).
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b. Proposal.
108. We remain concerned about the potential adverse impact that
affiliate power sales transactions may have on captive customers \104\
and propose to continue our policy of reviewing affiliate transactions
under section 205 of the FPA. Although we have traditionally identified
affiliate abuse as the fourth prong of our test for market-based rate
authority, in practice this prong is not only evaluated at the time an
application is filed, but rather is satisified on an ongoing basis
through the requirement that sellers obtain prior approval, under the
foregoing standards, for affiliate power sales. To reflect and codify
this practice, we propose to discontinue referring to affiliate abuse
as a separate ``prong'' of our analysis and instead we propose to
codify in our regulations at 18 CFR part 35, subpart H, an explicit
requirement that any seller with market-based rate authority must
comply with the affiliate power sales restrictions and other affiliate
provisions.\105\ Thus, we will address affiliate abuse by requiring
that the conditions set forth in the proposed regulations be satisfied
on an ongoing basis as a condition of obtaining and retaining market-
based rate authority. However, we note that a seller seeking to obtain
or retain market-based rate authority will continue to be obligated to
provide a detailed description of its corporate structure so that we
can be assured that our standards are being applied correctly. In
particular, applicants with franchised service territories will be
required to make a showing regarding whether they serve customers and
to identify all non-regulated power sales affiliates, such as
affiliated marketers and generators.\106\
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\104\ See Edgar, 55 FERC ] 61,382 at 62,167.
\105\ With regard to reciprocal dealing, we believe that any
concerns as to a seller's ability to engage in reciprocal dealing
are addressed by the affiliate abuse provisions we propose to
include in the Commission's regulations as well as the Commission's
final rule prohibiting energy market manipulation. See Prohibition
of Energy Market Manipulation, Order No. 670, 71 FR 4244 (January
26, 2006), FERC Stats. & Regs. ] 31,202 (2006), order on reh'g,
Order No. 670-A, 114 FERC ] 61,300 (2006).
\106\ In this regard, the Commission protects captive customers
by ensuring that wholesale rates are just and reasonable.
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109. Consistent with the foregoing, we propose to amend the
Commission's regulations to include a provision expressly prohibiting
power sales between a franchised public utility and any of its non-
regulated affiliates without first receiving authorization of the
transaction under section 205 of the FPA. Further, we propose that, as
a condition of receiving market-based rate authority, sellers must
adopt the MBR tariff (included as Appendix A to this NOPR) which
includes a provision requiring the seller to comply with, among other
things, the affiliate provisions in the regulations. We note that
failure to satisfy the conditions set forth in the affiliate provisions
will constitute a tariff violation. We seek comments on this proposal.
110. Sellers seeking authorization to engage in affiliate
transactions will continue to be obligated to provide evidence to
support a determination as to whether there are captive customers that
would trigger the application of our standards for affiliate power
sales.\107\ If the Commission finds, based on the evidence provided by
the seller, that the seller has no captive customers, the affiliate
provisions in the regulations would not apply. However, if the record
does not support a finding of no captive customers, the seller must
abide by all affiliate restrictions contained in the regulations in
order to obtain and retain market-based rate authority. In the
Commission's Final Rule on transactions subject to section 203, the
[[Page 33117]]
Commission defined the term ``captive customers'' to mean ``any
wholesale or retail electric energy customers served under cost-based
regulation.'' \108\ We seek comment on whether the same definition
should be used for purposes of this rule.
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\107\ Sellers that have already received authorization to make
sales to affiliates would retain that authorization unless the
Commission institutes a section 206 investigation to examine whether
the seller's current circumstances continue to satisfy our affiliate
abuse concerns and subsequently revokes such authorization.
\108\ Transactions Subject to FPA section 203, Order No. 669-A,
71 FR 28422 (May 16, 2006), FERC Stats. & Regs. ] 31,097 (2006). See
also Repeal of the Public Utility Holding Company Act of 1935 and
Enactment of the Public Utility Holding Company Act of 2005, Order
No. 667-A, 71 FR 28446 (May 16, 2006), FERC Stats. & Regs. ] 31,096
(2006).
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111. We propose to continue our past approach for determining what
types of affiliate transactions are permissible and the criteria that
should be used to make those decisions. When affiliates participate in
a competitive solicitation process, application of the Allegheny
criteria would constitute safe harbor criteria that the affiliate abuse
condition is satisfied in a transaction between a franchised public
utility and its affiliate. The Commission will consider competitive
solicitations, on a case-by-case basis. However, we emphasize that
using a competitive solicitation is not the only way an affiliate
transaction can address our concerns that the transaction does not pose
affiliate abuse concerns.
112. In Edgar, two alternatives to competitive solicitation
evidence were found to be acceptable evidence of a market price. These
alternatives included prices non-affiliates are willing to pay for
similar service and benchmark evidence. However, Edgar also noted the
difficulty of finding such truly comparable alternative evidence.\109\
This difficulty in finding adequate comparable evidence increases the
likelihood that applications submitted with such evidence could raise
issues of material fact and thus could be set for hearing.
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\109\ See Edgar, 55 FERC ] 61,382 at 62,169.
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113. We continue to believe that tying the price of an affiliate
transaction to an established, relevant market price or index such as
in an RTO or ISO is acceptable benchmark evidence and mitigates
affiliate abuse concerns so long as that benchmark price or index
reflects the market price where the affiliate transaction occurs (i.e.,
is a relevant index).\110\ The Commission has stated its belief that
the added protections in structured markets with central commitment and
dispatch and market monitoring and mitigation (such as RTOs/ISOs)
generally result in a market where prices are transparent.\111\
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\110\ Brownsville, 111 FERC ] 61,398 at P10. See also Portland
General Elec. Co., 96 FERC ] 61,093 at 61,378 (2001); FirstEnergy
Trading, 88 FERC ] 61,067 at 61,156 (1999).
\111\ April 14 Order, 107 FERC ] 61,018 at P 189.
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114. Although the Commission has found in the past that certain
non-RTO price indices are acceptable indicators of market prices, we
recognize that price indices at thinly traded points can be subject to
manipulation and are otherwise not good measures of market prices, as
discussed in the Price Index Policy Statement \112\ and November 19
Price Index Order.\113\ Accordingly, we propose to allow affiliate
transactions based on a non-RTO price index only if the index fulfills
the requirements of the November 19 Price Index Order for eligibility
for use in jurisdictional tariffs.\114\ The requirements include the
criteria found in the Price Index Policy Statement, including but not
limited to \115\ reporting of prices by those not involved in trading,
and a process for resolving reporting errors, as well as those specific
to jurisdictional tariffs: (1) Providing the volume and number of
transaction data on which the index value is based (or clearly
indicating when no such data is available); (2) confirming that the
Commission can have access to relevant data in the event of an
investigation of possible false price reporting or manipulation; and
(3) establishing minimum criteria to determine whether there is
adequate liquidity for daily, weekly, and monthly electricity indices.
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\112\ Policy Statement On Natural Gas And Electric Price Indices
104 FERC ] 61,121 (2003) (Price Index Policy Statement).
\113\ Order Regarding Future Monitoring Of Voluntary Price
Formation, Use Of Price Indices In Jurisdictional Tariffs, And
Closing Certain Tariff Docket 109 FERC ] 61, 184 (2004) (November 19
Price Index Order).
\114\ November 19 Price Index Order, 109 FERC ] 61,184 at P 40-
69.
\115\ Price Index Policy Statement, 104 FERC ] 61,121 at P 34.
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115. The Commission seeks comment on whether evidence other than
competitive solicitations, RTO price or non-RTO price indices, or
benchmarks described above, should be accepted in an application for
authority to engage in affiliate power sales.
116. With regard to merging companies the Commission has stated
that for the purposes of affiliate abuse, merging companies will be
considered affiliates under the market-based rate tariff while their
merger is pending.\116\ We seek comments regarding at what point the
Commission should consider two non-affiliates as merging partners: the
date the merger is announced, the date the section 203 application is
filed with the Commission, or another time? The Commission proposes to
use the date a merger is announced as the triggering event, but we seek
comment on this issue.
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\116\ Cinergy, Inc., 74 FERC ] 61,281 (1996); Consolidated
Edison Energy, Inc., 83 FERC ] 61,236 at 62,034 (1998); Central and
South West Services, Inc., 82 FERC ] 61,101 at 61,103 (1998);
Delmarva Power & Light Company, 76 FERC ] 61,331 at 62,582 (1996)
(``[T]he self-interest of two merger partners converge sufficiently,
even before they complete the merger, to compromise the market
discipline inherent in arm's-length bargaining that serves as the
primary protection against reciprocal dealing.'').
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117. The Commission also proposes that entities that engage in
energy/asset management of generation on behalf of a franchised public
utility be treated as affiliates of that franchised public utility in a
manner similar to that of non-regulated affiliates and be subject to
the affiliate provisions we propose herein. The Commission also
proposes that entities that engage in energy/asset management of
generation on behalf of non-regulated affiliates of a franchised public
utility be treated in a similar manner as the non-regulated affiliates.
We seek comment on this proposal.
118. The Commission currently requires that sales made under
market-based rate tariffs, including those made to affiliates, be
reported in an EQR.\117\ The Commission affirms that its role with
regard to market-based rates, and specifically affiliate transactions,
will be to either grant or deny authorization to make affiliate sales.
Additionally, the Commission reiterates that, once authorized, all such
sales should be reported in an EQR.
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\117\ Revised Public Utility Filing Requirements, Order No.
2001, 67 FR 31043 (May 8, 2002), FERC Stats. & Regs., Regulations
Preambles January 2001-December 2005 ] 31,127 (2002).
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119. Although, at one time, the Commission's policy was to require
certain market-based rate sellers to file their long-term market-based
rate power sales service agreements with the Commission,\118\ since the
issuance of Order No. 2001, the Commission's policy has been to require
that such agreements not be filed with the Commission. Notwithstanding
this policy, the Commission on occasion may have accepted long-term
service agreements for filing. At this time, the Commission reaffirms
that long-term affiliate sales contracts under the seller's market-
based rate tariff that are authorized by the Commission shall not be
filed with the Commission.\119\ However, the seller must make a section
205 filing with the Commission to obtain authorization to engage in an
[[Page 33118]]
affiliate transaction, and may not engage in such transaction without
first receiving such authorization.
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\118\ See Southern Company Services, Inc., 99 FERC ] 61,103
(2002).
\119\ 18 CFR 35.1(g) (2005) (``[A]ny market-based rate agreement
pursuant to a tariff shall not be filed with the Commission'').
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2. Market-Based Rate Code of Conduct for Affiliate Transactions
Involving Power Sales and Brokering, Non-Power Goods and Services and
Information Sharing
a. Current Policy.
120. The Commission requires affiliates of franchised public
utilities that request market-based rate authority to submit a market-
based rate code of conduct to govern the relationship between the
franchised public utility and its affiliates. Historically, the purpose
of the market-based rate code of conduct \120\ has been to safeguard
against affiliate abuse by protecting against the possible diversion of
benefits or profits from franchised public utilities (i.e., traditional
public utilities with captive ratepayers) to an affiliated entity for
the benefit of shareholders. Just as the Commission has expressed
concern about the potential for affiliate abuse in connection with
power sales between affiliates, it also has recognized that there may
be a potential for affiliate abuse through other means, such as the
pricing of non-power goods and services or the sharing of market
information between affiliates.\121\ The market-based rate code of
conduct was designed to address these concerns. The Commission has
waived the market-based rate code of conduct requirement in cases where
there are no captive customers, and thus no potential for affiliate
abuse, or where the Commission finds that such customers are adequately
protected against affiliate abuse.\122\ In such cases, however, the
Commission directed the utilities to notify the Commission should they
obtain captive customers in the future and expressly reserved the right
to reimpose the market-based rate code of conduct requirement. In the
Order No. 2004 Standards of Conduct rulemaking proceeding, the
Commission solicited comment on whether to reform the market-based rate
code of conduct but determined that such reform should take place in a
separate proceeding.\123\
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\120\ The market-based rate code of conduct has at times been
confused with the Commission's Standards of Conduct. The electric
Standards of Conduct, originally issued in Order No. 889 et seq.,
were established to govern the relationship between a public
utility's transmission function and its wholesale merchant function
(including affiliated power marketers) to ensure that all
transmission customers have equal access to transmission
information. See Open Access Same-Time Information System and
Standards of Conduct, Order No. 889, 61 FR 21737 (1996), FERC Stats.
& Regs., Regulations Preambles July 1996-December 2000 ] 31,035
(1996), order on reh'g, Order No. 889-A, 62 FR 12484 (1997), FERC
Stats. & Regs., Regulations Preambles July 1996-December 2000 ]
31,049 (1997), reh'g denied, Order No. 889-B, 81 FERC ] 61,253
(1997), order on reh'g, Order No. 889-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). The Standards of
Conduct were recently updated by the Commission. See Standards of
Conduct for Transmission Providers, Order No. 2004, 68 FR 69134
(Dec. 11, 2003), III FERC Stats. & Regs., Regulations Preambles
January 2001-December 2005 ] 31,155 (Nov. 25, 2003), order on reh'g,
Order No. 2004-A, 69 FR 23562, (Apr. 29, 2004), III FERC Stats. &
Regs., Regulations Preambles January 2001-December 2005 ] 31,161
(April 16, 2004), order on reh'g, Order No. 2004-B, 69 FR 48371
(Aug. 10, 2004), III FERC Stats. & Regs., Regulations Preambles
January 2001-December 2005 ] 31,166 (Aug. 2, 2004), order on reh'g,
Order No. 2004-C, 70 FR 284 (Jan 4., 2005), III FERC Stats. & Regs.,
Regulations Preambles January 2001-December 2005 ] 31,172 (Dec. 21,
2004), order on reh'g, Order No. 2004-D, 110 FERC ] 61,320 (March
23, 2005), appeal docketed sub nom., Natural Gas Fuel Supply Corp.
v. FERC, No. 04-1183 (D.C. Circuit).
\121\ See, e.g., Potomac Electric Power Company, 93 FERC ]
61,240 at 61,782 (2000); Heartland, 68 FERC ] 61,223 at 62,062-63.
\122\ See, e.g., CMS Marketing, Services and Trading Co., 95
FERC ] 61,308 at 62,051 (2001) (granting request for cancellation of
code of conduct where wholesale contracts, as amended, ``cannot be
used as a vehicle for cross-subsidization of affiliate power sales
or sales of non-power goods and services''); Alcoa, Inc., 88 FERC
]61,045 at 61,119 (1999) (waiving code of conduct requirement where
there were no captive customers); Green Power Partners 1 LLC, 88
FERC ] 61,005 at 61,010-11 (1999) (waiving code of conduct
requirement where there are no captive wholesale customers and
retail customers may choose alternative power suppliers under retail
access program).
\123\ Order No. 2004, at 30,853. The following entities
submitted comments in the Standards of Conduct rulemaking proceeding
in Docket No. RM01-10-000 relating to the concept of codifying the
code of conduct: Cinergy (codification not needed); Entergy (if
codified, the code of conduct should reflect established codes);
NEPOOL Industrial Customer Coalition (codification needed); LG&E
Energy Corporation (separate code of conduct policy issues should be
treated in a separate rulemaking); PanCanadian Energy Services, Inc.
(codification unnecessary).
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121. The market-based rate code of conduct requirements have
evolved through market-based rate orders.\124\ Beginning with orders
issued in 1999, the Commission informed sellers that if an applicant
submitted a market-based rate code of conduct that was inconsistent
with the market-based rate code of conduct attached to those orders,
the Commission would reject it and designate the attachment as the
applicable code.\125\ The Commission's market-based rate code of
conduct provisions state:
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\124\ Seminal early Commission decisions discussing the purposes
of the code of conduct requirements include Heartland and LG&E Power
Marketing, Inc., 68 FERC ] 61,247 at 62,121-24 (1994).
\125\ See, e.g., Northeast Utilities Service Company, 87 FERC ]
61,063 (1999) (requiring market-based rate applicants to submit
codes of conduct consistent with an attached code of conduct and
imposing the attached code in the event of inconsistency).
Statement of Policy and Code of Conduct With Respect to the
Relationship Between (Power Marketer/Power Producer) and [Public
Utility]
Marketing of Power
1. To the maximum extent practical, the employees of [Power
Marketer/Power Producer] will operate separately from the employees
of [Public Utility].
2. All market information shared between [Public Utility] and
[Power Marketer/Power Producer] will be disclosed simultaneously to
the public. This includes all market information, including but not
limited to, any communication concerning power or transmission
business, present or future, positive or negative, concrete or
potential. Shared employees in a support role are not bound by this
provision, but they may not serve as an improper conduit of
information to non-support personnel.
3. Sales of any non-power goods or services by [Public Utility],
including sales made through its affiliated EWGs or QFs, to [Power
Marketer/Power Producer] will be at the higher of cost or market
price.
4. Sales of any non-power goods or services by the [Power
Marketer/Power Producer] to [Public Utility] will not be at a price
above market.
Brokering of Power
To the extent [Power Marketer/Power Producer] seeks to broker
power for [Public Utility]:
5. [Power Marketer/Power Producer] will offer [Public Utility's]
power first.
6. The arrangement between [Power Marketer/Power Producer] and
[Public Utility] is non-exclusive.
7. [Power Marketer/Power Producer] will not accept any fees in
conjunction with any Brokering services it performs for [Public
Utility].
122. The Commission has also accepted the inclusion of an
additional provision to govern brokering activities where a franchised
public utility brokers for one of its affiliates.\126\
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\126\ See MEP Investments, LLC, 87 FERC ] 61,209 at 61,828
(1999) (``CP&L has taken the brokering rules established by the
Commission for the opposite situation (when the marketer is
brokering for the utility), and modified them to apply to its
situation. Specifically, instead of the no-fee rule when a marketer
brokers for its affiliate, for brokering service CP&L provides to
Monroe, CP&L will charge Monroe the higher of CP&L's costs for that
service or the market rate for such services. CP&L will also market
its own power first, simultaneously make public any information
shared with Monroe during brokering, and post on its Internet site
the actual brokering changes imposed. This addition to CP&L's code
of conduct is accepted.'').
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123. Numerous significant changes have taken place in the electric
industry relevant to the market-based rate code of conduct requirement
since the Commission approved the first market-based rate codes of
conduct in the mid-1990s. The Commission has required open access
transmission service in Order No. 888; there has been an increase in
the number of power marketers and power producers
[[Page 33119]]
authorized to transact under market-based rates, as well as an
increased market for available transmission capacity, an increased
number of power transactions, and new and different uses for the
transmission grid.\127\ The Commission has found that the nature of
electric market participants is also changing, with the rise of power
marketers and generation facilities that are affiliated with
traditional regulated entities, as well as unaffiliated entities.\128\
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\127\ Standards of Conduct for Transmission Providers, Order No.
2004, 68 FR 69134, FERC Stats. & Regs., ] 31,155, Regulations
Preambles January 2001-December 2005.
\128\ Id. As of April 1, 2006, approximately 1170 entities have
market-based rate authority granted by the Commission. They include
approximately 390 independent power marketers, 70 traditional
utilities with market-based rate authority, 100 affiliated power
marketers, 400 affiliated power producers, 180 independent power
producers and 30 financial institutions.
---------------------------------------------------------------------------
124. There also has been an increased range of activities engaged
in by asset or energy managers.\129\ Although asset managers can
provide valuable services and thereby benefit consumers and the
marketplace, such relationships also could result in transactions
harmful to captive customers. We note that, as the consequence of one
Commission investigation, there was a settlement agreement pursuant to
which a company's market-based rate codes of conduct were revised to
expand (a) the range of affiliates to which they applied and (b) the
regulation of conduct between affiliates, including the asset
manager.\130\
---------------------------------------------------------------------------
\129\ Kevin Heslin, A few thoughts on the industry: Ideas from
session at Globalcon, Energy User News, July 1, 2002, at 12 (Noting
that prior to deregulation, ``an energy manager had relatively
straightforward tasks: understanding applicable tariffs, evaluating
the possible installation of energy conservation measures (ECMs),
and considering whether to install on-site generation'' but that
``now, an energy manager has to be conversant with a far greater
number of issues'' such as complex legal issues and financial
instruments like derivatives.)
\130\ In 2003, as part of a Settlement Agreement with the
Commission, Cleco Corp. agreed to an expansion of its codes of
conduct governing relations between its various affiliates that
Enforcement staff alleged had participated in power sales and
related conduct in violation of the Standards of Conduct and Cleco's
previous codes of conduct. Cleco Corp., 104 FERC ] 61,125 (2003).
Pursuant to the terms of the resulting settlement agreement, Cleco
submitted revised codes that governed information sharing and
independent functioning between Cleco's three exempt wholesale
generators (with market-based rate authority), its power marketer
that in essence acted as an asset manager for the three, and its
captive ratepayer utility, rather than merely code provisions
governing relations between, on the one hand, the captive ratepayer
utility, and, on the other, the marketing and generation affiliates.
---------------------------------------------------------------------------
125. While the Commission has required that entities comply with
the provisions of the market-based rate code of conduct, the market-
based rate code of conduct has not been codified in the Commission's
regulations. Further, some applicants for market-based rate authority
have requested and received variations from the market-based rate code
of conduct. Such variations, while reasonable in individual
circumstances, may over time become inconsistent with the Commission's
goals of protecting captive customers and fostering transparent and
consistent regulation of the market. Likewise, some corporate families
have filed several different market-based rate codes of conduct for
their affiliates while others have filed only one or have received a
waiver of the market-based rate code of conduct requirement.
126. An example of inconsistent market-based rate codes of conduct
was revealed in Commission staff's audit of Progress Energy, Inc. In
that proceeding, there were eight different codes with differing
provisions for different Progress affiliates.\131\
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\131\ See Florida Power Corp., 111 FERC ] 61,243 (2005),
attached staff Audit Report at 6.
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b. Proposal.
127. The Commission continues to believe that a code of conduct is
necessary to protect captive customers from the potential for affiliate
abuse. Further, in light of the repeal of the Public Utility Holding
Company Act of 1935 and the fact that holding company systems may have
franchised public utility members with captive customers as well as
numerous ``non-regulated'' power sales affiliates that engage in non-
power goods and services transactions with each other, it is important
that the Commission have in place restrictions to preclude transferring
captive customer benefits to stockholders through a company's ``non-
regulated'' power sales business. We therefore believe it is
appropriate to condition all market-based rate authorizations,
including authorizations for sellers within holding companies, on the
seller abiding by a code of conduct for sales of non-power goods and
services between power sales affiliates.
128. We also believe that greater uniformity and consistency in the
codes of conduct is appropriate. With the experience gained over the
years in approving various codes of conduct, including our standard
code of conduct, we are proposing to adopt a uniform code of conduct to
govern the relationship between franchised public utilities with
captive customers and their ``non-regulated'' affiliates, i.e.,
affiliates whose power sales are not regulated on a cost basis under
the FPA. We therefore propose to codify such affiliate provisions in
section 35.39(b)-(e) of our regulations and to require that, as a
condition of receiving market-based rate authority, sellers comply with
these provisions. Failure to satisfy the conditions set forth in the
affiliate provisions will constitute a tariff violation. This
uniformity will help ensure that captive customers are protected and
that affiliate provisions are applied and administered in an even-
handed manner in harmony with legitimate current industry practices. We
seek comment on this proposal and on whether the specific affiliate
provisions proposed in this NOPR are sufficient to protect captive
customers. In particular, what changes, if any, should the Commission
adopt? Additionally, as previously noted, we seek comment on the
definition of ``captive customer.''
129. The proposed provisions are the same as those in the standard
code of conduct that exists today with the following exceptions. First,
the proposed regulations use the term ``non-regulated'' affiliates
instead of power marketer/power producer to make it clear that the
provisions apply to the relationship between a franchised public
utility and any of its affiliates that are not regulated under cost-
based regulation. This includes affiliate power marketers and affiliate
power producers, such as EWGs and QFs.
130. Second, in the case of companies that are acting on behalf of
and for the benefit of franchised public utilities with captive
customers, the proposed affiliate provisions treat such companies, for
purposes of the affiliate provisions, as the franchised public utility.
For example, if a company has been created to manage generation assets
for the franchised public utility, such entity is subject to the same
information sharing provision as the franchised public utility with
regard to information shared with non-regulated affiliates, such as
power marketers and power producers.
131. Likewise, in the case of non-regulated affiliates, the
proposed affiliate provisions treat companies that are acting on behalf
of and for the benefit of non-regulated affiliates, for purposes of the
affiliate provisions, as the non-regulated affiliates. For example,
asset managers of a non-regulated affiliate's generation assets are
treated as the non-regulated affiliate with regard to, for example, the
information sharing provision. We seek comment on this proposal.
132. The Commission invites comments proposing other additions,
substitutions, or eliminations to the proposed affiliate provisions.
[[Page 33120]]
D. Mitigation
1. Current Policy
133. The Commission began accepting applications for market-based
power sales in the late 1980s as a means to provide greater flexibility
to transactions in emerging competitive wholesale power markets. The
analysis for horizontal market power at that time was the ``hub and
spoke'' methodology, and under that methodology most sellers received
market-based rate approval. If, however, a seller failed the hub and
spoke analysis for a particular market, as a general matter, no
specific mitigation was imposed. Rather, the seller could continue to
sell power under existing cost-based rate schedules on file with the
Commission in that area.
134. The Commission began providing greater flexibility in setting
cost-based rates for coordination sales during this period as well.
Historically, utilities had set the rate for coordination sales on a
``split the savings'' formula \132\ or on the incremental cost of the
units participating in the sale (plus an adder). In the late 1980s,
however, the Commission began to approve a variety of ``up to'' rates
under which the applicant could charge a rate that was anywhere between
a ``floor'' of incremental cost and a ``ceiling'' of variable energy
costs plus an embedded cost demand charge. Examples of this more
flexible approach were the Western Systems Power Pool, Inc. agreement,
under which all sellers in the Western Interconnect could transact
under a common ceiling rate. The Commission also provided significant
flexibility to individual sellers, such as by allowing them to cap
rates at the cost of the most recently installed unit, even if that
unit was a high-cost baseload unit.
---------------------------------------------------------------------------
\132\ A seller's incremental cost (the out-of-pocket cost of
producing an additional MW) is compared with a buyer's decremental
cost (the cost of not producing the last MW). The average of the
incremental and decremental cost is the ``split the savings'' rate.
---------------------------------------------------------------------------
135. This more flexible approach to wholesale power sales continued
largely unchanged until 2001 when the Commission adopted the supply
margin assessment (SMA) test.\133\ The SMA sought to strengthen the
horizontal market power test in several significant ways, such as
considering transmission capability to limit the amount of competitive
supplies that could get into the relevant market. Although not imposing
a cost-based rate for longer term transactions, the SMA developed a
``must offer'' requirement and a ``split the savings'' formula in the
event that a seller failed the generation market power test, which was
the traditional cost-based ratemaking model used for spot market energy
sales.
---------------------------------------------------------------------------
\133\ See AEP Power Marketing, Inc., 97 FERC ] 61,219 (2001)
(SMA Order).
---------------------------------------------------------------------------
136. In the April 14 and July 8 Orders, the Commission replaced the
SMA test with two indicative screens for assessing horizontal market
power, the pivotal supplier screen and the wholesale market share
screen, and modified the Commission's approach to cost-based
mitigation.
137. In the April 14 Order, the Commission adopted default
mitigation tailored to three distinct products: (1) Sales of power of
one week or less will be priced at the seller's incremental cost plus a
10 percent adder; (2) sales of power of more than one week but less
than one year will be priced at an embedded cost ``up-to'' rate
reflecting the costs of the unit(s) expected to provide the service;
and (3) sales of power for one year or more will be priced at an
embedded cost of service basis and each such contract will be filed
with the Commission for review and approved prior to the commencement
of service. The Commission determined that sellers that are found to
have market power (i.e., after the Commission has ruled on the DPT
analysis), or that accept a presumption of market power, may either
accept the Commission's default cost-based mitigation measures or
propose their own case-specific measures tailored to their particular
circumstances that eliminate their ability to exercise market power,
including adopting existing cost-based rates, but did not provide
guidance as to which departures from the default mitigation would be
approved.\134\
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\134\ April 14 Order, 107 FERC ] 61,018 at P 147, 148 & n. 142,
150 & n. 144.
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2. Proposal
138. We seek comment on whether the default mitigation set forth in
the April 14 Order is appropriate as currently structured. In
particular, certain recurring issues have arisen in implementing the
cost-based mitigation and we seek comment on these issues.
Specifically, we seek comment, as discussed further below, on four
issues of recurring significance: (i) The rate methodology for
designing cost-based mitigation; (ii) discounting; (iii) protecting
customers in mitigated markets; and (iv) sales by mitigated sellers
that ``sink'' in unmitigated markets.
a. Cost-Based Rate Methodology.
139. We first seek comment on issues associated with the rate
methodology for designing cost-based mitigation. There are two
principal issues concerning rate methodology that have arisen in
implementing the April 14 Order. The first relates to the requirement
that sales of less than one week be made at incremental cost plus 10
percent. Sellers have argued that this is a departure from the
Commission's historical acceptance of ``up to'' rates for short-term
energy sales, including sales of less than one week. We seek comment on
whether to continue to apply a default rate for sales of less than one
week that is tied to incremental cost plus 10 percent. Are there
problems associated with using ``up to'' rates for shorter-term sales
and, if so, what are they? Does the current approach provide utilities
a disincentive to offer their power to wholesale customers in their
local control area for short-term sales? Would an ``up to'' rate
adequately mitigate market power for such sales?
140. The second rate methodology issue relates to the design of an
``up to'' cost-based rate. In the past, the Commission has allowed
significant flexibility in designing ``up to'' rates. Is that
flexibility still warranted? For example, there are often disputes over
which units are ``most likely to participate'' or ``could participate''
in coordination sales. Should the Commission continue to allow
utilities flexibility in selecting the particular units that form the
basis of the ``up to'' rate? If not, what units should an ``up to''
rate be based upon, and how should that rate be calculated? Should the
Commission prescribe a standard methodology that would allow an
applicant to avoid a hearing on rate methodology? Would a methodology
that is based on average costs (both variable and embedded) allow an
applicant to avoid a hearing because it eliminates the seller's
discretion in designating particular units as ``likely to
participate''? Are there other approaches that would accomplish a
similar objective?
141. In the April 14 and July 8 Orders, the Commission stated that
sellers that are found to have market power (i.e., after the Commission
has ruled on a DPT analysis) or that accept a presumption of market
power can either accept the Commission's default cost-based mitigation
measures or propose alternative methods of mitigation. With regard to
alternative methods of mitigation, should the Commission allow as a
means of mitigating market power the use of agreements that are not
tied to the cost of any particular seller but rather to a group of
sellers? Would
[[Page 33121]]
the use of such agreements as a mitigation measure satisfy the just and
reasonable standard of the FPA?
142. Finally, the Commission notes that if a mitigated seller is
returning to existing cost-based rates, the Commission would have the
obligation to consider whether those rates are sufficient for that
purpose, and would have the authority to institute a proceeding under
FPA section 206 to investigate their justness and reasonableness.
b. Discounting.
143. A seller that has authorization to sell under an ``up to''
cost-based rate has an incentive to discount its sales price when the
market price in the seller's local area is lower than the cost-based
ceiling rate. During these periods, a rational seller will discount its
sales to maximize revenue. In the past the Commission has encouraged
discounting as an efficient practice that can maximize revenues to
reduce the revenue requirements borne by customers.
144. The primary issue in this area is whether a seller can
``selectively'' discount, i.e., offer different prices to different
purchasers of the same product during the same time period. We seek
comment on whether selective discounting should be allowed for sellers
that are found to have market power or have accepted a presumption of
market power and are offering power under cost-based rates. If we do
allow selective discounting, what mechanisms (reporting or otherwise),
if any, are necessary to protect against undue discrimination? By
contrast, if we do not allow selective discounting, should we require
the utility to post discounts to ensure that they are available to all
similarly situated customers?
c. Protecting Mitigated Markets.
145. Under our current policy, if a seller loses market-based rate
authority in its home control area, any sales in that control area must
be pursuant to cost-based rates; however, there is no requirement that
the seller offer its available power to customers in that home control
area. Instead, the seller is free to market all its available power to
purchasers outside that control area if, for example, market prices
outside its control area exceed the cost-based caps. Wholesale
customers have argued that default cost-based mitigation of this kind
is of little value if a mitigated seller can simply market its excess
capacity at market-based rates in other control areas.\135\ To address
this concern, commenters have suggested that the Commission either
revoke a mitigated seller's market-based rate authority in all control
areas or impose some type of mitigation that protects wholesale
customers in those areas where a seller has been found to have market
power or has accepted the presumption of market power.
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\135\ See, e.g., Carolina Power and Light Company, 113 FERC ]
61,130 at P 16 & n.21 (2005).
---------------------------------------------------------------------------
146. The Commission seeks comment on whether its current policy is
appropriate and, if not, what further restrictions are necessary. In
particular, we seek comment on the following:
a. Is it appropriate to continue to allow sellers that are subject
to mitigation in their home control area to sell power at market-based
rates outside their control area? Does this represent undue
discrimination or otherwise constitute ``withholding'' in the home
control area that is inconsistent with the FPA's mandate that rates be
just, reasonable and not unduly discriminatory? Or, does this reflect
economically efficient behavior and encourage necessary trading within
and across regions, particularly in peak periods when marginal prices
rise above average embedded costs?
b. Should the Commission adopt a form of ``must offer'' requirement
in mitigated markets to ensure that available capacity (i.e., above
that needed to serve firm and native load customers) is not withheld?
If so, should the must offer requirement be limited to sales of a
certain period to help ensure that wholesale customers use that power
to serve their own needs, rather than simply remarketing that power
outside the control area and profiting? For example, should there be an
annual open season under which the mitigated seller offers its
available capacity to local customers for the following year at the
cost-based ceiling rate and, if customers do not commit to purchase
that capacity, then the seller is free to sell the remaining capacity
at market-based rates where it has authority to do so? If we adopt such
a must offer requirement, what rules should there be to define
``available'' capacity to avoid case-by-case disputes over this issue?
c. As an alternative, should the Commission find that any seller
that has lost market-based rate authority in its home control area
should not be able to sell power at market-based rates in adjacent
(first tier) control areas?
Would this be appropriate mitigation and easier to implement than a
must offer requirement? Or, would such mitigation unnecessarily
discourage trading and flexibility in markets for which the seller has
been found not to have market power?
d. Sales that Sink in Unmitigated Markets.
147. The Commission has stated that its role is to assure customers
that sellers who are authorized to sell at market-based rates do not
have market power or have adequately mitigated the potential exercise
of market power.\136\ Further, the Commission's recent orders accepting
mitigation proposals are clear that the mitigation is to apply to sales
in the geographic market where an applicant is found (or presumed) to
have market power (mitigated market), not only sales to end users in
the control area.\137\ In order to put in place adequate mitigation
that eliminates the ability to exercise market power and ensure that
rates are just and reasonable,\138\ all market-based rate sales in a
mitigated market where an applicant is found or presumed to have the
ability to exercise market power must be subject to mitigation approved
by the Commission.
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\136\ July 8 Order, 108 FERC ] 61,026 at P 146.
\137\ See Oklahoma Gas and Electric Company and OGW Energy
Resources, Inc., 114 FERC ] 61,297 (2006), reh'g pending; Carolina
Power and Light Company, 114 FERC ] 61,294 (2006) (CP&L); Duke
Energy Trading and Marketing, L.L.C., 114 FERC ] 61,056 (2006).
\138\ See April 14 Order at P 144, 147.
---------------------------------------------------------------------------
148. Some companies have proposed limiting mitigation to sales that
``sink in'' the mitigated market, that is, so that mitigation would
only apply to end users in the mitigated market.\139\ However, in
MidAmerican Energy Company,\140\ the Commission stated that limiting
mitigation to sales that ``sink in'' the mitigated market would
improperly limit mitigation to certain sales, namely, only to sales to
those buyers that serve end-use customers in the mitigated market.
Limiting mitigation in this manner would improperly allow market-based
rate sales within the mitigated market to entities that do not serve
end-use customers in the mitigated market. Such a limitation would not
mitigate the seller's ability to attempt to exercise market power over
sales in the mitigated market and is inconsistent with our direction in
the April 14 and July 8 Orders. For example, on rehearing of the April
14 Order, it was argued that access to power sold under mitigated
prices should be restricted to buyers serving end-use customers within
the relevant geographic market in which the applicant has been found to
have market power. In particular, arguments were made that an applicant
should not be required to make sales at mitigated prices to power
marketers or brokers
[[Page 33122]]
without end-use customers in the relevant market. In the July 8 Order,
the Commission rejected the suggestion that we restrict mitigated
applicants to selling power only to buyers serving end-use
customers,\141\ and has since rejected tariff language that proposes to
do so.\142\
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\139\ The Commission has recently clarified that mitigation
applies to all sales in a mitigated market. See, e.g., CP&L, 114
FERC ] 61,294 at P 9 (2006).
\140\ 114 FERC ] 61,280 (2006), reh'g pending (MidAmerican).
\141\ See July 8 Order, 108 FERC ] 61,026 at P 134.
\142\ See, e.g., MidAmerican, 114 FERC ] 61,280 at P 33.
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149. The Commission seeks comment on whether it should modify or
revise its current policy and, if so, how. In particular, we seek
comment on the following:
a. Should the Commission allow market-based rate sales by a
mitigated seller within a mitigated market if those sales do not
``sink'' in that control area? If so, under what circumstances should
the Commission allow such sales and how would the Commission ensure
that such sales do indeed ``sink'' in an unmitigated control area? How
does the Commission distinguish possible permissible sales to the
border of the restricted control area from sales that are not permitted
within the restricted control area?
b. Under such a policy, what opportunities, if any, are presented
to ``game'' the mitigation? If it is determined that a mitigated
seller's sales in fact do not ``sink'' outside the restricted control
area, what penalties should the Commission consider?
c. If the Commission retains its current policy of prohibiting all
market-based rate sales by a mitigated seller in a mitigated market
what effect, if any, does such a policy have on existing contractual
arrangements? With regard to existing transmission rights a buyer may
have in a mitigated market, how easily could existing market-based rate
agreements between that buyer and the mitigated seller be amended to
provide for delivery of power in an unmitigated market under the same
economic terms as exists today?
E. Implementation Process
1. Current Practice
150. The Commission's current practice is a case-by-case analysis
of new applications for market-based rate authorization as well as
updated market power analyses. In addition, to date the Commission has
allowed sellers to propose their own individualized tariffs.
2. Proposal
151. The Commission proposes to put in place a structured,
systematic review to assist the Commission in analyzing sellers based
on a coherent and consistent set of data for relevant geographic
markets. In addition, some corporate families have many subsidiaries
with market-based rate authorization, each with its own separate
tariff. This has led to confusion, inconsistencies between the tariffs
of a single corporate family, and difficulty in coordinating changes to
the tariffs. To remedy these concerns, the Commission proposes to
streamline the administrative process associated with the filing and
review of market-based rate updated market power analyses and to
consolidate market-based rate authorizations into a single tariff.
152. The Commission proposes to continue to require sellers to
submit updated market power analyses for all relevant geographic
markets (default or proposed alternative markets, as discussed
previously) in which they own or control generation. However, the
Commission proposes to modify this filing requirement in two ways.
First, the Commission proposes to establish two categories of sellers
with market-based rate authorization. The first category (Category 1)
would include power marketers and power producers that own or control
500 MW or less of generating capacity in aggregate and that are not
affiliated with a public utility with a franchised service territory.
In addition, Category 1 sellers must not own or control transmission
facilities other than limited equipment necessary to connect individual
generating facilities to the transmission grid (or must have been
granted waiver of the requirements of Order No. 888 because such
facilities are limited and discrete and do not constitute an integrated
grid \143\), and must present no other vertical market power issues.
Rather than requiring Category 1 sellers to file a regularly scheduled
triennial review, the Commission would monitor any market power
concerns through the change in status reporting requirement and through
ongoing monitoring by the Commission's Office of Enforcement.\144\ All
sellers with market-based rate authority are required to make a filing
with the Commission regarding any change in status that reflects a
departure from the characteristics that the Commission relied upon in
granting market-based rate authority. Failure to timely file a change
in status report would constitute a violation of the Commission's
regulations and the seller's MBR tariff.\145\ A seller would be subject
to disgorgement of profits and/or civil penalties from the date on
which the tariff violation occurred. Such seller may also be subject to
suspension or revocation of its authority to sell at market-based rates
(or other appropriate non-monetary remedies). In addition, the
Commission would retain the right to initiate a section 206 proceeding
if circumstances warranted. A seller that no longer satisfies the
Category 1 criteria would be required to submit a change in status
notification and would be subject to the updated market power analysis
filing required of Category 2 sellers.
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\143\ See, e.g., Black Creek Hydro, Inc., 77 FERC ] 61,232
(1996).
\144\ Order No. 652, FERC Stats. & Regs., ] 31,175.
\145\ Id. at P 113.
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153. The second category (Category 2) would include all sellers
that do not qualify for Category 1. Category 2 sellers, in addition to
the requirement to file change in status reports, would be required to
file regularly scheduled triennial reviews. Category 2 sellers are the
larger sellers with more of a presence in the market and are more
likely to either fail one or more of the indicative screens or pass by
a smaller margin than Category 1 sellers.
154. To ensure greater consistency in the data used to evaluate
Category 2 sellers, the Commission proposes to require each seller to
file updated market power analyses for its relevant geographic markets
(default and any proposed alternative markets) on a schedule that will
allow examination of the individual seller at the same time the
Commission examines other sellers in these relevant markets and
contiguous markets within a region from which power could be
imported.\146\ The regional reviews would rotate by geographic region
with three regions reviewed per year. Appendix B provides a schedule
for the proposed regional review process. The Commission proposes to
continue to make findings on an individual seller basis, but will have
before it a complete picture of the uncommitted capacity and
simultaneous import capability into the relevant geographic markets
under review.
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\146\ Sellers would be deemed to be assigned to a region based
on the control area in which they own or control generation. Nine
regions will be examined using the regions specified in the 2004
State of the Markets Report, excluding ERCOT, as shown in the map
attached as part of Appendix B. Those regions are: Northwest,
California, Southwest, Midwest, SPP, Southeast, PJM, New York, and
New England.
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155. The Commission proposes to codify in its regulations the
obligation for Category 2 sellers to timely file a triennial review. As
a result, failure to timely file a triennial review would constitute a
violation of the Commission's regulations and the seller's MBR tariff
and could result in disgorgement of profits and/or civil
[[Page 33123]]
penalties from the date on which the seller violated its tariff.\147\ A
seller may also be subject to suspension or revocation of its authority
to sell at market-based rates (or other appropriate non-monetary
remedies). If a seller files a timely triennial review, its market-
based rate authority would continue unless the Commission institutes a
section 206 proceeding because the seller fails one of the indicative
screens and the Commission subsequently makes a definitive finding of
market power and revokes its market-based authority, or the seller
accepts the presumption of market power and adopts the default cost-
based mitigation or proposes other cost-based mitigation or tailored
mitigation.
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\147\ Currently, the requirement to file triennial reviews is
contained in our orders, but not in the tariffs or in our
regulations.
---------------------------------------------------------------------------
156. Some corporate families own or control generation in multiple
control areas and different regions. For example, a corporate family
may own generation facilities on the east coast as well as in
California. In this instance, the corporate family would be required to
file a current triennial review for each region in which members of the
corporate family sell power during the time period specified for that
region. To the extent a new subsidiary is formed and a new request for
market-based rate authority is submitted, triennial reviews will be due
at the regularly scheduled time for review of the markets in the region
in which the new applicant owns or controls generation. We seek comment
on this proposal.
157. In addition, the Commission proposes to require that all
triennial review filings and all new applications for market-based rate
authority include an appendix listing all generation assets owned or
controlled by the corporate family by control area and listing the in-
service date and nameplate and/or seasonal ratings by unit. The
appendix should also reflect all electric transmission and natural gas
intrastate pipelines and/or gas storage facilities owned or controlled
by the corporate family and the location of such facilities.
158. Triennial reviews should reflect the most recently available
historical data from the calendar year prior to the year of filing.
159. We seek comments on the proposal to adopt these filing
requirements.
F. Market-Based Rate Tariff (MBR Tariff)
160. Historically the Commission has not required the filing of a
market-based rate tariff of general applicability. However, many
sellers have submitted one or more umbrella market-based rate tariffs
that set forth the conditions of market-based rate approval and the
general terms applicable to all transactions, with individual
transactions being negotiated through service agreements, letter
confirmations, or other documentation that sets forth the rates and any
individualized terms and conditions. This general practice has afforded
flexibility to sellers as markets and the industry evolved and as new
products and services were sold under market-based rate tariffs.
However, this flexible approach has sometimes resulted in inconsistency
in the tariffs filed within the same corporate family, which can create
confusion for customers and compliance problems, and it also has
resulted in inconsistencies in memorializing the conditions of market-
based rate approval in such tariffs.
161. As part of our effort to streamline and simplify the market-
based rate program in general, while at the same time maintaining a
high degree of transparency and oversight, we propose to adopt a
market-based rate tariff of general applicability that all sellers
authorized to sell wholesale electric power at market-based rates will
be required to file as a condition of market-based rate authority.\148\
The MBR tariff would require the seller to comply with the applicable
provisions of the market-based rate regulations which this NOPR
proposes to codify in 18 CFR Part 35, Subpart H. These provisions
reflect the Commission's two decades of experience with market-based
rate power sales and should serve to reduce the burden on customers of
managing multiple tariffs. In addition, the seller would be required to
list on the MBR tariff the docket numbers and case citations, where
applicable, of the proceedings, if any, in which the seller received
Commission authorization to make sales of energy between affiliates or
where its market-based rate authority was otherwise restricted or
limited. A copy of the proposed MBR tariff is attached as Appendix A.
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\148\ Order No. 614 guidelines for designating rate schedules
must be observed.
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162. Not all of the provisions of the proposed regulations may be
applicable to all sellers. For example, a seller may not wish to offer
ancillary services under the tariff. The Commission seeks comments on
whether a placeholder should be reserved in the MBR tariff for the
seller to indicate those parts of the regulations that are not
applicable to that seller.
163. In proposing the adoption of the MBR tariff, our purpose is
not to direct the terms and conditions of a particular power sale or to
otherwise reduce the flexibility afforded to market-based rate sellers
in fashioning the terms of individual transactions. Rather, sellers
would continue to negotiate the terms and conditions of sales entered
into under their MBR tariff, and the terms and conditions of those
underlying agreements and the transaction data would be reflected in
the quarterly EQRs. Further, if sellers wish to offer or require
certain ``generic'' terms and conditions that in the past were
contained in their market-based rate tariff, they may place customers
on notice of such requirements by including such information on a
company website and include any related provisions in individual
transaction agreements. Our purpose in requiring a MBR tariff of
general applicability is to ensure that the MBR tariff on file with the
Commission for each seller reflects, in a consistent manner, only those
matters that are required to be on file, namely, the identity of the
seller(s), the docket number(s) of the market-based rate authorization,
the seller's requirement to follow the conditions of market-based rate
authorization contained in our proposed regulations, and that the
rates, terms and conditions of any particular sale will be negotiated
between the seller and individual purchasers. We do not believe any
useful purpose is served in having on file the commercial terms
preferred by particular applicants, given that the purpose of market-
based rate authorization is to provide flexibility in such terms and
conditions. Furthermore, our standards for approval of market-based
rates do not include a review of such individualized commercial terms
and thus, such submissions are unnecessary.
164. Further, the Commission proposes that, rather than each entity
having its own MBR tariff, which can result in dozens of tariffs for
each corporate family with conflicting provisions, each corporate
family has only one tariff on file, with all affiliates with market-
based rate authority separately identified in the tariff. This will
allow for better transparency with regard to what sellers each
corporate family has, and a more customer-friendly tariff. The
requirement to have a single MBR tariff does not mean that all members
of a corporate family would be counterparties on every sale under the
tariff; rather, individual transactions would continue to be
consummated
[[Page 33124]]
with individual sellers within the corporate family, as they are today.
165. We seek comments on this proposal.
166. Regarding the specifics of filing the MBR tariffs, we note
that the Commission has initiated a rulemaking proceeding to require
the filing of electronic tariffs.\149\ We propose that the timing of
filing and format for the MBR tariffs be consistent with the
requirements of the final rule issued in that proceeding.
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\149\ See Electronic Tariff Filings, Notice of Proposed
Rulemaking, 69 FR 43929 (July 23, 2004), FERC Stats. & Regs.,
Proposed Regulations ] 32,575 (July 8, 2004).
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G. Miscellaneous Issues
1. Waivers
167. Certain entities with market-based rate authority have
typically been granted waiver of the Commission's Uniform System of
Accounts, and thus have not been subject to specified accounting rules.
For instance, Parts 41, 101, and 141 of the Commission's regulations
prescribe certain informational requirements that focus on the assets
that a public utility owns.\150\ For market-based rate applications,
the Commission has taken the position that, because a power marketer
does not own any electric power generation or transmission facilities,
its jurisdictional facilities would be only corporate and documentary,
its costs would be determined by utilities that sell power to it, and
its earnings would not be defined and regulated in terms of an
authorized return on invested capital; accordingly, the Commission has
granted waivers to power marketers of the requirements of these Parts.
The Commission also has granted other market-based rate sellers, such
as independent or affiliated power producers, waiver of the
requirements of these Parts.
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\150\ Part 41 pertains to adjustments of accounts and reports;
Part 101 contains the Uniform System of Accounts; Part 141 describes
required forms and reports.
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168. The Commission has also granted power marketers' and others'
requests for blanket approval under Part 34 of the Commission's
regulations for all future issuances of securities and assumptions of
liability, assuming that no party objects to such treatment during a
notice period which the Commission provides.\151\ The purpose of
section 204 of the FPA, which Part 34 implements, is to ensure the
financial viability of public utilities obligated to serve electric
consumers. The Commission has granted blanket approval under Part 34
for future issuances of securities and assumptions of liability where
the entity seeking market-based rate authority, such as a power
marketer or power producer, is not a public service franchise providing
electricity to consumers dependent upon its service.\152\
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\151\ We note that the Commission's jurisdiction over issuances
of securities and assumptions of liabilities under section 204 of
the FPA applies only to entities that are public utilities as
defined in the FPA and only where the public utilities' security
issues are not regulated by a State commission (see FPA section
204(f)).
\152\ See, e.g., St. Joe Minerals Corp., 21 FERC ] 61,323
(1982); Cliffs Electric Service Company, 32 FERC ] 61,372 (1985);
Citizens Energy Corp., 35 FERC ] 61,198 (1986); Howell Gas
Management Company, 40 FERC ] 61,336 (1987); and Nevada Sun-Peak
Limited Partnership, 86 FERC ] 61,243 (1999).
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169. As the development of competitive wholesale power markets
continues, independent and affiliated power marketers and power
producers are playing more significant roles in the electric power
industry. In light of the evolving nature of the electric power
industry, the Commission seeks comment on the extent to which these
entities should be required to follow the Uniform System of Accounts,
what financial information, if any, should be reported by these
entities, and how frequently it should be reported, and whether the
Part 34 blanket authorizations continue to be appropriate.
170. The Commission announced in the April 14 Order that, where an
applicant is found to have market power (or where the applicant accepts
a presumption of market power), the applicant will be required to adopt
some form of cost-based rates or other mitigation the applicant
proposes and the Commission accepts. Under these circumstances, the
Commission found that it is essential that appropriate accounting
records be maintained consistent with the Commission's regulations.
Accordingly, the Commission indicated it will no longer waive the
otherwise applicable accounting regulations (e.g. Parts 41, 101, and
141 of the Commission's regulations).\153\ Thus, the Commission would
revoke the accounting waivers for a mitigated seller, and for any of
its affiliates with market-based rates in the mitigated control area.
Further, the Commission stated that it will not grant blanket approval
for issuances of securities or assumptions of liability pursuant to
Part 34 of the Commission's regulation for the mitigated seller and its
affiliates.\154\ In the case of any affiliates, this would entail
rescission of these blanket authorizations in all geographic areas, not
just the mitigated control area.
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\153\ April 14 Order, 107 FERC ] 61,018 at P 150.
\154\ Id.
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171. We note that some sellers have had their market-based rate
authority revoked, or have elected to relinquish their market-based
rate authority after a presumption of market power, and have begun or
resumed selling power at cost-based rates. Consistent with the April 14
Order, any waivers previously granted in connection with those sellers'
market-based rate authority are no longer applicable. We propose that
such revocation of waivers become effective 60 days from the date of an
order revoking such waivers in order to provide the affected utility
with time to make the necessary filings with the Commission and allow
for an orderly transition from selling under market-based rates to
cost-based rates. We seek comment in this regard. The Commission seeks
input regarding any difficulties sellers may have when transitioning to
cost-based rates and whether a prior waiver of the accounting
regulations would leave them without adequate data to come into
conformance with the accounting rules.
2. Foreign Sellers
172. Under existing policy, a foreign entity selling in the United
States (and each of its affiliates) must not have, or must have
mitigated, market power in generation and transmission and not control
other barriers to entry. In addition, the Commission considers whether
there is evidence of affiliate abuse or reciprocal dealing. However,
for foreign sellers, the Commission allows a modified approach to the
four prongs.
173. With regard to generation market power, should a foreign
seller or any of its affiliates own or control any generation in the
United States, or should one of its first-tier markets include a United
States market, it should perform the market power screens in the
appropriate control area(s).
174. With regard to transmission market power, the Commission
requires a foreign seller seeking market-based rate authority to
demonstrate that its transmission-owning affiliate offers non-
discriminatory access to its transmission system that can be used by
competitors of the foreign seller to reach United States markets.\155\
However, if foreign transmission facilities meet the criteria
[[Page 33125]]
for waiver of Order No. 888, such a demonstration would not be
required.\156\
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\155\ See TransAlta Enterprises Corp., 75 FERC ] 61,268 at
61,875 (1996), and Energy Alliance Partnership, 73 FERC ] 61,019 at
61,030-31 (1995) (Energy Alliance).
\156\ Canadian Niagara Power Company, 87 FERC ] 61,070 (1999).
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175. For purposes of market-based rate authorization, the
Commission does not consider transmission and generation facilities
that are located exclusively outside of the United States and that are
not directly interconnected to the United States. However, the
Commission would consider transmission facilities that are exclusively
outside the United States but nevertheless interconnected to an
affiliate's transmission system that is directly interconnected to the
United States.\157\
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\157\ Fortis Ontario, Inc. and Fortis U.S. Energy Corp., 115
FERC ] 61,110 (2006).
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176. Regarding other potential barriers to entry, a foreign seller
should inform the Commission of any potential barriers to entry that
can be exercised by either it or its affiliates in the same manner as a
seller located within the United States.
177. Finally, regarding affiliate abuse, the Commission typically
requires a power marketer with market-based rate authorization to file
for approval under section 205 of the FPA before selling power to or
purchasing power from any utility affiliate. However, this general
requirement does not apply to situations involving sales of power to or
from a foreign utility outside of the Commission's jurisdiction.\158\
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\158\ Energy Alliance, 73 FERC ] 61,019 at 61,031; TransAlta, 75
FERC ] 61,268 at 61,876.
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178. The Commission proposes to retain its current policy when
reviewing a foreign seller's application for market-based rate
authorization consistent with our overall approach discussed herein.
The Commission seeks comments regarding whether this current policy is
adequate to grant market-based rate authorization to such sellers.
3. Change in Status
179. In early 2005, the Commission clarified and standardized
market-based rate sellers' reporting requirement for any change in
status that departed from the characteristics the Commission relied on
in initially authorizing sales at market-based rates. In Order No.
652,\159\ the Commission required, as a condition of obtaining and
retaining market-base rate authority, that sellers file notices of such
changes no later than 30 days after the change in status occurs. The
rule provided that a change in status includes, but is not limited to:
(i) Ownership or control of generation or transmission facilities or
inputs to electric power production other than fuel supplies, or (ii)
affiliation with any entity not disclosed in the application for
market-based rate authority that owns or controls generation or
transmission facilities or inputs to electric power production, or
affiliation with any entity that has a franchised service area.\160\ A
seller's experiencing one of these changes would trigger the
notification requirement.\161\
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\159\ Order No. 652 at P 47.
\160\ See 18 CFR 35.27(c) (2005).
\161\ If a seller ceases to do business, or, in the event of its
dissolution, such seller should file a notice of cancellation of its
rate schedule.
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180. The Commission has provided further guidance on change in
status filings in several cases. In Calpine Energy Services, L.P.,\162\
the Commission clarified that sellers making a change in status filing
to report an energy management agreement are required to make an
affirmative statement regarding whether the agreement transfers control
of any assets and whether it results in any material effect on the
conditions the Commission relied on when granting market-based rates.
The Commission also clarified that:
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\162\ 113 FERC ] 61,158 at P 13 (2005).
A seller making a change in status filing is required to state
whether it has made a filing pursuant to section 203 of the Federal
Power Act. To the extent the seller has made a section 203 filing
that it submits is being made out of an abundance of caution and
thus has voluntarily consented to the Commission's section 203
jurisdiction, the seller will be required to incorporate this same
assumption in its market-based rate change in status filing (e.g.,
if the seller assumes that it will control a jurisdictional facility
in a section 203 filing, it should make that same assumption in its
market-based rate change in status filing and, on that basis, inform
the Commission as to whether there is any material effect on its
market-based rate authority).[\163\]
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\163\ Id. at P 14 (footnotes omitted).
181. In addition, market-based rate sellers must report as a change
in status each cumulative increase in generation of 100 MW or more that
has occurred since the most recent notice of change in status filed by
that seller (i.e., multiple increases in generation that individually
do not exceed the 100 MW threshold must all be reported once the
aggregate amount of such increases reaches 100 MW or more).\164\ The
Commission reserves the right to require additional information,
including an updated market power analysis, if necessary to determine
the effect of an entity's change in status on its market-based rate
authority.\165\
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\164\ See Order No. 652, FERC Stats. & Regs. ] 31,175 at P 68.
The reporting requirement is triggered only by net, rather than
gross, increases in generation capacity of 100 MW or more. For
example, capacity decreases associated with changes in generation
capacity or expiration of capacity under long-term purchase
contracts should be netted against generation capacity increases to
determine whether the 100 MW materiality threshold has been reached.
The Commission has adopted a netting approach in determining whether
the materiality threshold has been reached, subject to the
cumulative 100 MW threshold. See Order No. 652-A, 111 FERC ] 61,413
at P 24-25.
\165\ Order No. 652 at P 95.
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182. In Order No. 652, the Commission identified a number of issues
that could be pursued in the instant rulemaking proceeding. The
Commission had proposed in that rulemaking proceeding to include fuel
supplies as an input to electric power production the acquisition of
which would be a reportable change in status. However, in the final
rule, the Commission determined that this issue would be more
appropriately raised in the instant rulemaking proceeding, and stated
that the Commission would provide opportunity for interested persons to
propose modifications to the existing approach in this proceeding.\166\
Accordingly, the Commission solicits comments on whether ownership of
any new inputs to electric power production, including fuel supplies,
should be reportable. To the extent that any such information is deemed
reportable, the Commission proposes to align this reporting requirement
to reflect the consideration of other barriers to entry as part of the
vertical market power analysis, and commenters should refer to the
discussion of other barriers to entry herein where the Commission
proposes to clarify what constitutes an input to electric power
production as part of the Commission's review of vertical market power.
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\166\ Id. at P 58.
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183. In Order No. 652, the Commission clarified that the reporting
of transmission outages per se as a change in status was not required.
However, to the extent a transmission outage affects, on a long-term
basis (e.g., an extended outage of a circuit or substation), whether
the seller satisfies the Commission's concerns regarding horizontal or
vertical market power (e.g., if it reduces imports of capacity by
competitors that, if reflected in the generation market power screens,
would change the results of the screens from a ``pass'' to a ``fail''),
a change of status filing would be required. The Commission also stated
that it would consider this matter further in the context of this
rulemaking in the transmission market power part of the market power
analysis.\167\ We propose,
[[Page 33126]]
consistent with Order No. 652, not to require the reporting of
transmission outages per se as a change in status. We seek comment on
this proposal.
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\167\ Id. at P 75.
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184. The Commission declined in Order No. 652 to narrow or
delineate the definition of control. The Commission noted that,
historically, if a seller has control over certain capacity such that
it can affect the ability of the capacity to reach the relevant market,
then that capacity should be attributed to the seller when performing
the generation market power screens. Further, the capacity associated
with contracts that confer operational control of a facility to an
entity other than the owner must be assigned to the entity exercising
control over that facility. The Commission concluded that it is not
possible to predict every contractual agreement that could result in a
change of control of an asset. However, the Commission indicated that
to the extent that parties wish to propose specific definitions or
clarifications to the Commission's historical definition of control,
they may do so in the course of the instant rulemaking.\168\ As
discussed above, the horizontal market power section herein seeks
comment on a number of issues concerning control and commitment of
generation.
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\168\ Id. at P 47.
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185. In Order No. 652 we did not expand the triggering events for a
change in status filing to include actions taken by a competitor (such
as a decision to retire a generation unit or take transmission capacity
out of service) or natural events (such as hydro-year level, higher
wind generation, or load disruptions due to adverse weather
conditions). In Order No. 652, we concluded that the reporting
obligation should extend only to changes in circumstances within the
knowledge and control of the seller. However, in Order No. 652, we
stated that interested persons could pursue in the instant rulemaking
whether the Commission should expand the triggering events for a change
in status filing. Accordingly, we invite comments generally on whether
the Commission should expand the triggering events beyond ownership or
control of facilities or inputs and affiliation with entities that own
or control facilities or inputs or that have a franchised service
territory, as adopted in Order No. 652.
4. Third-Party Providers of Ancillary Services
186. In Order No. 888, the Commission required transmission
providers to offer certain ancillary services at cost-based rates as
part of their open access commitment but also contemplated that third
parties (parties other than the transmission provider in a particular
transaction) would also provide ancillary services.\169\ The Commission
also left open the door that ancillary services could be provided on
other than a cost-of-service basis. In Order No. 888, Commission stated
that it would entertain requests for market-based pricing related to
ancillary services on a case-by-case basis if supported by analyses
that demonstrate that the seller lacks market power in these discrete
services.\170\ In Ocean Vista Power Generation, L.L.C. (Ocean
Vista),\171\ the Commission explained that as a general matter a study
of ancillary service markets should address the nature and
characteristics of each ancillary service, as well as the nature and
characteristics of generation capable of supplying each service, and
that the study should develop market shares for each service. The
Commission also noted that it would entertain alternative explanations
and approaches.
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\169\ See Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,720-
21.
\170\ Id.; Order No. 888-A, FERC Stats. & Regs. ] 31,048 at
30,237-38.
\171\ 82 FERC ] 61,114 at 61,406-07.
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187. In Ocean Vista, the Commission also offered more detailed
guidance for what a market power study for ancillary services markets
should include: (1) Defining a relevant product market for each
ancillary service, which should include the applicant's product,
together with other products that, from the buyer's perspective, are
good substitutes; (2) identifying the relevant geographic market, which
could include all potential suppliers of the product from whom the
buyer could obtain the service, taking into account relevant factors
which may include the other suppliers' locations, the physical
capability of the delivery system and the cost of such delivery, and
important technical characteristics of the suppliers' facilities; (3)
establishing market shares for all suppliers of the ancillary services
in the relevant geographic markets; and (4) examining other barriers to
entry.
188. The guidance offered by the Commission in Order No. 888 and
Ocean Vista was designed for two purposes: to ensure that sellers of
ancillary services do not exercise market power and to further the goal
of promoting competition in ancillary service markets.
189. However, in Avista Corporation,\172\ the Commission stated
that there remained two problems hindering the development of ancillary
service markets. First, access to critical data may preclude many
potential sellers of ancillary services from performing reliable market
analyses. Second, without an alternative means of regulating ancillary
service rates at an early stage in the development of competitive
wholesale power markets, the Commission may not be able to encourage
sufficient market entry of third-party providers of ancillary services.
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\172\ 87 FERC ] 61,223, order on reh'g, 89 FERC ] 61,136 (1999)
(Avista).
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190. Accordingly, the Commission adopted a policy wherein third-
party ancillary service providers that cannot perform a market power
study would be allowed to sell ancillary services at market-based
rates, but only in conjunction with a requirement that such third
parties establish an Internet-based OASIS-like site for providing
information about and transacting ancillary services.
191. In this regard, the Commission stated that it will apply this
policy only to applicants who are authorized to sell power and energy
at market-based rates. In addition, the Commission stated that it will
not apply this approach to sales of ancillary services by a third-party
supplier in the following situations: (1) The approach will not apply
to sales to a regional transmission organization (RTO) or an
independent system operator (ISO), i.e., where that entity has no
ability to self-supply ancillary services but instead depends on third
parties (the Commission stated that its experience to date indicates
that the data problems associated with market analysis involving sales
to an ISO, for example, should not be insurmountable and an appropriate
showing of a lack of market power can be made); \173\ (2) to address
affiliate abuse concerns, the approach will not apply to sales to a
traditional, franchised public utility affiliated with the third-party
supplier,
[[Page 33127]]
or to sales where the underlying transmission service is on the system
of the public utility affiliated with the third-party supplier; and (3)
the approach will not apply to sales to a public utility who is
purchasing ancillary services to satisfy its own open access
transmission tariff requirements to offer ancillary services to its own
customers (the Commission indicated that it is open, however, to
considering requests for market-based rates in such circumstances on a
case-by-case basis).\174\
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\173\ With the formation of RTOs and ISOs, several RTO/ISOs
performed market analyses to demonstrate whether various ancillary
services are competitive. The result has been as follows: California
Independent System Operator: Regulation, Spinning Reserve, and Non-
Spinning Reserve. ISO New England: Regulation and Frequency
(Automatic Generation Control), Operating Reserve--Ten-Minute
Spinning, Operating Reserve--Ten-Minute Non-Spinning, and Operating
Reserve--Thirty Minute. New York Independent System Operator:
Regulation and Frequency Response Service, Operating Reserve Service
(including Spinning Reserve, 10-Minute Non-Synchronized Reserves and
30-Minute Reserves). PJM Independent System Operator: Regulation and
Frequency Response, Energy Imbalance, Operating Reserve--Spinning,
and Operating Reserve--Supplemental. Thus, in markets where the
demonstration has been made, sellers are afforded the opportunity to
sell at market-based rates subject to any other conditions in those
markets.
\174\ Avista, 87 FERC at 61,883 n. 12.
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192. The Commission based its policy as announced in Avista on the
expectation that, as entry into ancillary service markets occurs,
prices will decrease from the level established by the transmission
provider's cost-based rate. Under these circumstances, customers will
pay prices for ancillary services that are no higher than and will very
likely be lower than the transmission provider's cost-based rate.\175\
The Commission explained that the ancillary services customer is
protected in part by the availability of the same ancillary services at
cost-based rates from the transmission provider. The backstop of cost-
based ancillary services from the transmission provider provides, in
effect, a limit on the price at which customers are willing to buy
ancillary services. The Commission stated that it believes that this
protection, in conjunction with the Internet-based site requirement,
will provide an appropriate and effective safeguard against potential
anticompetitive behavior.
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\175\ The Commission stated that it is cognizant of, but will
address separately and at the appropriate time, situations in which
it becomes apparent that, due to changes in ancillary services
markets, competitive prices would be higher than the transmission
provider's cost-based rate, were it not for the transmission
provider's obligation to meet all demand for ancillary services at
such a rate.
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193. The information contained in the Internet-based site would
include service availability, prices, and requests granted and denied.
To further monitor development of market entry, the Commission required
third-party suppliers to file with the Commission one year after their
Internet-based site is operational (and at least every three years
thereafter \176\) a report detailing their activities in the ancillary
services market.
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\176\ The Commission reserves the right to require that such a
report be filed at any time.
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194. In particular, the Commission stated that:
[i]f the applicant cannot perform a study showing that it lacks
market power in the provision of ancillary services, it may receive
flexible rates provided it safeguards against potential
anticompetitive behavior by establishing an Internet-based site for
providing information regarding, and conducting, ancillary services
transactions. The site would include postings of offers of services
available and their offering prices and would provide customers with
the ability to request services and make bids for these services.
The site would also contain information about accepted and denied
requests and the reasons for denial. The site should conform to the
applicable OASIS Standards and Communications Protocols (Version
1.3).[\177\]
\177\ Avista, 87 FERC at 61,884. We note that section 37.6(d)(5)
of the Commission's regulations states: ``Any entity offering an
ancillary service shall have the right to post the offering of that
service on the OATT if the service is one required to be offered by
the Transmission Provider under the pro-forma tariff prescribed by
part 35 of this chapter. Any entity may also post any other
interconnected operations service voluntarily offered by the
Transmission Provider. Postings by customers and third parties must
be on the same page, and in the same format, as posting of the
Transmission Provider.''
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195. We propose to retain our current approach in this regard. We
seek comment on whether we should modify or revise our current approach
and, if so, how. Also, we seek comment on whether our current
conditions such as the requirement to establish an Internet-based site
continue to be necessary.
Proposed Revisions To Regulations
I. Section 35.27 [Currently] Power Sales at Market-Based Rates
196. Subsections (a) and (b) of this section were added by Order
No. 888 in order to implement the post-1996 exemption for new
generation and to clarify the authority of state commissions
respectively. Order No. 652 later added subsection (c) to implement the
change in status reporting requirement.
197. This NOPR proposes to eliminate the post-1996 exemption, and
thus the proposed regulatory text deletes subsection (a). Subsection
(c) is proposed to move to subpart H section 35.43, and thus the
proposed text deletes section 35.27(c). This leaves only current
subsection (b) in 35.27. The proposed regulatory text does not revise
the language in any way and merely renumbers current subsection (b) to
reflect the absence of the other subsections.
198. With the changes proposed herein, the current section heading,
``Power Sales at Market-Based Rates,'' will no longer be pertinent. The
Commission proposes to amend the heading to ``Authority of State
Commissions'' to reflect the content of the remaining provision.
II. Section 35.36 Generally
199. This section is proposed to define certain terms specific to
Subpart H and to explain the applicability of Subpart H.\178\ Some of
these terms were put in place recently when the Commission codified
certain market behavior rules in Order No. 674.\179\ Subsection (a)(1)
explains that ``seller'' refers to a public utility with authority to,
or seeking authority to, engage in sales for resale of electric energy,
capacity or ancillary services at market-based rates to make clear that
Subpart H deals exclusively with market-based rate power and ancillary
services sales. The proposed regulations define Category 1 sellers and
Category 2 sellers to assist in understanding the parameters of the
updated market power analysis requirement. Subsection (a)(4) defines
inputs to electric power production in order to simplify section
35.37(e) regarding other barriers to entry. Subsection (a)(5) indicates
that where the term franchised public utility is used, it is meant to
include only those public utilities with a franchised service territory
that have captive customers. Last, subsection (a)(6) provides a
definition for non-regulated affiliated entities, which appears in
several places in the proposed regulations.
---------------------------------------------------------------------------
\178\ We note that we also proposed to change the title of
Subpart H from `Wholesale Sales of Electricity at Market-Based
Rates' to `Wholesale Sales of Electric Energy, Capacity and
Ancillary Services at Market-Based Rates.'
\179\ Conditions for Public Utility Market-Based Rate
Authorization Holders, Order No. 764, FERC Stats. & Regs.
31,208, 114 FERC ] 61,163 (2006).
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200. Subsection (b) is intended to leave room for certain
provisions that do not apply to a particular seller should the
Commission make a finding, for instance, that a franchised public
utility has no captive customers and hence section 35.39(b) is not
applicable.
201. We solicit comments on whether further or different language
than that proposed here should be incorporated in our regulations.
III. Section 35.37 Market Power Analysis Required
202. This section describes the market power analysis the
Commission employs, as discussed in the preamble, and when sellers must
file one. It is intended to identify the key aspects of the analysis
without providing too much detail. The Commission is cognizant that the
finer points of the market power analysis change over time as
individual orders consider new facts and as precedent shifts to follow
the evolution of the power industry; the proposed regulations should
not be so
[[Page 33128]]
detailed as to require revision from time to time to follow these
changes.
203. We solicit comments on the scope of the language that should
be incorporated in the regulations.
IV. Section 35.38 Mitigation
204. The NOPR raises questions concerning the current approach and
seeks comments regarding any changes the Commission should adopt. In
addition, we propose to characterize the informal term ``up to'' cost-
based rates as ``priced at no higher than a cost-based ceiling
reflecting the cost of the units expected to provide service.'' We seek
comments on whether further or different language than that proposed
here should be incorporated in our regulations.
V. Section 35.39 Affiliate Provisions
205. This section governs affiliate transactions and affiliate
relationships and establishes affiliate conditions that a seller must
satisfy as a condition of its market-based rate authority. Subsection
(a) includes a provision expressly prohibiting sales between a
franchised public utility and any of its non-regulated power sales
affiliates without first receiving authorization of the transaction
under section 205 of the FPA. This subsection requires that, where the
Commission grants a seller authority to engage in affiliate sales under
its MBR tariff, any and all such authorizations must be listed in the
seller's tariff. We seek comments on the proposal to include this
provision in the Commission's regulations.
206. Subsections (b)-(e) contain the market-based rate code of
conduct provisions governing the relationship between a franchised
public utility and its non-regulated power sales and power brokering
affiliates. The provisions of this subsection apply to all franchised
public utilities with captive customers. This subsection includes
provisions governing the separation of employees, the sharing of market
information, sales of non-power goods or services, and power brokering.
It proposes that, for purposes of applying the provisions of this
section, entities acting on behalf of and for the benefit of a
franchised public utility (such as service companies and entities
managing the generation assets of the franchised public utility) are
considered to be part of the franchised public utility, and entities
acting on behalf of and for the benefit of a non-regulated affiliate of
a franchised public utility (such as affiliated power marketers and
power producers and entities managing the generation assets of the
affiliated power marketers and producers) are considered to be part of
the non-regulated affiliates. This section is an integral part of the
Commission's conditions regarding affiliate abuse where captive
customers are concerned. We seek comments on the proposal to include
the affiliate provisions in the regulations.
VI. Section 35.40 Ancillary Services
207. This provision restricts sales of ancillary services to those
specific geographic markets for which the Commission has authorized
market-based rate sales of such. In addition, this section lays out the
limitations on third-party ancillary services sales provided in Avista
Corporation.\180\
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\180\ Avista Corporation, 87 FERC ] 61,223, order on reh'g, 89
FERC ] 61,136 (1999).
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VII. Section 35.41 Market Behavior Rules
208. Recently, the Commission rescinded two of its market behavior
rules and codified the remainder in section 35.37 of new Subpart H.
Also, in a Final Rule issued concurrently with this NOPR, the
Commission is revising the record retention period from three years to
five years. In this NOPR, we propose to move these market behavior
rules, unchanged, from Sec. 35.37 to Sec. 35.41.
VIII. Section 35.42 Market-Based Rate Tariff
209. This proposed provision imposes the requirement that each
seller (or its corporate parent) have on file with the Commission the
market-based rate tariff that is appended hereto at Appendix A.
IX. Section 35.43 Change in Status Reporting Requirement
210. This section incorporates the provision currently found at
subsection 35.27(c), which was codified by Order No. 652. No
modifications to the existing language are proposed. We seek comment on
whether any changes are warranted.
X. Information Collection Statement
211. The Office of Management and Budget (OMB) regulations require
approval of certain information collection and data retention
requirements imposed by agency rules.\181\ Upon approval of a
collection of information and data retention, OMB will assign an OMB
control number and an expiration date. Respondents subject to the
filing requirements of this 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. As discussed herein,
the Commission proposes amending its regulations to codify its
requirements for obtaining and retaining market-based rate
authorization, implementing a market-based rate tariff, and
incorporating the change in status reporting requirement for sellers
seeking market-based rate authority.
---------------------------------------------------------------------------
\181\ 5 CFR 1320.11 (2005).
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212. The Commission has previously required utilities seeking
market-based rate authority to file a market power analysis with the
Commission; the Commission now proposes to codify that requirement in
the Commission's regulations. This proposal reflects the Commission's
existing practice and will not impose any additional burden, with the
following exception.
213. Section 35.27(a) of the Commission's regulations currently
provides that any public utility seeking market-based rate authority
shall not be required to submit a generation market power analysis with
respect to sales from capacity for which construction commenced on or
after July 9, 1996. Under current procedures, if all the generation
owned or controlled by an applicant for market-based rate authority and
its affiliates in the relevant control area is post-July 9, 1996
generation, such applicant is not required to submit a generation
market power analysis. In this NOPR, the Commission proposes to
eliminate the express exemption provided in section 35.27(a). This
proposal would require that all new applicants seeking market-based
rate authority on or after the effective date of the final rule issued
in this proceeding, whether or not all of their and their affiliates'
generation was built or acquired after July 9, 1996, must provide a
market power analysis of their generation to support their application
for market-based rate authority. Because the Commission allows an
applicant to make simplifying assumptions, where appropriate, and
therefore to submit a streamlined analysis, any burden of document
preparation occasioned by the proposed elimination of section 35.27(a)
should be minimal. Moreover, any burden of document preparation caused
by the proposed elimination of section 35.27(a) should apply for the
most part only with regard to generation market power analyses required
to support an initial application for market-based rate authority.
214. The second filing requirement proposed in this NOPR is that
all market-based rate sellers file one market-based rate tariff per
corporate family. The MBR tariff proposed by the Commission is appended
to this NOPR. The proposed tariff, coupled with the proposed
regulations, will simplify the
[[Page 33129]]
content of MBR tariffs filed with the Commission and decrease the
burden of document preparation by providing a clearly defined statement
of the information sought by the Commission. Utilities will only be
required to fill in the company-specific information, which lessens the
burden of drafting documentation. A tariff of general applicability
will also give the Commission consistency on review and clarity
regarding the connections between parent and affiliate utilities in its
analysis. Although the requirement to file the specified MBR tariff may
cause a minimal burden of document preparation and organization for
existing market-based rate sellers, long-term benefits will be realized
for utilities as well as the Commission.
215. To retain market-based rate authority, the Commission
currently requires that sellers file a triennial review. In this NOPR,
the Commission proposes to codify the requirement that certain sellers
with market-based rate authority file a triennial review with the
Commission to retain that authority. However, the Commission proposes
that certain smaller utilities, Category 1 sellers, be relieved of
their existing duty to file the triennial review. Thus, larger sellers
will not face a greater burden to provide the Commission with the
information required for a triennial review, and the burden of
supplying the updated analysis may be eliminated for certain smaller
entities seeking to retain market-based rate authority.
216. The Commission's regulations, in 18 CFR part 35, specify those
reporting requirements that must be followed in conjunction with the
filing of rate schedules under the FPA. The information provided to the
Commission under part 35 is identified for information collection and
records retention purposes as FERC-516. Data collection FERC-516
applies to all reporting requirements covered in 18 CFR part 35
including: electric rate schedule filings, market power analyses,
tariff submissions, triennial reviews, and reporting requirements for
changes in status for public utilities with market-based rate
authority.
217. The Commission is submitting these reporting and records
retention requirements to OMB for its review and approval under section
3507(d) of the Paperwork Reduction Act.\182\ Comments are solicited on
the Commission's need for this information, whether the information
will have practical utility, the accuracy of provided burden estimates,
ways to enhance the quality, utility, and clarity of the information to
be collected, and any suggested methods for minimizing the respondent's
burden, including the use of automated information techniques.
---------------------------------------------------------------------------
\182\ 44 U.S.C. 3507(d) (2000).
---------------------------------------------------------------------------
Burden Estimate: The Public Reporting and records retention burden
for all four proposed reporting requirements and the records retention
requirement is as follows.\183\
---------------------------------------------------------------------------
\183\ These burden estimates apply only to this NOPR and do not
reflect upon all of FERC-516.
---------------------------------------------------------------------------
Title: Electric Rate Schedule Filings (FERC-516).\\ \\
Action: Revised Collection.\\
OMB Control No: 1902-0096.\\
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\184\ The number of respondents for market-based rate tariffs is
expected to be 650. The figure 217 represents 650 respondents, per
year, over the course of 3 years. Also, the 650 figure takes into
account that parent companies will file for their affiliates.
\185\ Category 1 Sellers are power marketers and power producers
that own or control 500 MW or less of generating capacity in
aggregate and that are not affiliated with a public utility with a
franchised service territory. In addition, Category 1 sellers must
not own or control transmission facilities, and must present no
other vertical market power issues. The zero in this section
represents that Category 1 Sellers are not responsible for filing
triennial updates.
\186\ Category 2 Sellers are any sellers not in Category 1.
\187\ To determine the number of responses, the number of
respondents (600) has been divided by 3 because the responses will
be submitted to the Commission on a staggered basis over the course
of a three year period.
----------------------------------------------------------------------------------------------------------------
Number of Number of Hours per Total annual
Data collection respondents responses response hours
----------------------------------------------------------------------------------------------------------------
Initial Market Power Analysis................... 120 120 130 15,600
Market-Based Rate Tariff........................ \184\ 650 217 6 3,900
Triennial Review Category 1 \185\............... 0 0 0 0
Triennial Review Category 2 \186\............... 600 \187\ 200 250 50,000
----------------------------------------------------------------------------------------------------------------
Total Annual hours for Collection: (Reporting + record retention,
(if appropriate) = hours.
Information Collection Costs: The total annual cost for Initial
Market Power Analysis is estimated to be $2,340,000. Total annual cost
for market-based rate tariffs is projected to be $195,300. Total annual
cost for Triennial Reviews Category 2 is projected to be $7,500,000.
The hourly rate of $150 includes attorney fees, engineering
consultation fees and administrative support. There are 2080 total work
hours in a year. There are no filing fees associated with applications
for market-based rate authority.
Respondents (Market Power Analysis; MBR Tariff; Triennial Review):
Businesses or other for profit.
Frequency of Responses: Market Power Analyses: Occasionally;
consistent with current practice, a market power analysis must be filed
for each utility seeking market-based rate authority.
MBR Tariff: An MBR tariff for each corporate family with all
current sellers to be filed with the Commission after the final rule is
effective. In the future, an MBR tariff will be filed occasionally by
each utility newly seeking market-based rate authority.
Triennial Review: Updated market power analysis filed every three
years for Category 2 sellers seeking to retain market-based rate
authority.\188\
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\188\ Certain smaller entities (Category 1 sellers) are proposed
to be exempted from this requirement.
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Necessity of the Information: Market Power Analyses: Consistent
with current practices, the market power analysis aids the Commission
in determining whether an entity seeking market-based rate authority
lacks market power and permits a determination that sales by that
entity will be just and reasonable.
MBR Tariff: A market-based rate tariff filed for each corporate
family, with all affiliates with market-based rate authority separately
identified in the tariff, would improve the efficiency of the
Commission in its analysis and determination of market-based rate
authority. The MBR Tariff would allow the Commission to have a clear
definition of the relationships between parent and affiliate utilities
in assessing market-based rate authority and/or the investigation
thereof. This will allow for better transparency with regard to what
sellers each corporate family has, and a more customer friendly tariff.
A tariff of general applicability will also reduce document preparation
time overall and provide utilities with the clearly defined
expectations of the Commission.
Triennial Review: The triennial review allows the Commission to
monitor market-based rate authority to
[[Page 33130]]
detect changes in market power or potential abuses of market power. The
updated market power analysis permits the Commission to determine that
continued market-based rate authority will still yield rates that are
just and reasonable.
Internal review: The Commission has conducted an internal review of
the public reporting burden associated with the collection of
information and assured itself, by means of internal review, that there
is specific, objective support for this information burden estimate.
Moreover, the Commission has reviewed the collections of information
proposed by this NOPR and has determined that these collections of
information are necessary and conform to the Commission's plans, as
described in this order, for the collection, efficient management, and
use of the required information.\189\
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\189\ See 44 U.S.C. 3506(c) (2004).
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Interested persons may obtain information on the reporting
requirements by contacting: Federal Energy Regulatory Commission, 888
First Street, NE., Washington, DC 20426 [Attention: Michael Miller,
Office of the Executive Director, Phone: (202) 502-8415, fax: (202)
273-0873, e-mail: [email protected]. Comments on the requirements
of the proposed rule may also be sent to the Office of Information and
Regulatory Affairs, Office of Management and Budget, Washington, DC
20503 [Attention: Desk Officer for the Federal Energy Regulatory
Commission].
XI. Environmental Analysis
218. 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.\190\ The
Commission has categorically excluded certain actions from this
requirement as not having a significant effect on the human
environment.\191\ The actions proposed here fall within the categorical
exclusions in the Commission's regulations for rules that are
clarifying, corrective, or procedural, or do not substantially change
the effect of legislation or regulations being amended.\192\ In
addition, the proposed rule is categorically excluded as an electric
rate filing submitted by a public utility under sections 205 and 206 of
the FPA.\193\ As explained above, this proposed rule addressing the
issue of electric rate filings submitted by public utilities for
market-based rate authority is clarifying in nature. Accordingly, no
environmental assessment is necessary and none has been prepared in
this NOPR.
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\190\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. &
Regs., Regulations Preambles July 1996-December 2000 ] 30,783
(1987).
\191\ 18 CFR 380.4 (2005).
\192\ See 18 CFR 380.4(a)(2)(ii).
\193\ See 18 CFR 380.4(a)(15).
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XII. Regulatory Flexibility Act Analysis
219. The Regulatory Flexibility Act of 1980 (RFA) \194\ generally
requires a description and analysis of rules that will have significant
economic impact on a substantial number of small entities.\195\ The
proposed rule will be applicable to all public utilities seeking and
currently possessing market-based rate authority. The Commission finds
that the regulations proposed here should not have a significant impact
on small businesses.
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\194\ 5 U.S.C. 601-12 (2000).
\195\ The RFA definition of ``small entity'' refers to the
definition provided in the Small Business Act, which defines a
``small business concern'' as a business that is independently owned
and operated and that is not dominant in its field of operation. 15
U.S.C. 632 (2000). 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 the generation, transmission, and/or distribution of
electric energy for sale and whose total electric output for the
preceding fiscal year did not exceed 4 million MWh. 13 CFR 121.201
(2004) (section 22, Utilities, North American Industry
Classification System, NAICS).
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220. The submission of a market power analysis is currently
required of all entities seeking authority to sell at market-based
rates, and the proposed rule does not alter which entities will be
required to file these analyses. The proposed rule does not create a
new reporting requirement. It does, however, propose to expand the
scope of the analysis that must be submitted for those entities that
previously were exempted from preparing a generation market power
analysis by virtue of 18 CFR 35.27(a). The Commission is concerned that
the continued use of the section 35.27(a) exemption, in time, would
encompass all market participants as all pre-July 9, 1996 generation is
retired. Nevertheless, because the Commission allows an applicant to
make simplifying assumptions, where appropriate, and therefore to
submit a streamlined analysis, the Commission believes that any
additional burden imposed by the proposed elimination of the section
35.27(a) exemption will be minimal. Thus, public utilities are
currently prepared to submit market power analyses and this requirement
does not pose a greater burden.
221. The proposed rule requires that each corporate family have on
file one MBR tariff of general applicability, with all affiliates with
market-based rate authority separately identified in the tariff.
Although this may initially increase the burden of document preparation
and organization for parent utilities, long-term benefits will be
realized that reduce burdens on utilities and the Commission. A tariff
of general applicability will decrease document preparation by
providing a clearly defined statement of the information sought by the
Commission. Moreover, a single tariff for each corporate family will
reduce the filing burden on utilities. Small entities affiliated with a
parent utility need not prepare a separate tariff; rather, they will
merely add their company name to their parent utility's tariff. Thus,
the burden is decreased.
222. The triennial review submissions that provide updated market
power analyses are required for the retention of market-based rate
authority. Category 2 utilities shall continue to submit this analysis,
which poses no greater burden than that already in place. However, the
proposed regulations would result in fewer filings with the Commission
than currently required for qualified smaller utilities' (Category 1)
retention of market-based rate authority. Those who do have to file are
able to use short cuts described above (i.e., simplifying assumptions).
Thus, the proposed rule would be less burdensome economically and
reduce the frequency of document preparation for market-based rate
authority retention for qualified smaller utilities.
XIII. Comment Procedures
223. The Commission invites interested persons to submit comments
on the matters and issues proposed in this notice to be adopted,
including any related matters or alternative proposals that commenters
may wish to discuss. Comments are due August 7, 2006. Reply comments
are due September 6, 2006. Comments and reply comments must refer to
Docket No. RM04-7-000, and must include the commenter's name, the
organization they represent, if applicable, and their address in their
comments. Comments and reply comments may be filed either in electronic
or paper format.
224. Comments and reply comments may be filed 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
commenters may attach additional files with supporting information in
certain
[[Page 33131]]
other file formats. Documents created electronically using word
processing software should be filed in the native application or print-
to-PDF format and not in a scanned format. This will enhance document
retrieval for both the Commission and the public. Attachments that
exist only in paper form may be scanned. Commenters filing
electronically should not make a paper filing. Service of rulemaking
comments is not required. Commenters that are not able to file comments
and reply 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.
225. All comments and reply 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.
Commenters on this proposal are not required to serve copies of their
comments and reply comments on other commenters.
XIV. Document Availability
226. 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.
227. 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 of this document in the docket
number field.
228. User assistance is available for eLibrary and the Commission's
Web site during normal business hours. For assistance, please contact
FERC Online Support at 1-866-208-3676 (toll free) or (202) 502-8222 (e-
mail at [email protected]), or the Public Reference Room at
(202) 502-8371, TTY (202) 502-8659 (e-mail at
[email protected]).
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.
By direction of the Commission.
Magalie R. Salas,
Secretary.
In consideration of the foregoing, the Commission proposes to amend
part 35, Chapter I, Title 18, Code of Federal Regulations, as follows:
1. The authority citation for part 35 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.
2. Section 35.27 is revised as follows:
Sec. 35.27 Authority of State Commissions.
Nothing in this part--
(a) Shall be construed as preempting or affecting any jurisdiction
a state commission or other state authority may have under applicable
state and federal law, or
(b) Limits the authority of a state commission in accordance with
state and federal law to establish:
(1) Competitive procedures for the acquisition of electric energy,
including demand-side management, purchased at wholesale, or
(2) Non-discriminatory fees for the distribution of such electric
energy to retail consumers for purposes established in accordance with
state law.
3. Subpart H is revised to read as follows:
Subpart H--Wholesale Sales of Electric Energy, Capacity and
Ancillary Services at Market-Based Rates
Sec.
35.36 Generally.
35.37 Market power analysis required.
35.38 Mitigation.
35.39 Affiliate restrictions.
35.40 Ancillary services.
35.41 Market behavior rules.
35.42 Market-based rate tariff.
35.43 Change in status reporting requirement.
Appendix A to Subpart H--Proposed Market-Based Rate Tariff
Sec. 35.36 Generally.
(a) For purposes of this subpart:
(1) Seller means any person that has authorization to or seeks
authorization to engage in sales for resale of electric energy at
market-based rates under section 205 of the Federal Power Act.
(2) Category 1 Sellers means wholesale power marketers and
wholesale power producers that own or control 500 MW or less of
generation; that do not own or control transmission facilities (or have
been granted waiver of the requirements of Order No. 888, FERC Stats. &
Regs. ] 31,036); that are not affiliated with anyone that owns or
controls transmission facilities; that are not affiliated with a public
utility with a franchised service territory; and that do not raise
other vertical market power issues.
(3) Category 2 Sellers means any Sellers not in Category 1.
(4) Inputs to electric power production means sites for development
of generation, fuel inputs such as coal facilities, and the
transportation or distribution of inputs to electric power production
such as gas storage, intrastate gas transportation and distribution
systems, and rail cars/barges for the transportation of coal.
(5) Franchised public utility means a public utility with a
franchised service obligation under state law and that has captive
customers.
(6) Non-regulated power sales affiliate means any non-traditional
power seller affiliate, including a power marketer, exempt wholesale
generator, qualifying facility or other power seller affiliate, whose
power sales are not regulated on a cost basis under the FPA.
(b) The provisions of this subpart apply to all sellers authorized,
or seeking authorization, to make sales for resale of electric energy,
capacity or ancillary services at market-based rates unless otherwise
ordered by the Commission.
Sec. 35.37 Market power analysis required.
(a) In addition to other requirements in subparts A and B, a Seller
must submit a market power analysis in the following circumstances:
when seeking market-based rate authority; for Category 2 Sellers, every
three years, according to the schedule contained in Order No. ----,
FERC Stats. & Regs. ] 31, ----; or any other time the Commission
directs a Seller to submit one. Failure to timely file an updated
market power analysis will constitute a violation of Seller's market-
based rate tariff.
(b) A market power analysis must address whether a Seller has
horizontal and vertical market power.
(c) There will be a rebuttable presumption that a Seller lacks
horizontal market power if it passes two indicative market power
screens: first, a pivotal supplier analysis based on the annual peak
demand of the relevant market and; second, a market share analysis
applied on a seasonal basis. There will be a rebuttable presumption
that a Seller possesses horizontal market power if it fails either
screen. A Seller that has horizontal market power, or that has not
rebutted a presumption of horizontal market power, is subject to
mitigation, as described in Sec. 35.38.
(d) To demonstrate a lack of vertical market power, a Seller that
owns, operates or controls transmission
[[Page 33132]]
facilities, or whose affiliates own, operate or control transmission
facilities, must have on file with the Commission an Open Access
Transmission Tariff, as described in Sec. 35.28.
(e) To demonstrate a lack of vertical market power in wholesale
energy markets through the affiliation, ownership or control of inputs
to electric power production, such as the transportation or
distribution of the inputs to electric power production, a Seller must
provide the following information: a description of its affiliation,
ownership or control of inputs to electric power production; a
description of its ownership or control of intra-state transportation
or distribution of inputs to electric power production; a description
of its ownership or control of any sites for new generation capacity
development; and a statement that it cannot erect barriers to entry in
the relevant markets.
Sec. 35.38 Mitigation.
(a) A Seller that has been found to have market power in generation
or that is presumed to have horizontal market power by virtue of
failing or foregoing the horizontal market power screens, as described
in Sec. 35.37(c), may adopt the default mitigation detailed in
paragraph (b) of this section or may propose mitigation tailored to its
own particular circumstances to eliminate its ability to exercise
market power.
(b) Default mitigation consists of three distinct products: (i)
sales of power of one week or less priced at the Seller's incremental
cost plus a 10 percent adder; (ii) sales of power of more than one week
but less than one year priced at no higher than a cost-based ceiling
reflecting the costs of the unit(s) expected to provide the service;
and (iii) new contracts filed for review under section 205 of the
Federal Power Act for sales of power for one year or more priced at a
rate not to exceed embedded cost of service.
Sec. 35.39 Affiliate restrictions.
(a) Restriction on affiliate sales of electric energy. As a
condition of obtaining and retaining market-based rate authority, no
wholesale sale of electric energy may be made between a public utility
Seller with a franchised service territory and a non-regulated power
sales affiliate without first receiving Commission authorization for
the transaction under section 205 of the Federal Power Act. Failure to
satisfy this condition will constitute a violation of the Seller's
market-based rate tariff. All authorizations to engage in affiliate
wholesale sales of electricity must be listed in a Seller's market-
based rate tariff.
(b) Separation of functions. (1) For the purpose of this
subsection, entities acting on behalf of and for the benefit of a
franchised public utility (such as entities managing the electrical
generation assets of the franchised public utility) are considered part
of the franchised public utility. Entities acting on behalf of and for
the benefit of a franchised public utility's non-regulated power sales
affiliates are considered part of the non-regulated affiliated
entities.
(2) To the maximum extent practical, the employees of a non-
regulated power sales affiliate will operate separately from the
employees of any affiliated franchised public utility.
(c) Information sharing. All market information shared between a
franchised public utility and a non-regulated power sales affiliate
will be disclosed simultaneously to the public. This includes, but is
not limited to, any communication concerning power or transmission
business, present or future, positive or negative, concrete or
potential. Shared employees in a support role are not bound by this
provision, but they may not serve as a conduit of information to non-
support personnel.
(d) Non-power goods or services. (1) Sales of any non-power goods
or services by a franchised public utility, including sales made to or
through its affiliated exempt wholesale generators or qualifying
facilities, to a non-regulated power sales affiliate will be at the
higher of cost or market price.
(2) Sales of any non-power goods or services by a non-regulated
power sales affiliate to an affiliated franchised public utility will
not be at a price above market.
(e) Other. (1) To the extent a non-regulated power sales affiliate
seeks to broker power for an affiliated franchised public utility:
(i) The non-regulated power sales affiliate must offer the
franchised public utility's power first;
(ii) The arrangement between the non-regulated power sales
affiliate and the franchised public utility must be non-exclusive; and
(iii) The non-regulated power sales affiliate may not accept any
fees in conjunction with any brokering services it performs for an
affiliated franchised public utility.
(2) To the extent a franchised public utility seeks to broker power
for a non-regulated power sales affiliate:
(i) The franchised public utility will be required to charge the
higher of its costs for the service or the market rate for such
services;
(ii) The franchised public utility will be required to market its
own power first, and simultaneously make public (on an electronic
bulletin board and/or the Internet) any market information shared with
its affiliate during the brokering; and
(iii) The franchised public utility will post on an electronic
bulletin board and/or the Internet the actual brokering charges
imposed.
Sec. 35.40 Ancillary services.
(a) If a Seller seeks authority to make sales of ancillary services
at market-based rates, it may offer such services provided the service
has been authorized by the Commission and only in specific geographic
markets as the Commission has authorized.
(b) If a Seller is authorized by the Commission to make sales of
ancillary services at market-based rates as a third-party ancillary
services provider:
(1) Seller shall establish an Internet-based site for providing
information regarding ancillary services transactions including, prior
to making transactions, postings of offers of services available and
offering prices; procedures under which all customers would request
service and make bids; postings of the actual transaction prices after
the transactions are consummated; and accepted and denied requests and
the reasons for denial. The site should conform to the applicable OASIS
Standards and Communications Protocols.
(2) [Reserved]
(c) Seller is not authorized to make sales of ancillary services at
market-based rates as a third-party ancillary services provider:
(1) To a regional transmission organization or an independent
system operator (other than those ancillary services that are subject
to Sec. 35.40(a)) that has no ability to self-supply ancillary
services but instead depends on third parties;
(2) When the underlying transmission service is on the transmission
system of a transmission provider with whom the Seller is affiliated;
or
(3) To a public utility who is purchasing ancillary services to
satisfy its own Open Access Transmission Tariff requirements to offer
ancillary services to its own transmission customers, unless Seller(s)
receives separate authorization by the Commission.
Sec. 35.41 Market behavior rules.
(a) Unit operation. Where a Seller participates in a Commission-
approved
[[Page 33133]]
organized market, Seller will operate and schedule generating
facilities, undertake maintenance, declare outages, and commit or
otherwise bid supply in a manner that complies with the Commission-
approved rules and regulations of the applicable power market. Seller
is not required to bid or supply electric energy or other electricity
products unless such requirement is a part of a separate Commission-
approved tariff or is a requirement applicable to Seller through
Seller's participation in a Commission-approved organized market.
(b) Communications. Seller will provide accurate and factual
information and not submit false or misleading information, or omit
material information, in any communication with the Commission,
Commission-approved market monitors, Commission-approved regional
transmission organizations, Commission-approved independent system
operators, or jurisdictional transmission providers, unless Seller
exercises due diligence to prevent such occurrences.
(c) Price reporting. To the extent Seller engages in reporting of
transactions to publishers of electric or natural gas price indices,
Seller shall provide accurate and factual information, and not
knowingly submit false or misleading information or omit material
information to any such publisher, by reporting its transactions in a
manner consistent with the procedures set forth in the Policy Statement
issued by the Commission in Docket No. PL03-3-000 and any
clarifications thereto. Unless Seller has previously provided the
Commission with a notification of its price reporting status, Seller
shall notify the Commission within 15 days of the effective date of
this regulation or within 15 days of the date it begins making
wholesale sales, whichever is earlier, whether it engages in such
reporting of its transactions. Seller must update the notification
within 15 days of any subsequent change in its transaction reporting
status. In addition, Seller shall adhere to such other standards and
requirements for price reporting as the Commission may order.
(d) Records retention. Seller shall retain, for a period of five
years, all data and information upon which it billed the prices it
charged for the electric energy or electric energy products it sold
pursuant to Seller's market-based rate tariff, and the prices it
reported for use in price indices.
Sec. 35.42 Market-based rate tariff.
(a) In addition to other requirements in subpart A, every public
utility that is authorized to sell electric energy at market-based
rates pursuant to section 205 of the Federal Power Act must have on
file with the Commission a tariff of general applicability. Such tariff
must be the market-based rate tariff contained in Order No. ----, FERC
Stats. & Regs. ] 31, ---- (Final Rule on Market-Based Rates for
Wholesale Sales of Electricity by Public Utilities).
(b) The market-based rate tariff contained in Order No. ----, FERC
Stats. & Regs. ] 31, ---- must be filed by Sellers who have been
granted market-based rate authority prior to the issuance of Order No.
--------, in accordance with Order No. --------, FERC Stats. & Regs. ]
31, ---- (Final Rule on Electronic Tariff Filing). A market-based rate
tariff must be filed by a Seller who is initially seeking market-based
rates at the time it applies for market-based rate authorization.
(c) Each corporate family will file a single market-based rate
tariff, with all affiliates with market-based rate authority separately
identified in the tariff.
Sec. 35.43 Change in status reporting requirement.
(a) As a condition of obtaining and retaining market-based rate
authority, a Seller must timely report to the Commission any change in
status that would reflect a departure from the characteristics the
Commission relied upon in granting market-based rate authority. A
change in status includes, but is not limited to, the following:
(1) Ownership or control of generation capacity that results in net
increases of 100 MW or more, or transmission facilities or inputs to
electric power production other than fuel supplies, or
(2) Affiliation with any entity not disclosed in the application
for market-based rate authority that owns, operates or controls
generation or transmission facilities or inputs to electric power
production, or affiliation with any entity that has a franchised
service area.
(b) Any change in status subject to paragraph (a) of this section
must be filed no later than 30 days after the change in status occurs.
Failure to timely file a change in status report constitutes a tariff
violation.
Appendix A to Subpart H--Proposed Market-Based Rate Tariff
Market-Based Rate Tariff
------------------------------------------------------------------------
Docket No. authorizing
Seller(s) under this tariff: market-based rates:
------------------------------------------------------------------------
ABC, Inc.................................. Docket No. ERXX-XXX-XXX.
XYZ, LLC.................................. Docket No. ERXX-XXX-XXX.
Etc....................................... etc.
------------------------------------------------------------------------
1. Availability: Electric energy, capacity and ancillary
services are available under this tariff for wholesale sales to
purchasers with whom seller has contracted. Not all services may be
available from all sellers listed. Seller shall comply with the
provisions of 18 CFR Part 35, Subpart H, as applicable, and with any
conditions the Commission imposes in its orders concerning seller's
market-based rate authority, including orders in which the
Commission authorizes seller to engage in affiliate sales under this
tariff or otherwise restricts or limits the seller's market-based
rate authority. Failure to comply with the applicable provisions of
18 CFR Part 35, Subpart H, and with any orders of the Commission
concerning seller's market-based rate authority, will constitute a
violation of this tariff.
2. Applicability: This tariff is applicable to all wholesale
sales of electric energy, capacity and ancillary services by seller.
3. Rates: All sales shall be made at rates established by
agreement between the purchaser and seller.
4. Other Terms and Conditions: All other terms and conditions
not listed herein shall be established by agreement between the
purchaser and seller.
5. Effective Date: This Rate Schedule is effective on the date
of compliance with the final rule on Electronic Tariff Filings,
Order No. ----, FERC Stats. & Regs. ] 31,----.
Docket No. Approving Affiliate Sales
Docket No. ERXX-XXX-XXX
Docket No. ERXX-XXX-XXX
Etc.
[ballot] Check if Not Applicable
Docket No. Imposing Restrictions on Market-Based Rate Authority
Docket No. ERXX-XXX-XXX
Docket No. ERXX-XXX-XXX
Etc.
[ballot] Check if Not Applicable
Note: The following Appendix will not appear in the Code of
Federal Regulations.
Appendix B--Schedule for Regional Triennial Review Process
All Category 2 sellers that own or control generation in the
California, Northwest, Southwest, Midwest, SPP, Southeast, PJM, New
York, and New England regions during the period specified below
(Qualification Period) will file updated market power analyses
within the filing period specified in the following schedule.
Triennial Reviews
[[Page 33134]]
should reflect the most recently available historical data from the
calendar year prior to the year of filing. The regions are depicted
in the map that follows. (Source: Federal Energy Regulatory
Commission, 2004 State of the Markets Report, staff report prepared
by the Office of Market Oversight & Investigations, June 2005.)
------------------------------------------------------------------------
Qualification
Region period Filing period
------------------------------------------------------------------------
PJM.......................... 2006 April 1-30, 2007.
New York..................... 2006 July 1-30, 2007.
New England.................. 2006 October 1-30, 2007.
Midwest...................... 2007 April 1-30, 2008.
SPP.......................... 2007 July 1-30, 2008.
Southeast.................... 2007 October 1-30, 2008.
California................... 2008 April 1-30, 2009.
Northwest.................... 2008 July 1-30, 2009.
Southwest.................... 2008 October 1-30, 2009.
PJM.......................... 2009 April 1-30, 2010.
New York..................... 2009 July 1-30, 2010.
New England.................. 2009 October 1-30, 2010.
Midwest...................... 2010 April 1-30, 2011.
SPP.......................... 2010 July 1-30, 2011.
Southeast.................... 2010 October 1-30, 2011.
California................... 2011 April 1-30, 2012.
Northwest.................... 2011 July 1-30, 2012.
Southwest.................... 2011 October 1-30, 2012.
------------------------------------------------------------------------
This review cycle will be repeated in subsequent years.
[GRAPHIC] [TIFF OMITTED] TP07JN06.000
Note: The following Appendix will not appear in the Code of
Federal Regulations.
Appendix C--Standard Screens Format
Amounts Listed Are for Illustrative Purposes Only
[Pivotal supplier analysis]
----------------------------------------------------------------------------------------------------------------
Row (MW) Reference
----------------------------------------------------------------------------------------------------------------
Supply:
Applicant's Installed Capacity...... A 19,500 Workpaper 1.
Applicant's Long-Term Firm Purchases B 500 Workpaper 6.
Applicant's Long-Term Firm Sales.... C (1,000) Workpaper 2.
Applicant's Imports (Limited by D 0 Workpaper 5.
Simultaneous Import Capability).
Non-Affiliate Local Installed E 8,000 Workpaper 1.
Capacity.
Non-Affiliate Long-Term Firm F 500 Workpaper 6.
Purchases.
[[Page 33135]]
Non-Affiliate Long-Term Firm Sales.. G (2,500) Workpaper 2.
Non-Affiliate Uncommitted Capacity H
Imports.
(Limited by Simultaneous Import I 3,500 Workpaper 5.
Capability).
Control Area Reserve Requirement.... J (2,160) Workpaper 3.
Amount of Line J Attributable to K (2,160) Workpaper 3.
Applicant, if any.
L
Total Uncommitted Supply (SUM M 9,840
A,B,C,D,E,F,G,I,J,Q).
N
Load: O
Control Area Annual Peak Load....... P 18,000 Workpaper 4.
Average Daily Peak Native Load in Q (16,500) Workpaper 4.
Peak Month.
Amount of Line Q Attributable to R (16,500) Workpaper 4.
Applicant, if any.
S
Wholesale Load (-SUM P,Q)........... T (1,500)
U
Net Uncommitted Supply (SUM M,T).... V 8,340
W
Applicant's Uncommitted Capacity X 340
(SUM A,B,C,K,R).
.................... PASS
----------------------------------------------------------------------------------------------------------------
Wholesale Market Share Analysis
[Amounts for Illustrative Purposes Only]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Row Q1 (MW) Q2 (MW) Q3 (MW) Q4 (MW) Reference
--------------------------------------------------------------------------------------------------------------------------------------------------------
Applicant's Installed Capacity...... A 19,500 19,500 19,500 19,500 Workpaper 1.
Applicant's Long-Term Firm Purchases B 500 500 500 500 Workpaper 6.
Applicant's Long-Term Firm Sales.... C (1,000) (1,000) (1,000) (1,000) Workpaper 2.
Applicant's Seasonal Average Planned D (4,000) (3,000) (800) (3,500) Workpaper 7.
Outages.
Applicant's Imports (Limited by E 0 0 0 0 Workpaper 5.
Simultaneous Import Capability).
Average Peak Native Load in the F (11,500) (10,000) (12,500) (11,500) Workpaper 8.
Season.
Amount of Line F Attributable to G (11,500) (10,000) (12,500) (11,500) Workpaper 8.
Applicant, if any.
Amount of Line F Attributable to H (0) (0) (0) (0) Workpaper 8.
Others, if any.
Control Area Reserve Requirement.... I (1,500) (1,320) (1,560) (1,500) Workpaper 3.
Amount of Line I Attributable to J (1,500) (1,320) (1,560) (1,500) Workpaper 3.
Applicant, if any.
Amount of Line I Attributable to K (0) (0) (0) (0) Workpaper 8.
Others, if any.
Non-Affiliate Local Installed L 8,000 8,000 8,000 8,000 Workpaper 1.
Capacity.
Non-Affiliate Long-Term Firm M 500 500 500 500 Workpaper 6.
Purchases.
Non-Affiliate Long-Term Firm Sales.. N (2,500) (2,500) (2,500) (2,500) Workpaper 2.
Non-Affiliate Local Seasonal Average O (800) (200) (300) (400) Workpaper 7.
Planned Outages.
Non-Affiliate Uncommitted Capacity P
Imports.
(Limited by Simultaneous Import Q 5,000 4,500 3,500 4,000 Workpaper 5.
Capability).
R
Total Competing Supply (SUM S 10,200 10,300 9,200 9,600
L,M,N,O,Q,H,K).
Applicant's Uncommitted Capacity T 2,000 4,680 4,140 2,500
(SUM A,B,C,D,E,G,J).
Total Seasonal Uncommitted U 12,200 14,980 13,340 12,100
Capacity (SUM S,T).
V
Applicant's Market Share (T/U)...... W 16.39% 31.24% 31.03% 20.66%
................ PASS FAIL FAIL FAIL
--------------------------------------------------------------------------------------------------------------------------------------------------------
[FR Doc. 06-4903 Filed 6-6-06; 8:45 am]
BILLING CODE 6717-01-P