[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]



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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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \43\ 16 U.S.C. 824d(a) (2000).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \46\ April 14 Order, 107 FERC ] 61,018 at P 208.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \56\ 18 U.S.C. 824d (c) (2000).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \57\ April 14 Order, 107 FERC ] 61,018 at P 187.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \58\ Id. at 187.
    \59\ Alliant Energy Corporate Services, Inc., 109 FERC ] 61,289 
at P 31 (2004).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \76\ July 8 Order, 108 FERC ] 61,026 at P 124.
---------------------------------------------------------------------------

    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?
---------------------------------------------------------------------------

    \77\ Critical Energy Infrastructure Information, Order No. 662, 
70 FR 37031 (June 28, 2005), FERC Stats. & Regs. ] 31,189 (June 21, 
2005).
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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).
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.'').
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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'').
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.'').
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \131\ See Florida Power Corp., 111 FERC ] 61,243 (2005), 
attached staff Audit Report at 6.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \134\ April 14 Order, 107 FERC ] 61,018 at P 147, 148 & n. 142, 
150 & n. 144.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
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    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).
---------------------------------------------------------------------------

    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:
---------------------------------------------------------------------------

    \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\]
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \167\ Id. at P 75.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \168\ Id. at P 47.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \172\ 87 FERC ] 61,223, order on reh'g, 89 FERC ] 61,136 (1999) 
(Avista).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \176\ The Commission reserves the right to require that such a 
report be filed at any time.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \180\ Avista Corporation, 87 FERC ] 61,223, order on reh'g, 89 
FERC ] 61,136 (1999).
---------------------------------------------------------------------------

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).
---------------------------------------------------------------------------

    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.\\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \188\ Certain smaller entities (Category 1 sellers) are proposed 
to be exempted from this requirement.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \189\ See 44 U.S.C. 3506(c) (2004).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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