[Federal Register Volume 65, Number 229 (Tuesday, November 28, 2000)]
[Rules and Regulations]
[Pages 70984-71020]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-29676]



[[Page 70983]]

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Part III





Department of Energy





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Federal Energy Regulatory Commission



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18 CFR Part 33



Revised Filing Requirements Under Part 33 of the Commission's 
Regulations; Final Rule

Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / 
Rules and Regulations

[[Page 70984]]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 33

[Docket No. RM98-4-000; Order No. 642]


Revised Filing Requirements Under Part 33 of the Commission's 
Regulations

Issued November 15, 2000.
AGENCY: Federal Energy Regulatory Commission DOE.

ACTION: Final rule.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is 
revising 18 CFR Part 33 to update the filing requirements for 
applications under part 33, including public utility mergers. The 
Commission expects that, by providing applicants more detailed guidance 
for preparing applications, the revised filing requirements will assist 
the Commission in determining whether applications under section 203 of 
the Federal Power Act are consistent with the public interest and will 
provide more certainty and expedition in the Commission's handling of 
such applications. This final Rule generally follows the approach of 
the NOPR. This Rule affirms the Commission's screening approach to 
mergers that may raise horizontal competitive concerns and sets forth 
specific filing requirements consistent with the Appendix A analysis 
set forth in the Merger Policy Statement. This Rule also establishes 
guidelines for vertical competitive analysis and accompanying filing 
requirements for mergers that may raise vertical market power concerns. 
The Rule streamlines filing requirements and reduces the information 
burden for mergers and other dispositions of jurisdictional facilities 
that raise no competitive concerns and eliminates certain filing 
requirements in part 33 that are outdated or no longer useful to the 
Commission in analyzing mergers and other dispositions of 
jurisdictional facilities.

EFFECTIVE DATE: This Final Rule will become effective January 29, 2001.

FOR FURTHER INFORMATION CONTACT:
Kimberly D. Bose (Legal Matters), Office of the General Counsel--
Markets, Tariffs and Rates, Federal Energy Regulatory Commission, 888 
First Street, N.E., Washington, DC 20426, Telephone: (202) 208-0019
Diana Moss (Technical Matters), Office of Markets, Tariffs and Rates, 
Federal Energy Regulatory Commission, 888 First Street, N.E., 
Washington, DC 20426, Telephone: (202) 208-0019
James Turnure (Technical Matters), Office of Strategic Direction, 
Federal Energy Regulatory Commission, 888 First Street, N.E., 
Washington, DC 20426, Telephone: (202) 208-5364
Daniel Hedberg (Technical Matters), Office of Markets, Tariffs and 
Rates, Federal Energy Regulatory Commission, 888 First Street, N.E., 
Washington, DC 20426, Telephone: (202) 208-0243
Steve Rodgers (Technical Matters), Office of Markets, Tariffs and 
Rates, Federal Energy Regulatory Commission, 888 First Street, N.E., 
Washington, DC 20426, Telephone: (202) 208-1247

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Introduction and Summary
II. Background
III. Discussion
    A. Revisions to Part 33--Basic Information Requirements
    B. Revised Filing Requirements Applicable to Merger Filings
    1. Applicability
    2. Data and format
IV. Effect on Competition
V. Horizontal Screen Analysis
    A. Relevant Products
    B. Relevant Geographic Markets
    C. Suppliers (Delivered Price Test)
    D. Transmission capability
    E. Historical data
    F. Concentration Statistics and Related Matters
    G. Mitigation Measures and Analysis of Other Factors
    H. Merger applications that are exempt from filing a competitive 
screen
VI. Guidelines for Vertical Competitive Analysis
    A. General Vertical Issues
    B. Vertical Analytic Guidelines--Introduction
    C. Merger Applications That are Exempt From Filing a Full 
Vertical Analysis
    D. Components of the Analysis as Proposed in the NOPR
    E. Mitigation Measures and Analysis of Other Factors as Proposed 
in the NOPR--Introduction
    F. Remedy--Concerning Vertical Mergers
VII. Effect on Rates--Revised Requirements for Ratepayer Protections
VIII. Effect on Regulation--Revised Requirements Concerning the 
Impact on State and Commission Regulatory Jurisdiction
IX. Emerging Issues
    A. Computer-Based Simulation Models
    B. Retail Competition, Restructuring, and Other Newly Emerging 
Competitive Issues Raised by Section 203 Transactions
    C. Moratorium on Mergers
X. Regulatory Flexibility Act
XI. Environmental Statement
XII. Information Collection Statement
XIII. Document Availability
XIV. Effective Date and Congressional Notification

Appendix--List of Commenters

I. Introduction and Summary

    In 1996, the Commission issued the Merger Policy Statement (Policy 
Statement) updating and clarifying the Commission's procedures, 
criteria and policies concerning public utility mergers in light of 
dramatic and continuing changes in the electric power industry and the 
regulation of that industry.\1\ The purpose of the Policy Statement was 
to ensure that mergers are consistent with the public interest and to 
provide greater certainty and expedition in the Commission's analysis 
of merger applications. Therefore, we stated in the Policy Statement 
that we would issue a notice of proposed rulemaking to set forth more 
specific filing requirements consistent with the Policy Statement and 
additional procedures for improving the merger hearing process.\2\
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    \1\ Inquiry Concerning the Commission's Merger Policy Under the 
Federal Power Act: Policy Statement, Order No. 592, 61 Fed. Reg. 
68,595 (1996), FERC Statutes and Regulations para. 31,044 (1996), 
reconsideration denied, Order No. 592-A, 62 Fed. Reg. 33,34 (1997), 
79 FERC para. 61,321 (1997) (Policy Statement).
    \2\ Policy Statement at p. 30,111 n.3.
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    Following the issuance of the Policy Statement, applications filed 
pursuant to section 203 of the Federal Power Act (FPA) \3\ have varied 
widely in the quantity and quality of information they have included, 
particularly with respect to market analyses and the supporting data. 
Thus, on April 16, 1998, the Commission issued a notice of proposed 
rulemaking in this docket \4\ to revise 18 CFR part 33 by specifying 
clear and succinct filing requirements for all applications submitted 
pursuant to section 203 of the FPA (including non-merger transactions). 
In this NOPR, the Commission analyzed information that is needed to 
evaluate section 203 applications to determine how the filing 
requirements under part 33 could be made more helpful to the electric 
industry, intervenors and businesses operating in the emerging 
competitive landscape. The proposed revised filing requirements were 
intended to provide greater certainty about what needed to be filed in 
section 203 applications. This would allow applicants to prepare their 
proposals more quickly and efficiently and to better predict the 
outcome of the Commission's evaluation. The proposed requirements

[[Page 70985]]

would also facilitate intervenors' evaluations of section 203 
applications and provide for a more timely and accurate section 203 
decision-making process by the Commission. An additional goal of the 
NOPR was to lessen regulatory burdens on the industry by eliminating 
outdated and unnecessary filing requirements and streamlining the 
filing requirements for mergers that clearly do not raise competitive 
concerns.
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    \3\ 16 U.S.C. 824b.
    \4\ Revised Filing Requirements Under Part 33 of the 
Commission's Regulations, Notice of Proposed Rulemaking, 63 Fed. 
Reg. 20340 (1998), FERC Statutes and Regulations para. 32,258 (1998) 
(NOPR).
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    Based on careful consideration of the comments submitted in 
response to the NOPR,\5\ the Commission now adopts a Final Rule that 
amends Part 33 of the Commission's regulations. This Final Rule 
generally follows the approach of the NOPR. Specifically, in this Rule 
we are: (1) Affirming the Commission's screening approach to mergers 
that may raise horizontal competitive concerns and setting forth 
specific filing requirements consistent with the Policy Statement's 
Appendix A analysis; \6\ (2) setting forth guidelines for vertical 
competitive analysis and accompanying filing requirements for mergers 
that may raise vertical market power concerns; (3) streamlining filing 
requirements and reducing the information burden for mergers and other 
dispositions of jurisdictional facilities that raise no competitive 
concerns; and (4) eliminating certain filing requirements in Part 33 
that are outdated or no longer useful to the Commission in analyzing 
mergers and other dispositions of jurisdictional facilities. The Final 
Rule also addresses the use of computer simulation models. As discussed 
further below, there is currently no consensus as to which model(s) to 
use, and there are many issues that must be addressed before the 
Commission is able to determine the appropriateness of any particular 
model. Therefore, we believe that a technical conference is needed. The 
Final Rule also reorganizes part 33 so that users of the regulations 
can quickly find requirements that apply to the section 203 
transactions in which they are interested.
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    \5\ The commenters, and abbreviations for them as used herein, 
are listed in the Appendix attached to this Final Rule.
    \6\ Policy Statement at p. 30,128.
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    Following the Background and general Discussion sections below 
(Sections II and III), this preamble sets forth requirements for the 
competitive analysis screen for horizontal mergers, followed by the 
guidelines for vertical competitive analysis. The preamble then 
discusses effects on rates and regulation and a number of emerging 
issues, including computer models, as noted above.

II. Background

    Pursuant to section 203, Commission authorization is required for 
public utility mergers and consolidations and for public utility 
acquisitions or dispositions of jurisdictional facilities. Section 
203(a) of the FPA provides that:

    No public utility shall sell, lease or otherwise dispose of the 
whole of its facilities subject to the jurisdiction of the 
Commission, or any part thereof of a value in excess of $50,000, or 
by any means whatsoever, directly or indirectly, merge or 
consolidate such facilities or any part thereof with those of any 
other person, or purchase, acquire, or take any security of any 
other public utility, without first having secured an order of the 
Commission authorizing it to do so.

    Transactions covered by this provision will be referred to as 
``section 203 transactions.'' Section 203 provides that the Commission 
shall approve such transactions if they are consistent with the public 
interest.
    The Policy Statement set out three factors (revising the 30-year-
old criteria that evaluated mergers using six factors) the Commission 
considers when analyzing a merger proposal: Effect on competition; 
effect on rates; and effect on regulation.\7\ With respect to the 
effect on competition, the Policy Statement adopted the Department of 
Justice (DOJ)/Federal Trade Commission (FTC) 1992 Horizontal Merger 
Guidelines (Guidelines) \8\ as the analytical framework for examining 
horizontal market power concerns. The Policy Statement also adopted an 
analytical screen (the Appendix A analysis) that is intended to allow 
early identification of mergers that clearly do not raise competitive 
concerns. The Commission believes that the screen produces a reliable, 
generally conservative analysis of the horizontal competitive effects 
of a proposed merger. As part of the screen analysis, the Policy 
Statement requires generally that the applicants define product and 
geographic markets that are likely to be affected by the proposed 
merger and measure the concentration in those markets. The Policy 
Statement suggests a way of defining geographic markets based on 
identifying alternative competitive suppliers to the merged firm--the 
delivered price test. The concentration of potential suppliers included 
in the market is then measured by the Herfindahl-Hirschman Index (HHI) 
and used as an indicator of the potential for market power.
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    \7\ Although we apply these factors to other section 203 
transactions as well, the filing requirements and the level of 
detail required may differ.
    \8\ U.S. Department of Justice and Federal Trade Commission, 
Horizontal Merger Guidelines, 57 FR 41,552 (1992), revised, 4 Trade 
Reg. Rep. (CCH) para. 13,104 (Apr. 8, 1997).
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    In its Policy Statement, the Commission said that it will examine 
the second factor, the effect on rates, by focusing on ratepayer 
protections designed to insulate consumers from any harm resulting from 
the merger. Applicants were directed to attempt to negotiate such 
measures with their customers before filing merger applications.
    Finally, the Policy Statement set forth a third factor for 
examination, the effect on regulation, both state regulation and any 
potential shift in regulation from the Commission to the Securities and 
Exchange Commission (SEC), the latter as the result of a merger 
creating a registered public utility holding company. With respect to a 
merger's effect on state regulation, where the state commissions have 
authority to act on the merger, the Commission stated that it intends 
to rely on them to exercise their authority to protect state interests. 
With respect to shifts of regulatory authority from this Commission to 
the SEC, the Policy Statement explained that, unless applicants commit 
themselves to abide by this Commission's policies with regard to 
affiliate transactions, we will set the issue of the effect on 
regulation for hearing.\9\
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    \9\ See Atlantic City Electric Company and Delmarva Power & 
Light Company, 80 FERC para. 61,126 at 61,412, order denying reh'g, 
81 FERC para. 61,173 (1997) (Atlantic City/Delmarva).
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    Since the issuance of the Policy Statement and the NOPR, the 
Commission has gained valuable experience evaluating various types of 
mergers and other section 203 transactions. Some of these were mergers 
of interconnected, adjacent, vertically-integrated electric companies. 
Others involved utilities that were geographically separated and not 
physically interconnected. Yet others involved mergers of electric 
companies with natural gas companies and acquisitions of jurisdictional 
utilities by foreign firms.
    The Commission has devoted substantial resources to considering 
whether proposed mergers would significantly increase horizontal or 
vertical market power, thereby raising competitive concerns. Based on 
experience in reviewing the issues related to competition presented by 
these mergers, the Commission, in various merger orders, has provided 
further clarification of the Appendix A analysis set out in the Policy 
Statement and guidance for evaluating the

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competitive effects of proposed vertical mergers.\10\
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    \10\ See, e.g., Enova Corporation and Pacific Enterprises, 79 
FERC para. 61,372 (1997) (Enova) and Dominion Resources, Inc. and 
Consolidated Natural Gas Company, 89 FERC para. 61,162 (1999) 
(Dominion/CNG).
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    As a result of these efforts, the Commission has been able to act 
more expeditiously and to provide a more predictable decisionmaking 
process for the more than 50 merger cases filed since the issuance of 
the Policy Statement. For all merger applications submitted in the past 
year, the Commission has issued an initial order within the 150-day 
target announced in the Policy Statement. Since the issuance of the 
Policy Statement, the average processing time for merger applications 
has been 117 days. The Commission has been able to act expeditiously on 
merger proposals where applicants submitted concise, accurate 
information that demonstrated that the proposed merger was consistent 
with the public interest, pursuant to the guidance provided in the 
Policy Statement.
    Based on our experience and the comments we have received, we are 
now revising our merger filing requirements to enable applicants and 
intervenors to more effectively and predictably address the types of 
issues that have arisen in the applications filed since the issuance of 
the Policy Statement, as well as issues that will undoubtedly arise as 
the industry continues to make the transition to a more competitive 
marketplace. Below, we set forth revised filing requirements that are 
consistent with the Policy Statement. We also update and streamline 
certain areas of our current filing requirements so as to expedite and 
better focus applications and our review processes.
    In the NOPR, we raised a set of emerging issues resulting from the 
changes occurring in the energy industry that could affect mergers and 
other section 203 transactions. In this Final Rule, we address the 
emerging issues raised in the NOPR and by commenters. For example, we 
note the potential for computer-based simulation models to assist us in 
our analysis of merger applications. We also address retail competition 
and restructuring actions, including RTO development and other emerging 
competitive issues raised by mergers and other section 203 
transactions. Programs such as retail access, market-based rates for 
generation-based products, and product line diversification by 
integrated energy companies could affect our analysis of section 203 
applications. This Final Rule explains that these types of initiatives 
may require that applicants file additional information so the 
Commission and intervenors may accurately analyze the potential effects 
of section 203 transactions. Finally, we also look at the request of 
some commenters that the Commission impose a moratorium on mergers. As 
we explain in more detail below, we decline to do so.

III. Discussion

A. Revisions to Part 33--Basic Information Requirements

    In the NOPR, the Commission explained that a portion of the basic 
information that has historically been required for all section 203 
applications is no longer needed for those applications that involve 
routine dispositions of jurisdictional facilities, and accordingly, we 
proposed eliminating certain filing requirements. Due to the increasing 
complexity of the section 203 applications being filed, the NOPR also 
proposed to eliminate Sec. 33.10, which set forth the 45-day time frame 
for Commission action. However, we affirmed our intention to process 
section 203 applications as expeditiously as practicable, with a stated 
goal of issuing an initial order for most mergers within 150 days of a 
completed application.\11\
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    \11\ Id., n. 12.
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    The NOPR also proposed to reorganize and clarify certain 
regulations under part 33. The NOPR explained that the goal of these 
measures is to streamline and clarify our filing requirements, make our 
processing of section 203 applications more efficient and timely, and 
provide greater certainty regarding the Commission's probable action on 
applications.
    Part 33 currently contains twelve basic information requirements 
(Sec. 33.2(a) through (l)) and nine exhibits (Sec. 33.3 Exhibits A 
through I) that an applicant must file. Some of these requirements 
overlap. For example, Secs. 33.2(i) and 33.3 Exhibit G both concern 
applications filed with state commissions. Therefore, the NOPR proposed 
to consolidate these sections into Sec. 33.2(i). Other information 
requirements are no longer relevant to our review of applications filed 
under this part. An example is Sec. 33.3, Exhibit A, which concerns 
resolutions by applicants' directors authorizing the transaction for 
which Commission approval is requested. In the NOPR, we stated that 
this information is not necessary to determine whether a transaction is 
consistent with the public interest.
    The current Secs. 33.2(g) and 33.3, Exhibits C, D, E and F, relate 
to financial statements and account balances. Because a number of 
public utilities are exempt from the record-keeping requirements of the 
Commission's Uniform System of Accounts, the NOPR proposed that we 
impose our accounting requirements only on those applications that 
result in accounting revisions under the Commission's Uniform System of 
Accounts.
    Further, the NOPR proposed to eliminate Sec. 33.10, which stated 
that the Commission will ``ordinarily'' act within 45 days on section 
203 applications.\12\ In addition, the NOPR proposed revising 
Sec. 33.6, which would incorporate the requirement of the current 
Sec. 33.2(l) to file a form of notice and would require submission of 
the notice in electronic format. With minor modifications, we set forth 
the following revisions to the basic information requirements proposed 
in the NOPR.\13\
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    \12\ Although we are eliminating this section of our Part 33 
regulations, the Commission intends to continue to process section 
203 applications as expeditiously as practicable. As stated in the 
Policy Statement, the Commission continues to believe that, for 
example, we can issue an initial order for most mergrs within 150 
days of receiving a completed application.
    \13\ In this preamble, we will not note all the sections that 
are not revised. However, these sections are set forth in the 
attached regulatory text.
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    No revision will be implemented to proposed Sec. 33.1--
Applicability.
    No change was proposed to Sec. 33.2(b)--Authorized representative--
except that the phone and fax numbers of the person authorized to 
receive communications regarding the application, which have been 
voluntarily provided by nearly all applicants, are required, as are E-
mail addresses.
    Proposed Sec. 33.2(c)--Description of the applicant--incorporates 
the requirements of current Secs. 33.2(c) and (k) and Exhibit B and 
requires a description of each applicant's business activities, 
corporate affiliations, officers in common with other parties to the 
transaction, and jurisdictional customers. As discussed later, this 
section also requires applicants to provide information about RTO 
membership. Information on corporate affiliations must include a 
complete list of energy affiliates and subsidiaries, percentage 
ownership interests in such affiliates, and a description of the 
primary business in which each energy affiliate is engaged. An energy 
affiliate includes those companies which provide electric products or 
inputs to electric products. This section also

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requires that organizational charts be filed.
    Proposed Sec. 33.2(d)--Description of the jurisdictional 
facilities--requires a general description of each applicant's 
jurisdictional facilities.
    Proposed Sec. 33.2(e)--Description of the proposed transaction--
incorporates the old Secs. 33.2(d), (e), (f) and (h), requiring a 
description of the proposed transaction for which Commission 
authorization is sought, including all parties to the transaction, the 
jurisdictional facilities involved or affected by the transaction, the 
type of consideration for the transaction,\14\ and the effect of the 
transaction on each applicant's jurisdictional facilities and 
securities, including transfers of operational control and securities.
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    \14\ Policy Statement at pp. 30,125-26 (we no longer consider 
the reasonableness of purchase price as a factor; rather, it is 
subsumed within the effect on rates factor). This information is 
used for purchase accounting purposes.
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    Proposed Sec. 33.2(f)--Contracts related to the proposed 
transaction--incorporates the requirements of the old Exhibit H.
    Proposed Sec. 33.2(g)--The applicant's public interest statement--
includes the requirement that each applicant address the three factors 
the Commission considers in determining whether a transaction is 
consistent with the public interest, as set forth in the Policy 
Statement.
    Proposed Sec. 33.2(h)--Maps--incorporates the requirements of the 
old Exhibit I and is applicable if the proposed transaction involves a 
disposition of physical facilities and to merger applications.
    Proposed Sec. 33.2(i)--Other regulatory approvals--incorporates the 
requirements of the old Sec. 33.2(i) and Exhibit G. In addition, copies 
of relevant orders, if any, obtained by each applicant from other 
regulatory bodies are required. If the regulatory bodies issue orders 
pertaining to the proposed transaction after the date of filing with 
the Commission, and before the date of final Commission action, the 
applicant must supplement its application promptly with a copy of these 
orders.\15\ However, Sec. 33.2(i) eliminates a requirement that copies 
of the applications filed with those bodies be filed with the 
Commission, as this information largely duplicates the information 
required in the Part 33 regulations.
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    \15\ Supplementing the application with orders from other 
regulatory bodies will not normally delay the processing of an 
application.
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    Proposed Sec. 33.8--Number of copies--includes the information 
required in the old Sec. 33.6. This section now requires eight copies 
instead of five, sets out copy requirements for information filed with 
a request for privileged treatment and also requires that each 
applicant file electronic as well as paper copies of any competitive 
analysis screen filed pursuant to Secs. 33.3 and 33.4.
    Proposed Sec. 33.9--Protective orders--requires each applicant to 
include a proposed protective order if it seeks privileged treatment 
for any information submitted. The protective order enables the parties 
to review any of the data, information, analysis or other documentation 
relied upon by the applicant to support its application and for which 
privileged treatment is sought.
Comments
    In general, commenters support the NOPR's goals to streamline and 
clarify our basic information filing requirements. Commenters subscribe 
to the need for a clear regulatory merger policy and an efficient 
process that provides a degree of certainty about how the Commission 
will review merger applications, and assures that mergers are 
consistent with the public interest. Commenters generally commend the 
Commission's efforts, and support or do not oppose the proposed 
revisions to current Secs. 33.1, 33.2 and 33.3. Specifically, the 
Midwest ISO Participants and Gridco Commenters support the Commission's 
efforts to streamline and simplify the requirements when no 
competitive, rate, or regulatory-impairment issues exist.
    With respect to the NOPR's proposal to eliminate the 45-day time 
frame for Commission action, however, Southern contends that 
lengthening the process moves in the wrong direction, since other 
agencies have managed to keep pace despite having received increasing 
merger applications. Although Southern did not propose a specific 
alternative time frame, it did propose that the Commission continue its 
reform aimed at accelerating section 203 review.
Commission Conclusion
    Upon review of the comments submitted, the Commission adopts the 
revised filing requirements set forth in the NOPR regarding basic 
information, with minor modifications. We are eliminating the 45-day 
time frame for Commission action, which is not a requirement under the 
statute, because it is no longer feasible. While old Sec. 33.10 stated 
that the Commission will ordinarily need 45 days in which to act on 
merger applications, most merger applications filed today raise 
numerous complex issues that require more time for analysis and public 
comment. However, the Commission remains committed to the goal of 
issuing an initial order within 150 days of receiving a completed 
application. Indeed, since the Policy Statement, the average processing 
time for merger applications has been 117 days. Furthermore, we are 
typically processing uncontested non-merger applications within 60 days 
of filing and are typically processing protested non-merger 
applications within 90 days of filing, on average. We intend to 
continue this practice.
    Also, the Exhibit H filing requirements are now reflected in new 
Sec. 33.2(f). Although we are not revising these filing requirements, 
we take this opportunity to clarify that all section 203 filings must 
include a copy of all contracts pertaining to the proposed disposition 
and/or such other agreements (in final or, if not available, in draft 
form) and must identify: (1) All relevant parties to the transaction 
and their roles in the transaction (e.g., as seller, purchaser, lessor, 
lessee, operator); (2) the jurisdictional facilities that are being 
disposed of and/or acquired, directly or indirectly; and (3) all terms 
and conditions of the proposed disposition that pertain to the 
ownership, leasing, control of, or operation of jurisdictional 
facilities. If contracts pertaining to the section 203 disposition have 
not been finalized at the time of filing, or, in the case of intra-
corporate transactions, if applicants claim there will be no contracts 
associated with the disposition, applicants may submit a draft 
contract, a term sheet, a letter of intent or a memorandum of 
understanding to satisfy the Sec. 33.2(f) filing requirement. However, 
in such instances, we will require that in the transmittal letter 
accompanying the application, counsel for applicants certify that, to 
the best of their knowledge, the final agreements will reflect the 
terms and conditions contained in the draft agreements in all material 
respects.
    In response to comments, such as those expressed by FTC Staff, that 
the Commission should expand its data requirements, the Final Rule 
modifies Sec. 33.2(c)--description of the applicant--to require a 
description of the applicant's business activities, corporate 
affiliations, officers in common with other parties associated with the 
transactions either directly or indirectly,\16\ and jurisdictional 
transactions. Also, pursuant to Sec. 33.2(c)(3), we will now require 
that organizational charts be filed showing

[[Page 70988]]

the position within the corporate structure of each applicant in its 
corporate family, including all parent companies and all energy 
affiliates and subsidiaries (those companies which provide electric 
products or inputs to electric products). In Sec. 33.2(c)(2) we will 
require applicants to list all energy subsidiaries and energy 
affiliates, percentage ownership interest in such subsidiaries and 
affiliates, and a description of the primary business in which each 
energy subsidiary and energy affiliate is engaged.
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    \16\ This information is needed so that we can determine the 
existence of interlocking directorates.
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    Revised Sec. 33.2(c)(4) now requires each applicant to provide a 
description of all joint ventures, strategic alliances, tolling 
arrangements \17\ or other business arrangements. In light of Order No. 
2000, this section also requires a description of transfers of 
operational control of transmission facilities to Commission approved 
Regional Transmission Organizations, both current, and planned to occur 
within a year from the date of filing.
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    \17\ For example, under a tolling arrangement, a gas supplier 
would receive the output of a gas-fired generator as payment for the 
gas it supplies to the generator. If the gas supplier is the only 
supplier to that generator, then the gas supplier could effectively 
control the generator.
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    We recognize that not all applications require the same amount of 
information (regarding applicants' organizational structure and 
business arrangements and activities, for example) to allow the 
Commission to evaluate whether the transaction is consistent with the 
public interest. Applicants may request waiver of specific sections 
accompanied by support for why they believe we do not need such 
information. For example, as to the requirement of revised 
Sec. 33.2(c)(3) to provide organizational charts, an applicant can seek 
waiver of this requirement based upon a demonstration that the proposed 
transaction does not affect the corporate structure of any party to the 
transaction.
    The Final Rule also modifies revised Sec. 33.6--Form of notice--to 
require that the form of notice be filed in a specified format, or 
template (as set forth in this section), to simplify this 
responsibility of applicants. Finally, the Rule revises Sec. 33.8 to 
require applicants to submit eight copies of their application (instead 
of the five proposed in the NOPR) to aid our processing of 
applications.
    With regard to the proper notice period for section 203 filings, in 
the Merger Policy Statement the Commission stated that it would 
routinely provide for a 60-day comment period for merger filings to 
allow potential intervenors sufficient time to analyze the filing.\18\ 
The Commission has generally noticed section 203 filings other than 
mergers for considerably less time than 60 days. However, our 
experience with section 203 filings since the issuance of the Merger 
Policy Statement indicates that our policy on noticing should be 
altered somewhat. First, we have found that merger applications that do 
not require the filing of a competitive analysis screen (as provided in 
Sec. 33.3) or a vertical competitive analysis (as provided in 
Sec. 33.4) are generally not as complex (and thus not as difficult to 
analyze) as other section 203 filings, and thus a notice period of less 
than 60 days is adequate. Second, we have found that some section 203 
filings that do not involve mergers are of such significance and 
complexity that either a competitive analysis screen or a vertical 
competitive analysis is nevertheless required, and that a 60-day 
comment period is appropriate to allow potential intervenors adequate 
time to analyze these applications. Thus, we have found that the 
primary determinant for a longer notice period (i.e., 60 days) is not 
whether the filing is a merger, but whether the filing contains a 
competitive analysis screen or a vertical competitive analysis. Thus, 
we revise our policy on noticing section 203 filings to provide that 
any such filings containing either a competitive analysis screen or a 
vertical competitive analysis will generally be noticed for 60 days, 
while all other filings (including mergers not requiring a competitive 
analysis screen or a vertical competitive analysis) will generally be 
noticed for less than 60 days.
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    \18\ Policy Statement at p. 30,119.
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B. Revised Filing Requirements Applicable to Merger Filings

1. Applicability
    As we explained in the preamble of the NOPR, the following filing 
requirements (codified in the revised Secs. 33.3 and 33.4) apply to 
corporate transactions in which the applicant proposes either to: (a) 
Transfer control of jurisdictional facilities to another entity, 
whether the transfer of control is effectuated, directly or indirectly, 
by merger, consolidation or other means; or (b) acquire control over 
the jurisdictional facilities of another entity, whether the transfer 
of control is effectuated, directly or indirectly, by merger, 
consolidation or other means.\19\ For any such corporate transaction 
that results in a single entity obtaining ownership or control, 
directly or indirectly, over generating facilities of unaffiliated 
parties, the applicant must file certain additional information, 
described below. If the merger transaction involves a horizontal 
combination of facilities that results in a single corporate entity 
obtaining ownership or control over generating facilities of 
unaffiliated parties, the applicant must file the information set forth 
in Sec. 33.3. If the merger transaction involves a vertical combination 
of facilities resulting in a single corporate entity obtaining 
ownership or control over previously unaffiliated businesses that 
provide electricity products, or inputs to electricity products, the 
applicant must file the information set forth in Sec. 33.4.\20\
---------------------------------------------------------------------------

    \19\ Policy Statement, p. 30,113. See also, Duke Power Company 
and PanEnergy Corporation, 79 FERC para. 61,236 (1997) (Duke); NorAm 
Energy Services, Inc., 80 FERC para. 61,120 at 61,379 and n.13 
(1997) (NorAm); Morgan Stanley Capital Group Inc., et al., 79 FERC 
para. 61,109 at 61,503-04 (1997) (Morgan Stanley); and Boston Edison 
Company and BEC Energy, 80 FERC para. 61,274 (1997).
    \20\ We noted in Enova that a merger of jurisdictional 
facilities can be effected by a change in control over a public 
utility's facilities. Public utilities (or their parent companies) 
can effect a merger by combining their businesses through the 
formation of a new holding company that will own or control, either 
directly or indirectly, previously unaffiliated entities. See Enova, 
79 FERC para. 61,107 at 61,491-96 (1997).
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2. Data and Format
    The Commission must have the ability to perform, within a 
reasonable time, an independent verification of the horizontal or 
vertical competitive analysis presented in the application. To do so, 
we (and intervenors) must have the data underlying the analysis in a 
useful format. Thus, we are requiring that the data needed to perform 
the competitive analysis, and any additional data used, be filed 
electronically.\21\ Specific data requirements for the various 
components of the competitive analysis are discussed below.
---------------------------------------------------------------------------

    \21\ The electronic filing requirements are set forth in 
Sec. 33.8 of the revised regulations.
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    The Commission must be able to determine whether a merger is 
consistent with the public interest based on the data and analysis 
provided. When a proposed vertical merger requires further evaluation, 
the Commission will determine what procedures are appropriate.\22\ One 
value of the screen process is that some mergers may be quickly 
approved if the evidence as to the lack of effect on competition is 
convincing and verifiable and the merger is otherwise found to be

[[Page 70989]]

consistent with the public interest. The screen process may also be 
useful in narrowing issues that may require further analysis. This can 
be especially helpful to intervenors. In addition, the screen process 
is useful to suggest possible mitigation measures if there is a 
potential competitive concern.
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    \22\ In the NOPR, the Commission recognized that certain data 
required for our analysis may not be available to applicants. When 
this is the case, the Commission proposed that applicants make their 
best efforts to provide accurate substitute data, as well as 
corroborating data to validate the results of the analysis. This is 
not to say that all such evidence will be accepted without challenge 
or verification.
---------------------------------------------------------------------------

Comments
    We note that some commenters suggest specific minimum data to be 
included in the merger filing requirements, some already specified by 
name in the NOPR, and others to be gathered depending on case-specific 
facts and circumstances.
Commission Conclusion
    Upon review of the comments submitted, the Commission adopts the 
revised filing requirements set forth in the NOPR regarding data and 
format without any modifications. The Commission must be flexible when 
evaluating section 203 applications and must be able to obtain any 
information necessary to determine that an application is consistent 
with the public interest. Therefore, we will not attempt to construct a 
specific, exhaustive list of data that must be included in each 
applicant's filing.

IV. Effect on Competition

    The Commission's objective in analyzing a proposed merger's effect 
on competition is to determine whether the merger will result in higher 
prices or reduced output in electricity markets. This may occur if the 
merged firm is able to exercise market power, either alone or in 
coordination with other firms. The filing requirements proposed in the 
NOPR are consistent with Appendix A to the Policy Statement, and 
address anticompetitive concerns in a predictable and expedited 
fashion.
    In Appendix A to our Policy Statement, we outlined a standard 
analytic framework for evaluating mergers, a horizontal competitive 
analysis screen (horizontal screen) designed to allow the Commission to 
quickly identify proposed mergers that are unlikely to present 
competitive concerns. Since the Policy Statement and NOPR were issued, 
we have gained considerable and valuable experience analyzing 
horizontal and vertical mergers and are now establishing filing 
requirements regarding the data needed for the analytic framework and 
the horizontal screen. In Secs. 33.3 and 33.4, the NOPR set forth 
filing requirements to enable the Commission to have the necessary 
Appendix A information.
    The Commission emphasized in the NOPR that the horizontal screen is 
not meant to be a definitive test of the likely competitive effects of 
a proposed merger. Instead, it is intended to provide a standard, 
generally conservative check to allow the Commission, applicants and 
intervenors to quickly identify mergers that are unlikely to present 
competitive problems. The horizontal screen approach allows applicants, 
intervenors and the Commission to have a common starting point from 
which to evaluate proposed mergers. Failing the initial screen does not 
necessarily mean the Commission will reject the merger. Rather, it 
means only that the Commission must take a closer look at the 
competitive impacts of the proposed merger.
    When a proposed merger fails the horizontal screen, the Commission 
will determine what procedures are appropriate. The Commission 
recognizes that these procedures should not delay the processing of 
mergers unnecessarily, and in most cases we may expedite this 
processing. In the NOPR, we solicited comments on alternative 
procedures for investigating mergers that do not pass the initial 
horizontal screen.
    The Commission recognizes the need for balance between the benefits 
of standardization regarding how proposed mergers will be evaluated and 
the need for flexibility, given the changing nature of the electric 
power industry and the likely evolution of analytic techniques and 
capabilities. The Commission solicited comments on whether the proposed 
approach strikes the proper balance between standardization and 
flexibility.

Comments

    Commenters address a number of points regarding the Commission's 
proposed analytic requirements (generally, proposed Secs. 33.3 and 
33.4) . Most of these comments focus on the type of information the 
Commission proposed to obtain from merger applicants, as well as the 
proposed procedures for obtaining and processing such information. For 
example, citing recent experience in the AEP/CSW merger proceeding,\23\ 
APPA/TAPS argue the Commission should reject obviously deficient 
filings. They urge that promulgation of the merger filing requirements 
be accompanied by substantial initial review for compliance.
---------------------------------------------------------------------------

    \23\ American Electric Power Co. and Central and South West 
Corp., 85 FERC para. 61,201; reh'g denied, 87 FERC para. 61,274 
(1999) (AEP/CSW).
---------------------------------------------------------------------------

    Missouri Commission argues the Commission errs when it proposes to 
rely on the applicants' analyses of potential adverse competitive 
effects without doing its own independent analysis or providing 
intervenors with the information they need to conduct their own 
independent analyses. The Commission, Missouri Commission concludes, 
should not depend on applicants for data collection and analysis, 
because applicants inherently have a self-interest in merger approval.
    The FTC Staff echos these concerns and recommends the Commission 
expand its data requirements in order to more closely match the 
Guidelines. It further contends the competitive effects of horizontal 
and vertical mergers are best analyzed with documents, interviews and 
data from a variety of sources that go beyond the scope of the 
information proposed in the NOPR. \24\ In the FTC Staff's view, 
depending upon a merging firm to supply its own analysis may not 
produce reliable information. Therefore, assessments from third parties 
will be important. For example, merger applicants' analysis of their 
ability to raise rivals' costs or their data approximations about other 
firms will be subjective and subject to error and bias. NASUCA raises 
similar concerns, arguing the Commission has an independent obligation 
to obtain the facts. It believes that merger applicants should bear the 
risk of information unavailability and that the Commission should not 
approve mergers without sufficient supporting information.
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    \24\ Among the information the FTC Staff suggests: internal 
documents of the merging parties; third-party documents, including 
documents from industry trade associations; depositions of 
applicants and third-party executives and consultants; history of 
previous antitrust cases; financial analysts' reports; consultants' 
reports on competitive conditions in the industry; documents and 
interviews with executives of failed entrants, prospective entrants 
and fringe firms; filings about competitive conditions made with 
other government agencies; and documents and interviews with 
suppliers and customers.
---------------------------------------------------------------------------

    WEPCO notes that under the Hart-Scott-Rodino approach to 
consideration of mergers by the antitrust agencies, there is 
substantial interaction between agency staff and interested parties 
that has better promoted understanding of merger-related problems. 
WEPCO suggests that one way to improve the communication among 
Commission staff, applicants and intervenors, given the quasi-judicial 
functions of the Commission and its ex parte restrictions, would be for 
staff to prepare a report summarizing its preliminary findings; merger 
applicants and other interested parties could comment upon that report. 
Staff would then revise its conclusions as appropriate to take into 
account any

[[Page 70990]]

new information developed in the comment process.
    Several commenters express concern that applicants provide full 
disclosure of the required data. APPA/TAPS cautions that despite the 
fact that filing requirements focus on the past, current, and near 
future, they cannot accurately capture the dynamic changes in the not-
so-near future. Full disclosure of all information that may bear on 
future competitive activities and changes, such as retail competition, 
is vital to the screening process.\25\
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    \25\ APPA/TAPS notes that strategic alliances should be 
disclosed and treated as mergers where their terms could have 
horizontal or vertical competitive effects. Also, to evaluate 
whether a proposed merger is likely to harm competition by placing 
additional costs on competitors, merging companies should be 
required to disclose existing ``reserve sharing,'' pooling 
arrangements and contractual or other commitments in order to 
continue those arrangements post-merger.
---------------------------------------------------------------------------

    NRECA recommends a two-track merger review policy to foster 
flexibility. It suggest fast-track review of mergers of small and 
medium-sized utilities that would not adversely affect competition in a 
relevant regional market and that could enhance regional competition by 
creating a stronger, more viable competitor. NRECA believes that such a 
two-track review process would allow the Commission to more effectively 
scrutinize proposed ``mega-mergers'' where the Commission's horizontal 
screen indicates the potential to create or exacerbate market 
dominance.
    Finally, APPA/TAPS cautions against applying the institutional 
framework and processes for reviewing ordinary rate filings to 
evaluating mergers. They state that the analysis produced by the filing 
requirements will not yield a reliable answer to the fundamental 
question of the effect of a merger on future competitive markets. They 
therefore urge the Commission not to follow a mechanistic approach to 
evaluating mergers.

Commission Conclusion

    In response to concerns regarding deficient filings, we note that 
this agency has used procedures such as staff deficiency letters to 
obtain additional information from merger applicants.\26\ Nothing 
precludes use of this or other procedures in the future to address 
deficient applications.
---------------------------------------------------------------------------

    \26\ See e.g., UtiliCorp United Inc. and St. Joseph Light & 
Power Co. and UtiliCorp United Inc. and Empire District Electric 
Co., 92 FERC para. 61,067 (2000) (Utilicorp/St. Joseph), AEP/CSW; 
Allegheny Energy, Inc. and DQE, Inc., 84 FERC para. 61,223 (1998) 
(APS/Duquesne).
---------------------------------------------------------------------------

    While we acknowledge Missouri Commission and the FTC Staff's 
concerns that the proposed filing requirements place the Commission in 
a position of relying on merger applicants' potentially biased 
analysis, the Commission can generally obtain the types of information 
these commenters describe or communicate with merger applicants pre-or 
post-filing (through, e.g., a technical conference) regarding 
competitive concerns or the results of preliminary analysis.\27\ For 
example, in Sierra Pacific we proposed a technical conference as an 
appropriate avenue of communication among Commission staff, applicants 
and intervenors.\28\ In addition, the intervention process itself 
allows other market participants to raise concerns.
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    \27\ It is important to note that our statutory authority in 
retrieving information pursuant to a section 203 investigation is 
adjudicatory in nature; adequate public notice, public participation 
and administrative due process are required.
    \28\ Sierra Pacific Power Co., Nevada Power Co. and Portland 
General Electric Co., 92 FERC para. 61,069 (2000).
---------------------------------------------------------------------------

    We note that our regulations require that all data, assumptions, 
techniques and conclusions in applicants' analyses be accompanied by 
supporting documentation. Indeed, the revised regulations explain in 
detail the type of information applicants must file, for use both by 
the Commission and by intervenors, to confirm applicants' results. 
Moreover, the Commission has required, in many instances, full 
disclosure of merger applicants' activities. The Commission will 
continue to use all means available to ensure that merger applications 
are complete, accurate, and free from bias. In regard to complete 
applications, we note that if changes that would affect the analysis 
occur after the date a filing is made with the Commission, but before 
final Commission action, the applicant must supplement its application 
promptly, describing such changes and explaining their effect.
    Currently, Sec. 33.4 of the Commission's regulations provides that 
``the Commission may require additional information when it appears to 
be pertinent in a particular case.'' In the NOPR, the Commission 
proposed that its authority to require the submission of such 
additional information be delegated to the Director of the Office of 
Electric Power Regulation or his designee, under a new Sec. 33.10. No 
commenters opposed this proposed action, and it is hereby adopted with 
the clarification that the ``Director of the Office of Markets, Tariffs 
and Rates'' is substituted for the ``Director of the Office of Electric 
Power Regulation'' to make this section consistent with the 
Commission's recent internal reorganization.
    In response to NRECA's suggestion that the Commission adopt a two-
track system for reviewing mergers of small/medium and large utilities, 
we note that the size of a merger does not indicate the level of 
competitive concern it may raise. Mergers of small, adjacent utilities 
in transmission constrained regions, for example, can raise competitive 
concerns, just as can ``mega-mergers.'' We believe the filing 
requirements proposed in the NOPR are sufficient to produce the 
information and analysis necessary to evaluate small and large mergers 
alike. Our experience has been that mergers that do not pose 
competitive problems will be quickly identified. Therefore, we do not 
see the need to distinguish between mergers of small/medium and large 
utilities.
    Below we discuss the background, public comments and our 
conclusions regarding the more specific information necessary to 
perform the competitive analysis.

V. Horizontal Screen Analysis

    The Guidelines set out the following five steps for analyzing the 
competitive effects of proposed mergers: (1) Analyze whether the merger 
would significantly increase concentration; (2) analyze whether the 
merger, in light of market concentration and other factors that 
characterize the market, raises concern about potential adverse 
competitive effects; (3) analyze whether entry would mitigate the 
adverse effects of the merger; (4) analyze whether the merger would 
result in efficiency gains not achievable by other means; and (5) 
analyze whether, absent the merger, either party would likely fail, 
causing its assets to exit the market.\29\
---------------------------------------------------------------------------

    \29\ Policy Statement at p. 30,118.
---------------------------------------------------------------------------

    The competitive analysis screen \30\ focuses on the first step: 
whether the merger would significantly increase concentration in 
relevant markets. Concentration statistics indicate whether a merger 
may have adverse competitive effects, but they are not the end of the 
analysis. We note that in many cases, the Commission has moved quickly 
beyond market concentration statistics in evaluating the competitive 
effects of proposed mergers. For example, in Commonwealth Edison 
Company and PECO Energy Company, the Commission found that despite high 
concentration statistics in the Commonwealth Edison Company (ComEd) 
destination market, ComEd would not be able to influence market price 
since most of its capacity was nuclear, which is difficult to ramp up 
or

[[Page 70991]]

down in order to withhold output. In addition, the market demand fell 
within the flat portion of the supply curve for most hours of the year, 
so withholding output would not significantly affect price.\31\
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    \30\ These specific filing requirements are set forth in 
Sec. 33.3 of the revised regulations.
    \31\ Commonwealth Edison Company and PECO Energy Company, 91 
FERC para. 61,036 (2000) (PECO/ComEd).
---------------------------------------------------------------------------

    If applicants' competitive analysis screen indicates that the 
merger would significantly increase concentration, applicants must 
either address the other steps in the Guidelines or propose measures 
that would mitigate the adverse competitive effects of the proposed 
merger.\32\ If applicants propose mitigation measures, the screen 
analysis should also take into account, to the extent possible, the 
effect of these remedies on market concentration.
---------------------------------------------------------------------------

    \32\ The specific filing requirements for applicants addressing 
mitigation measures and additional factors are set forth in 
Sec. 33.3(e) and Sec. 33.3(f), respectively.
---------------------------------------------------------------------------

    The competitive analysis screen is made up of four steps: (1) 
Identify the products sold by the merging firms; (2) identify the 
customers affected by the merger; (3) identify the suppliers in the 
market; and (4) analyze the merger's effect on concentration. Below we 
discuss the filing requirements for each step.

A. Relevant Products

Background
    Applicants must identify the wholesale electricity products sold by 
the merging firms. At a minimum, such products include non-firm energy, 
short-term capacity (or firm energy), and long-term capacity. Products 
should be grouped together when they are reasonable substitutes for 
each other from the buyer's perspective. Supply and demand conditions 
for particular electricity products may vary substantially over time 
and, if so, the analysis should take this into account. Periods with 
similar supply and demand conditions should be aggregated. Thus, 
applicants must define and describe all products sold by the firms, 
explain and support the market conditions and groupings, and provide 
all data relied upon for product definition.
    In the NOPR, we stated that as restructuring in the wholesale and 
retail electricity markets progresses, short-term markets appear to be 
growing in importance. We sought comments on the assessment of long-
term capacity markets in merger analysis.
    The delivered price test, which we require applicants to use to 
identify potential suppliers in a market, focuses on the ability of 
suppliers to deliver energy to relevant markets as measured by their 
short-term variable costs. However, there is no good measure for long-
term capacity prices per se. Therefore, we sought comments on the 
appropriate analytic framework for evaluating long-term capacity 
products.
Comments
    As discussed in greater detail in later sections, commenters offer 
a number of insights and suggestions regarding the scope of the 
Commission's merger analysis pertaining to retail competition. The 
major area in the proposed filing requirements where this subject 
arises is in the definition of relevant products. As we noted earlier, 
for example, the Missouri Commission argues that the emphasis on 
products should include retail markets, since unbundling will blur the 
traditional distinction between wholesale and retail electricity 
products. NASUCA suggests the Commission modify its screen to encompass 
the following product markets: Wholesale sales, wholesale purchases, 
retail sales, retail purchases, existing generation, new generation, 
ancillary services related to generation and ancillary services related 
to transmission.
    The FTC Staff argues that unbundling could increase product 
differentiation, which may alter the degree of substitutability between 
products and may affect product market definitions. They also state 
that because electricity cannot be stored in large quantities and 
supply and demand conditions within short time intervals may be 
independent of each other, there may be a need to define electricity 
sales during individual hours as separate product markets, each of 
which may have a different geographic market associated with it. Thus, 
FTC Staff recommends the Commission consider techniques for examining 
the degree of linkage between different electricity product markets 
(e.g., electricity sold on an hourly basis).
    WEPCO states that since electricity is not purchased to be consumed 
in a specific hour, (e.g., off peak, on peak, summer, winter, and 
shoulder months), but it purchased and consumed over the course of a 
year in a stable and predictable pattern, the relevant product market 
for competitive analysis should be electricity consumed over the course 
of a year, not electricity consumed in a single time period. Thus, 
WEPCO believes that guidance is needed from the Commission concerning 
how we will aggregate and evaluate multi-period analyses.
Commission Conclusion
    We agree with NASUCA, Missouri Commission and FTC Staff that 
unbundling and retail competition will affect relevant product 
definitions. The Commission recognized this possibility in the Policy 
Statement when we stated that non-firm energy, short-term capacity, and 
long-term capacity are products that should, at a minimum, be evaluated 
by a merger applicant. Recognizing that energy companies are entering 
new product markets and that the effect of a merger could be to 
eliminate one of the merged companies as a perceived potential 
competitor in such new product markets,\33\ we will also require 
applicants to identify product markets in which they may be reasonably 
perceived as potential competitors. We do not see the need at this 
time, however, to require merger applicants to separately identify and 
define various retail products or to define certain additional 
products, with the exception of ancillary services.
---------------------------------------------------------------------------

    \33\ See below note 77.
---------------------------------------------------------------------------

    We base this conclusion on two reasons. First, it is important to 
define relevant products from the perspective of the consumer, i.e., 
including in a product group those products considered by the consumer 
to be good substitutes. NASUCA's suggested product definitions do not 
do this. For example, we do not see how wholesale sales versus 
wholesale purchases warrant definition as separate relevant products 
from the consumer's perspective. Moreover, given this approach to 
defining relevant products, we disagree with WEPCO that electricity 
consumed over the course of the year should be defined as a relevant 
product. We note in response to the FTC Staff's comments that we 
require separate relevant products be defined for distinct market 
conditions. These market conditions can encompass greater or fewer 
numbers of hours during the year, depending on the specifics of the 
case. To facilitate accurate energy product definition when market 
conditions vary, however, we will require merger applicants to use load 
level, as opposed to time of day. This is a minor modification to what 
was proposed in the NOPR. When time periods are lengthy, distinct 
market conditions that occur within a particular time period can go 
unevaluated. We note that many merger applicants routinely define 
relevant energy products using load level.
    Second, the Commission made it clear in the Policy Statement and 
the NOPR that it stood ready to evaluate the effect

[[Page 70992]]

of a merger on retail competition if a state lacks authority under 
state law and asks us to do so. The NOPR noted that restructuring in 
the electric industry, i.e., retail access, could affect presumptions 
that are necessary to complete our screen analysis. In such cases we 
will require merger applicants to provide analyses that will also be 
useful in assessing the effect of a merger on retail electricity 
markets. For example, the existing filing requirements require 
applicants to provide information on their native load obligations.
    We believe, however, that some ancillary services, specifically 
spinning and non-spinning reserves and imbalance energy--if they are 
sold by the merging firms--must be added to the list of relevant 
products to be analyzed by merger applicants. The movement toward RTOs 
has led to the development of bid-based ancillary service markets, 
especially imbalance energy markets. Participation in these markets is 
greater now than in the past, and we expect such participation to 
expand as markets develop. We note that ancillary service market 
conditions are not directly captured by capacity measures for either 
non-firm energy or short-term capacity. While high levels of or changes 
in concentration in energy markets may be good general indicators of 
the structure of or changes in the structure of ancillary service 
markets, the technical requirements for providing these services may be 
more stringent than those for providing energy, and there may be fewer 
potential suppliers than in energy markets. Given the foregoing, we 
will, therefore, require that merger applicants assess the effects of 
proposed mergers in the reserve and imbalance energy markets. We 
recognize that ancillary service and imbalance energy markets are not 
fully developed in some regions of the country. As RTOs are formed, we 
expect that these markets will become more fully developed.\34\ We, 
therefore, require applicants to analyze reserves and imbalance energy 
as separate products when the necessary data are available. If not, 
applicants must explain why the markets cannot or should not be 
analyzed.
---------------------------------------------------------------------------

    \34\ Regional Transmission Organizations, Order No. 2000, 65 
Fed. Reg. 809 (Jan. 6, 2000), FERC Statutes and Regulations at 
31,135 (1999).
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B. Relevant Geographic Markets

    Below we discuss the methods of identifying the relevant geographic 
markets as set forth in the NOPR.
Background
    Customers (Destination Markets): As discussed in the Policy 
Statement, identifying the customers likely to be affected by a merger 
is one part of defining the geographic scope of the relevant market. At 
a minimum, affected customers include all entities that are directly 
interconnected to any of the applicants or that have purchased 
wholesale electricity from any of the applicants in the past two 
years.\35\ The Commission solicited comments in the NOPR on whether two 
years was the appropriate period of purchases for deciding to include 
purchasers as affected customers. Customers considered to be affected 
by the merger and included in the analysis are referred to as 
``destination markets.''
---------------------------------------------------------------------------

    \35\ Policy Statement at p. 30,130.
---------------------------------------------------------------------------

    To simplify the analysis, customers that have the same supply 
alternatives, as identified in the competitive analysis screen, can be 
aggregated into a single destination market. The Commission has 
accepted this approach in a number of merger filings. For example, in 
Atlantic City/Delmarva, the Commission found acceptable the treatment 
of PJM as a single destination market since customers in PJM trade 
largely with the same set of suppliers. The same is true of mergers 
occurring within the New England and New York ISOs (e.g., ConEd/NU and 
CMP/NYSEG).\36\ We proposed that applicants be required to provide all 
data used in determining the affected customers.
---------------------------------------------------------------------------

    \36\ Consolidated Edison, Inc. and Northeast Utilities, 92 FERC 
para. 61,225 (2000), reh'g denied, 92 FERC para. 61,014 (2000) 
(ConEd/NU) and Energy East Corp. and CMP Group, 91 FERC para. 61,001 
(2000) (Energy East/CMP).
---------------------------------------------------------------------------

Comments
    FTC Staff remarks that the list of affected customers produced by 
the delivered price test provides only a limited picture of the 
customers who may be harmed by a merger. It notes that in their own 
experience, suppliers' pricing decisions focus on attracting new 
customers that often are not on lists of current customers. FTC Staff 
also contends that if a potential anticompetitive effect of a merger 
involves increased coordination among suppliers, the harmful effects of 
the acquisition may go beyond customers of the merging parties to 
include many customers supplied by non-merging companies. Lastly, it 
explains that if a potential anticompetitive effect of a merger is 
slower entry into new geographic markets, the affected consumers will 
(by definition) be those located where the parties have not previously 
done business. Without information about these potential customers, the 
FTC Staff states, merger analysis may underestimate present and future 
demand elasticity or incentives to innovate. Therefore, FTC Staff 
recommends the Commission broaden its concept of affected customers to 
include potential customers and customers of third-party suppliers in 
the market(s) served by the merging parties.
    Because transmission constraints may bind during peak demand 
periods, the FTC Staff suggests that more care be taken when defining 
geographic markets. In an ISO that is divided into zones, such as 
California, during off-peak hours the relevant geographic market could 
be the entire ISO, while during the peak hours each zone could be a 
relevant geographic market. Since, in general, the broader the 
geographic area the less concentrated the market, applicants should 
justify the use of a broad geographic market with evidence that the 
market definition remains viable during peak times. If not, the FTC 
Staff suggests, the market definitions should be narrowed for peak 
periods.
Commission Conclusion
    The Commission generally shares the FTC Staff's broad concept of 
customers which are potentially affected by a proposed merger. We 
believe that the existing requirement to identify as destination 
markets those entities directly and indirectly interconnected with the 
merging companies, in addition to entities with which the merging 
companies trade, partially captures the universe of potential customers 
affected by the merger. We also believe the intervention process is, in 
itself, a generally reliable way for customers potentially affected by 
a merger to identify themselves and raise their particular concerns. 
However, as discussed below under Section V.H, we recognize that energy 
companies are increasingly entering new geographic markets and that the 
presence of a perceived potential competitor in a geographic market can 
have a salutary effect on that market. If a merger could eliminate such 
a salutary effect by removing one of the merging companies as a 
perceived potential competitor in such markets, we will also require 
applicants to identify any geographic markets in which they may be 
reasonably perceived as potential competitors.
    The Commission also agrees with FTC's point regarding the effect of 
transmission constraints on the scope of geographic markets. We believe 
that the market analysis adopted here captures this effect, because the 
use of different

[[Page 70993]]

load levels in defining relevant products narrows the scope of relevant 
geographic markets by constraining transmission where appropriate. 
Thus, markets analyzed during peak load levels are often smaller 
because transmission links are full at those load levels.

C. Suppliers (Delivered Price Test)

Background
    Defining the relevant geographic market also requires identifying 
the sellers that can compete to supply a relevant product. Suppliers 
must be able to reach the destination markets both economically and 
physically. To determine the suppliers that can economically supply a 
destination market, the NOPR proposed that applicants conduct a 
delivered price test. In the delivered price test, suppliers can 
economically serve destination markets to the extent that they have 
generating capacity that can serve the market at a price \37\ no more 
than five percent above the pre-merger market price.\38\ Applicants 
would then adjust suppliers' capacity consistent with the physical 
transmission capacity available to reach the destination market.
---------------------------------------------------------------------------

    \37\ The price would include payments for transmission and 
ancillary services needed to deliver the power.
    \38\ Policy Statement at pp. 30,130-31.
---------------------------------------------------------------------------

    In some cases, potential suppliers may be parties to mergers that 
have been announced but not yet consummated. The Commission sought 
comments on whether those suppliers should be treated in the 
competitive analysis screen as if their mergers have been consummated 
or whether they should be treated as independent rivals.
    In addition, the NOPR proposed that a supplier's ability to 
economically serve a destination market be measured by generating 
capacity controlled by the supplier rather than historical sales data. 
We also discussed in the NOPR two generating capacity measures we 
believed appropriate for the competitive analysis screen: economic 
capacity (EC) \39\ and available economic capacity (AEC).
---------------------------------------------------------------------------

    \39\ The starting point for calculating economic capacity is the 
supplier's own generation capacity with low enough variable costs 
that energy can be delivered to a market (after paying all necessary 
transmission and ancillary service costs, including losses) at a 
price that is five percent or less above the pre-merger market 
price. Capacity must be decreased to reflect any portion committed 
to long-term firm sales; and it must be increased to reflect any 
portion acquired by long-term firm purchases. In addition, any 
capacity under the operational control of a party other than the 
owner must be attributed to the party for whose economic benefit the 
related unit is operated. The result of these calculations is the 
supplier's ``economic capacity.''
---------------------------------------------------------------------------

Comments
    A number of commenters respond generally to the Commission's 
proposed filing requirements governing the definition of relevant 
geographic markets using the delivered price test. EEI believes that 
the screen is valuable in identifying potential problems early in the 
process. However, EEI and Southern advocate a change in the 
Commission's Appendix A analysis from the individual destination 
markets defined using the delivered price test to a single geographic 
market defined by using the hypothetical monopolist test, as suggested 
by the DOJ/FTC Merger Guidelines.\40\ EEI claims that the hypothetical 
monopolist test will produce a more accurate picture of the markets a 
merger would affect. It argues that a major flaw in the delivered price 
test is that it assumes that price discrimination can occur even though 
such discrimination would be unlawful and the Commission's open access 
rules go far to prevent it.
---------------------------------------------------------------------------

    \40\ Southern comments that actual market conditions reflecting 
any legal constraints on market participation should be considered, 
but only if such constraints are actually being adhered to.
---------------------------------------------------------------------------

    EEI explains that the delivered price test does not consider the 
role of power marketers and arbitrage in preventing potential price 
discrimination. In contrast, the hypothetical monopolist test assumes 
that there is no price discrimination, absent other factors. EEI argues 
that the Commission's claim that the delivered price test produces 
conservative results is not persuasive because the delivered price test 
produces erroneous results by over (or understating) the potential 
effects of a merger on the market.
Commission Conclusions
    In response to general concerns regarding the delivered price test, 
we reiterate that the competitive analysis screen is intended to 
provide a standard, generally conservative check to allow the quick 
identification of mergers that are unlikely to present competitive 
problems, and is not meant to be a definitive test of the competitive 
effects of a proposed merger. Therefore, we will continue to apply the 
delivered price test set forth in the Policy Statement in future merger 
cases. This does not preclude applicants or other parties from filing 
alternative analyses, including those using the price increase (i.e., 
hypothetical monopolist) test for defining relevant markets, as 
suggested by EEI, nor does it preclude the Commission from performing 
analyses of alternative scenarios to test the sensitivity of results to 
key assumptions, as suggested by the FTC Staff.
    We also will adopt our proposal regarding suppliers' ability to 
reach a market. Since merger analysis should be as forward-looking as 
practicable, suppliers' ability to economically serve a destination 
market seems better measured by the generating capacity they control 
than by historical sales data. This is because information about 
current or past sellers may not identify those participants whose 
generation capacity could discipline future price increases. Moreover, 
data on sales made in a past environment characterized by monopoly and 
cost-based rates or pancaked transmission rates and other grid 
management inefficiencies may not be a good indicator of how firms will 
behave in an environment increasingly characterized by generation 
competition and RTOs.\41\ In addition, the competitive analysis screen 
filed by applicants must use both EC and AEC measures to gauge supplier 
presence.
---------------------------------------------------------------------------

    \41\ Baltimore Gas & Electric Company and Potomac Electric Power 
Company, Opinion No. 412, 76 FERC para. 61,111 (1996), 79 FERC para. 
61,027 at 61,120-21 (1997) (BG&E/PEPCO). This is not to say, 
however, that sales data are irrelevant to market analysis. If sales 
data indicate that certain participants actually have been able to 
reach the market in the past, it is appropriate to consider whether 
they are likely candiates to be included in the market in the 
future. BG&E/PEPCO at n.72. It is for this reason that we will 
require a ``trade data check'' as part of the competitive analysis 
screen.
---------------------------------------------------------------------------

    As we stated above, the competitive analysis screen is intended to 
be a forward-looking measure. Therefore we believe it is appropriate 
that applicants provide sensitivity analyses of their results to the 
assumption that announced, but not consummated, mergers are completed. 
Such information would be useful in assessing, for example, the 
appropriateness of behavioral versus structural remedies. Applicants 
may perform sensitivity analyses which incorporate different scenarios 
regarding announced, but not consummated mergers and should explain why 
certain scenarios might be more appropriate.
    Discussed in more detail below are the general data requirements 
that are needed to determine the suppliers in the relevant market for a 
competitive analysis screen, a summary of the comments on these 
requirements, and our conclusions.

Generating Capacity and Variable Cost

Background
    The NOPR explained that the basic determinants of a supplier's 
presence in a market are the generating capacity the supplier controls 
and the variable costs associated with that capacity. For each

[[Page 70994]]

potential supplier to a relevant market, applicants must file the 
publicly available generation capability and variable cost data for 
each generating plant or unit. Aggregate plant level data from plants 
with units that burn different fuels can result in average plant 
variable costs that inaccurately state the units' economic ability to 
sell into a market.\42\ For such plants, cost data at the unit level 
are preferable to cost data at the plant level, and applicants must 
file disaggregated plant data to the extent it is publicly available.
---------------------------------------------------------------------------

    \42\ We have noted such discrepancies in data received from 
applicants in our analysis in a prior case. See BG&E/PEPCO, pp. 
61,119-120.
---------------------------------------------------------------------------

Comments and Commission Conclusion
    No specific comments were received on this issue. We adopt in this 
Final Rule the proposals set forth in the NOPR.

Purchase and Sales Data Adjustments

Background
    In the NOPR, we stated that data regarding the long-term purchases 
and sales of suppliers should be filed with the application. These data 
would, to the extent available, include the buyer, the seller, the 
contract duration, the degree of interruptibility, the quantity (MW), 
and the capacity and energy charges. Applicants must explicitly show 
any adjustments made to suppliers' capacity due to long-term contracts.
Comments and Commission Conclusion
    No specific comments were received on this issue. We note that our 
experience with both horizontal and vertical mergers since the NOPR was 
issued indicates that case-specific circumstances are important in 
determining if the inclusion of purchased power in a supplier's 
capacity is reasonable. For example, if purchased power could be 
withheld by the merged firm to drive up market prices, including such 
purchases in a supplier's capacity would be appropriate. Therefore, we 
will require that purchase and sales data include information on 
whether the terms and conditions of purchase contracts confer 
operational control over generation resources to the purchaser. In 
addition, we will also require information on the remaining life of 
contracts and any evergreen or rollover provisions. If the terms and 
conditions of purchase contracts do confer operational control over the 
generation resources to the purchaser and the merger raises competitive 
concerns, this information could be useful, for example, in determining 
the type and duration of remedies. If contracts do not confer 
operational control over the generation resources to the purchaser then 
the capacity should be attributed to the seller.

Native Load Commitment Adjustments

Background
    Along with EC, the other measure of supplier presence relevant to 
the competitive analysis screen is AEC. AEC is calculated as EC less 
the capacity needed to serve native load customers.\43\ In the NOPR, we 
proposed that applicants include this measure in their screen analysis 
for all suppliers that have native load commitments. The Commission 
sought comments on the role of native load and the weight the AEC 
measure should be given in market analyses.
---------------------------------------------------------------------------

    \43\ Native load customers are the wholesale and retail power 
customers on whose behalf a utility, by statute, franchise, 
regulatory requirement, or contract, has an obligation to construct 
and operate an electric system.
---------------------------------------------------------------------------

Comments
    A number of commenters raised issues regarding native load 
obligations. For example, WEPCO asserts that retail choice reduces 
native load obligations and correspondingly increases AEC and available 
transmission capability (ATC) in wholesale bulk power markets. It 
states that under full retail competition with complete release of 
native load, AEC converges to EC. In states where retail competition is 
not on the horizon, AEC still provides useful information. WEPCO, 
therefore, suggests the Commission consider the value of AEC on a case-
by-case basis.
    NASUCA and Missouri Commission argue that since retail choice is 
quickly expanding throughout the country, the Commission should not 
rely on AEC. With retail choice comes the release of some or all of a 
utility's native load obligation. In addition, under retail choice, 
rates for native load customers that had been regulated become market-
based, increasing the ability of anticompetitive behavior to raise 
rates. NASUCA and Missouri Commission also point out that the 
Commission noted in the NOPR that the assumption that a utility uses 
its least-cost generation to serve its native load may no longer hold 
under retail competition, to whatever extent it currently holds.
    The FTC Staff argues the impending release of native load 
requirements has different competitive implications for a merger before 
and after retail choice programs are enacted. It suggests the 
Commission look at two scenarios: one considering those suppliers that 
are constrained by native load obligations (representing the near-term) 
and one considering those that are not (representing the long-term). 
EEI recommends the Commission require applicants to perform tests of 
the sensitivity of their delivered price test results to changes in 
assumptions regarding retail choice.
Commission Conclusions
    We adopt in this Rule the proposals set forth in the NOPR. The 
Commission is cognizant that the term ``native load'' has a specific 
meaning. However, as electricity markets change, the meaning of native 
load may change too, such that it is reasonable to consider it as part 
of a broader set of contractual commitments. We agree with commenters 
regarding the need to recognize the implications of retail access for 
evaluating AEC and EC results. The Commission has raised this issue in 
a number of merger cases.\44\ As a result of these concerns, we 
encourage merger applicants who rely on estimates of retail access to 
provide sensitivity tests of their results showing how varying degrees 
of retail competition would affect concentration statistics. These 
tests could include, for example, scenarios with differing geographic 
market definitions if retail competition is in varying stages of 
development in the markets affected by the merger. Applicants must 
describe and indicate the status of retail access programs in the 
markets affected by their proposed merger.
---------------------------------------------------------------------------

    \44\ See, e.g., Utilicorp/St. Joseph.
---------------------------------------------------------------------------

    Where applicants are using the AEC measure in the competitive 
analysis screen, they must file historical data regarding hourly native 
load commitments. Applicants must provide these data for the most 
recent two years or the most recent available time period or explain 
why such data are not relevant, given the status of retail access.\45\ 
The specific filing requirements for reporting native load commitments 
are set out in Sec. 33.3(d)(4) of the revised regulations.
---------------------------------------------------------------------------

    \45\ Hourly data are available in electronic format from the 
FERC Form 714, Annual Electric Control and Planning Area Report.
---------------------------------------------------------------------------

Other Adjustments to Supplier Capacity

Background
    In the NOPR, we stated that other adjustments to reflect a 
supplier's competitive ability to serve a destination market may be 
appropriate, and that applicants must support any such adjustments with 
adequate

[[Page 70995]]

analyses and set out all data and assumptions used. There may be 
instances where a generation supplier's ability to participate in 
markets is limited by statutory restrictions. For example, the tax-
exempt status of municipal generators can be jeopardized if they sell 
more than a certain percentage of their tax-exempt financed generation 
to private utilities. Another example is the statutory geographic 
limitations placed on the Tennessee Valley Authority's wholesale sales 
activities. We noted that failing to recognize such restrictions could 
overstate the ability of such generation suppliers to compete and 
thereby to discipline prices in a market.
    Another adjustment discussed in the NOPR that may be needed to 
accurately represent a supplier's ability to sell into markets is to 
adjust for reserve requirements for reliability or other reasons. 
Generation capacity that must be held in reserve is not available to be 
sold into markets on a firm basis to respond to price increases, and 
therefore should not be attributed to the supplier in the competitive 
analysis screen.
Comments
    WEPCO argues that by ignoring alternative markets in which 
suppliers could sell, the delivered price test overstates the amount of 
power that seeks to reach each destination market. This can cause 
mergers of no competitive significance to fail the screen and 
competitively significant mergers to pass it. Therefore, realistic 
assessment of mergers requires that the opportunity costs of sales in 
other areas be taken into account.
Commission Conclusions
    We adopt in this Rule the proposals set forth in the NOPR. We agree 
with WEPCO that it may be useful in certain cases to account for 
suppliers' opportunity costs in defining relevant geographic markets. 
We note that ongoing modeling efforts are attempting to incorporate 
this capability and we encourage merger applicants and industry experts 
to continue such efforts. If merger applicants wish to provide market 
analyses that reflects suppliers' opportunity costs, we will consider 
such analyses as a supplement to the required analysis. Applicants must 
describe any statutory restrictions that may apply to generation 
suppliers included in their competitive screen analyses, reserve 
requirements and how those requirements affect the availability of each 
unit included in the competitive analysis, and any other adjustments to 
supplier capacity.

Transmission Prices, Ancillary Service Prices and Loss Factors

Background
    The NOPR emphasized that an important factor in determining whether 
capacity can serve a destination market is the transmission costs that 
would be incurred in delivering generation services to a destination 
market. The Policy Statement recognizes that prices paid for 
transmission and ancillary services should be added to the variable 
costs of a supplier's capacity.\46\ For purposes of competitive 
analysis screen, applicants must use the maximum tariff rates in public 
utilities' open access tariffs on file with the Commission. The NOPR 
pointed out that where a non-public utility's transmission system is 
involved, the maximum tariff rates under any non-jurisdictional (NJ) 
open access reciprocity tariff should be used. If an NJ tariff for an 
entity has not been submitted to the Commission, the NOPR proposed that 
applicants use their best efforts to obtain or estimate transmission 
and ancillary services rates.\47\ In cases where the transmission and 
ancillary service prices used in a competitive analysis screen are not 
found in publicly available tariffs or rate schedules, applicants may 
need to estimate these parameters. The assumptions underlying such 
estimates must be adequately supported.
---------------------------------------------------------------------------

    \46\ Policy statement at pp. 30,131.
    \47\ Rates for non-public utilities that are members of a 
regional body such as an RTO may be found in the RTO tariff. Such 
information may also be available on a non-public utility's OASIS.
---------------------------------------------------------------------------

    Consistent with the generally conservative nature of the 
competitive analysis screen, the NOPR proposed to require that the 
transmission prices used be the maximum tariff rates in the open access 
tariffs. Applicants may present, in addition to the required screen 
analysis, a separate analysis using lower discounted transmission 
rates, if applicants can demonstrate that discounted lower rates have 
been generally available and that discounting is likely to be available 
in the future.\48\
---------------------------------------------------------------------------

    \48\ For public utilities (and non-public utilities with OASIS), 
evidence should be available from OASIS archives. OASIS database 
transaction data must be retained and made available upon request 
for three years after they were first posted. See 18 CFR 37.7.
---------------------------------------------------------------------------

    Restructuring efforts in some regions may result in transmission 
pricing regimes that depart from traditional system-specific, average 
cost prices. Accordingly, the NOPR proposed that the transmission 
pricing used in the competitive analysis screen and the data presented 
in the filing reflect the transmission pricing regime in effect in the 
relevant geographic markets.
    The NOPR proposed that for each transmission system that a supplier 
must use to deliver energy to a relevant destination market, applicants 
must provide data, including the transmission provider's name, the firm 
and non-firm point-to-point rates, the ancillary services rates, the 
loss factors, and an estimate of the cost of supplying energy losses. 
Where tariff rates that are expressed as $/MW are converted to $/MWH, 
applicants must explain the conversion. The NOPR proposed that 
applicants must also explain how suppliers are assigned transmission 
contract paths to the destination markets.
Comments and Commission Conclusion
    No specific comments were received on this issue. We adopt in this 
Final Rule the proposals set forth in the NOPR. The specific filing 
requirements for transmission rate and loss factor data are set out in 
Sec. 33.3(d)(5) of the revised regulations.

Market Prices

Background
    As discussed in the Policy Statement, a supplier's capacity may be 
included in a relevant market, for purposes of the competitive analysis 
screen, if it can be delivered into the market at a price that is no 
more than 5 percent above the pre-merger market price.\49\ We therefore 
proposed that the application support market prices for each relevant 
product and geographic market. Significant market conditions included, 
for example, those characterized by periods of high (peak) or low (off-
peak) demand and by transmission constraints.\50\
---------------------------------------------------------------------------

    \49\ Policy Statement at p. 30,131.
    \50\ Atlantic City/Delmarva, p. 61,408.
---------------------------------------------------------------------------

    As discussed in the Policy Statement, the Commission does not 
believe that all electricity markets have matured sufficiently to 
exhibit single market-clearing prices for various products. Therefore, 
in the NOPR we sought comments on appropriate criteria for determining 
when surrogate measures are needed. We did not require a specific 
method for estimating market prices. However, we stated that the 
results must be supported and consistent with what one would expect in 
a competitive market. For example, we would expect prices to vary 
little from customer to customer in the same region during similar 
demand conditions (if there are no transmission constraints), but we 
would expect prices to vary between peak and off-peak

[[Page 70996]]

periods.\51\ Where results are at odds with those that would be 
expected under competitive market conditions, we proposed that 
applicants explain such results. We also encouraged applicants to use 
more than one approach to estimating market prices in order to 
demonstrate that the market price estimates are valid. To support the 
market price estimates, we proposed that applicants must file any cost 
or sales data relied upon in estimating the price, as well as an 
explanation of how the data were used to determine the estimates.
---------------------------------------------------------------------------

    \51\ Ohio Edison Company, et al., 80 FERC para. 61,039 at 
61,105-6 (1997) (FirstEnergy).
---------------------------------------------------------------------------

Comments
    The FTC Staff raises a number of issues concerning the choice of 
representative prices and their effect on geographic market size. 
First, it argues that geographic markets expand when prices are high 
because it becomes feasible for distant electricity suppliers to 
provide economically competitive substitutes. However, it points out 
that transmission congestion during these peak periods would reduce the 
relevant market. Similarly, it states the transmission pricing regime 
can affect the scope of the relevant market. It proposes the Commission 
require merger applicants to provide a sensitivity analysis for various 
pricing regimes as well as for the representative prices used in the 
competitive inquiry.
    WEPCO raises similar concerns. WEPCO believes that because prices 
in adjacent markets tend toward uniformity, a single regional market 
emerges in place of several localized ones. The adjustment WEPCO 
proposes is for the Commission to require a competitive analysis over 
the larger area in which price formation takes place.
    Several commenters raise related issues concerning the 
determination of representative prices. For example, the FTC Staff, 
Missouri Commission and NASUCA contend that either competitive prices 
or likely future prices are more appropriate choices for baseline 
market power analyses than the pre-merger market prices. Similarly, the 
Missouri Commission and NASUCA want the Commission to require merger 
applicants to account for the effect of any residual retail market 
power by adjusting the base price and/or 5 percent differential used to 
determine alternative supply sources in order to reflect the absence of 
full competition in the pre-merger markets.
Commission Conclusions
    We adopt in this Rule the proposals set forth in the NOPR. In 
response to commenters' concerns, we agree that markets can be 
regional, as opposed to local, under certain circumstances. The 
Commission has often received merger filings that employ identical 
price estimates for several destination markets.\52\ Where there are no 
transmission constraints between markets and where there is a 
demonstrated lack of price discrimination, similar prices across 
destination markets generally indicate a larger, single geographic 
market.\53\ Therefore, even though the delivered price test initially 
requires the identification of separate relevant markets associated 
with each affected customer, applicants should explain and support the 
use of a broader regional market if they choose to use such a market 
definition.
---------------------------------------------------------------------------

    \52\ Examples include Energy East/CMP, ConEd/NU, and NiSource 
Inc. and Columbia Energy Group, 92 FERC para. 61,068 (2000) 
(NiSource/Columbia Energy).
    \53\ When transmission constraints are binding, identical prices 
in adjacent markets may still occur, although this is unlikely.
---------------------------------------------------------------------------

    The Commission also believes that selecting representative market 
prices in a sensible manner is among the most critical components of 
merger analysis when determining players in the relevant market. We 
note that since the NOPR was issued, the availability of price data has 
increased. However, there will likely be instances where actual price 
data may be limited or unavailable. We are open to the use of estimated 
prices, provided that they are accurate representations of prevailing 
market conditions. The accuracy of such prices must be supported by 
available data. In cases where applicants provide analysis based on 
price ranges, we note that results that differ from those based on 
actual reported prices will be inadequate unless evidence is provided 
to the contrary.\54\ Given the importance of prices to the outcome of 
market definition, we will require applicants to perform sensitivity 
analysis of alternative prices on the predicted competitive effects. 
This provides us with an additional measure of confidence and assurance 
that results are reliable.
---------------------------------------------------------------------------

    \54\ See, CP&L/Florida Progress, in which prices based on system 
lambda and observed ``Market Power Week'' data were different.
---------------------------------------------------------------------------

    The specific filing requirements for market price data are set out 
in Sec. 33.3(d)(6) of the revised regulations.

D. Transmission Capability

    In the NOPR, we explained that the capacity of suppliers determined 
to be economic in a relevant destination market (that is, capacity that 
can be delivered at a cost that is no more than 5 percent above the 
pre-merger market price) may be included in a relevant market, for 
purposes of the competitive analysis screen, only to the extent that 
transmission capability is available to the supplier. Such capacity is 
calculated as the sum of ATC and any firm transmission rights held by 
the supplier that are not committed to long-term transactions. Thus, 
the extent of transmission capability and the allocation of the rights 
to use that capability are important factors in determining a 
supplier's ability to physically reach a market.
    This section discusses the general data and analyses proposed in 
the NOPR to allow us independently to estimate each economic supplier's 
ability to reach a market.

Physical Capability

Background
    In the NOPR, we proposed that for those suppliers able to 
economically serve a relevant destination market, applicants must 
present data on transmission capability for each transmission system a 
supplier must use to deliver the energy, to the extent available. These 
data would include total transfer capability (TTC) and firm ATC and 
must be consistent with values posted on the OASIS. We were, however, 
concerned that the sum of transfer capabilities reported on OASIS sites 
could exceed the simultaneous transfer capability. We therefore 
proposed the transmission capability be reported as simultaneous 
transfer capability to avoid attributing more generating capacity to a 
market than could actually reach it under actual operating conditions.
    The NOPR also proposed that applicants identify the hours when 
transmission constraints have been binding and the levels at which they 
were binding. We proposed the application also present data regarding 
whether and how the proposed merger would change line loadings and the 
resulting effect on transfer capability. To the extent possible, 
applicants should provide maps showing the location of transmission 
facilities where binding constraints currently occur. The Commission 
asked for comments regarding what determines when a binding constraint 
is significant enough to cause competitive concern. For

[[Page 70997]]

example, is there a minimum number of hours that a constraint must 
last?
    The Commission understood that applicants must depend on publicly 
available information regarding transmission capability for systems 
other than their own, and that some of the information discussed above 
may not be generally available for all systems. The NOPR proposed that 
applicants file the best available data regarding systems other than 
their own. However, all of the data discussed in this section regarding 
the applicant's systems must be filed, even if it is not available for 
all other systems. An accurate representation of transmission 
conditions on systems, where the merger's effects are likely to be 
greatest is important.
Comments and Commission Conclusions
    No specific comments were received on this issue. The Commission 
understands that simultaneous transfer capability data may not be 
generally available. Where this is the case, applicants must use the 
best data available to estimate transfer capability. For example, the 
analysis should not add together the capabilities of several interfaces 
if the simultaneous transfer capability into a market is less than the 
sum capabilities of the individual interfaces.\55\ The Commission 
expects that the development of RTOs should result in the availability 
of transmission data that is more accurate because RTOs will conduct 
regional transmission analyses that account for factors such as loop 
flows and simultaneous transfers in a coordinated fashion.
---------------------------------------------------------------------------

    \55\ First Energy, p. 61,104.
---------------------------------------------------------------------------

    In addition, we recognize the importance of flow-based modeling in 
terms of both the existing transmission network and any proposed 
integration between the merging parties. We note that the North 
American Electric Reliability Council has developed data that greatly 
facilitate the use of flow-based models.\56\ As the industry continues 
to develop flow-based models, we encourage applicants to adopt these 
methods for estimating transmission availability.\57\
---------------------------------------------------------------------------

    \56\ See, e.g., North American Electric Reliability Council's 
web page (http://www.nerc.com.filez/ptdf/html) on use of Power 
Transfer Distribution Factors and the Interchange Distribution 
Calculator which can be used to identify interchange transactions 
contributing to a constraint.
    \57\ See, e.g., Northern States Power and New Centuries, Inc., 
91 FERC para. 61,157 (2000) reh'g pending (NSP/New Century), where 
the applicants modeled the effect of the integration on transmission 
availability.
---------------------------------------------------------------------------

    The specific filing requirements for transmission capability data 
are set out in Sec. 33.3(d)(7) of the revised regulations.

Firm Transmission Rights

Background
    The NOPR suggested that transmission capacity along transmission 
paths between suppliers and destination markets that is reserved under 
a long-term firm transmission contract by suppliers should be presumed 
to be available to other suppliers on a non-firm basis unless the 
capacity is committed to a long-term power transaction. We proposed 
that applicants identify such transmission capability and provide 
supporting information, including the FERC rate schedule numbers if the 
transmission provider is a public utility.
Comments
    The New York Commission contends that along with long-term 
transmission rights, transmission congestion contracts (TCCs) need to 
be considered in analyzing market power. The New York Commission 
further states that a market participant who owns generation in a 
higher-priced market along with a substantial amount of transmission 
rights or TCCs could increase the value of its TCCs by withholding 
generation, thereby causing the market price to rise.
    In addition, WEPCO expresses concern that confusion may arise as to 
whether a long-term transmission reservation is associated with a long-
term transaction in light of ongoing industry restructuring.
Commission Conclusions
    We adopt the approach in the NOPR as to the information that 
applicants must present regarding the treatment of firm transmission 
rights (FTRs). We agree with the New York Commission regarding the 
importance of TCCs and therefore will also require applicants to file 
the same information about TCCs that we have required for FTRs. Since 
FTRs and TCCs confer either physical or financial rights, we clarify 
that applicants must provide information in either case.\58\ This 
information would be useful in doing a competitive effects analysis.
---------------------------------------------------------------------------

    \58\ In either case, physical or financial, withholding 
generation could increase the value of FTRs and TCCs. On the other 
hand, competing firms that hold FTRs may have incentives that offset 
this effect. Applicants are encouraged to provide such information.
---------------------------------------------------------------------------

    In response to WEPCO's concern that long-term transmission 
reservations may not be associated with long-term transactions, we note 
that our approach is to assume that unused long-term transmission 
capacity will be made available to other suppliers through secondary 
transmission markets or other means. Consistent with Order 888 and the 
pro forma tariff, such unused capacity will be treated as available on 
a short term (non-firm) basis.
    The specific filing requirements for firm transmission rights data 
are set out in Sec. 33.3(d)(9) of the revised regulations.

Allocation of Transmission Capability

Background
    The NOPR proposed that transmission capability that is not subject 
to existing firm reservations by others may be presumed for purposes of 
the competitive analysis screen to be available to economic suppliers 
to reach the relevant markets. However, this would not be the case for 
transmission capability on interfaces that would become internal to the 
merged firm after the merger. If, after a merger, the merged firm would 
have either generating resources or load on both sides of the 
interface, and would have ownership or entitlement interests in the 
interface on both sides, the transmission capability on that interface 
could be used to serve native load. Since native load generally would 
have a higher reservation priority than most third party uses, it could 
preclude access by other suppliers to that interface.\59\ The 
Commission proposed that, for purposes of the competitive analysis 
screen, it would be inappropriate to allocate to competing sellers 
unreserved capability over interfaces internal to the merged company 
unless the applicants demonstrate that: (a) The merged company would 
not have adequate economic generating capacity to use the interface 
capability fully, (b) the applicants have committed that the portion of 
the interface capability allocated to third parties will in fact be 
available to such parties, or (c) alternate suppliers have purchased 
the transmission capability on a long-term basis.\60\ Any allocation of 
internal transfer capability to third parties consistent with the above 
guidance would have to be adequately explained and supported.
---------------------------------------------------------------------------

    \59\ Wisconsin Electric Power Company, et al. (Primergy), 79 
para. 61,158 at 61,694 (1997), and FirstEnergy at 61,107.
    \60\ FirstEnergy, pp. 61,103-04.
---------------------------------------------------------------------------

    In many cases, multiple suppliers could be subject to the same 
transmission path limitation to reach the same market, and the sum of 
their economic generation capacity could exceed the transmission 
capability available to them. Where this situation arises, we proposed 
the competitive

[[Page 70998]]

analysis screen allocate the transmission capability among the 
suppliers' generating capacity. There are a number of methods for 
accomplishing this. We proposed that applicants describe and support 
the method used and show the resulting transfer capability allocation. 
The Commission did not propose a single method, but invited comments on 
the merits of various approaches to allocating transmission capability 
in the competitive analysis screen.
Comments
    Commenters generally agree with the Commission's policy of 
allocating transmission capacity over post-merger internal interfaces 
to the merging parties absent a showing that the capacity is generally 
available to others. However, NARUC and the Ohio Commission argue the 
Commission should also examine external interfaces, which can be 
affected by factors such as seasonal increases in native load. FTC 
Staff and NRECA believe the Commission should examine short-term 
constraints carefully, pointing to the potentially large effects on the 
market. Some commenters also advocate further information filing 
requirements, such as load flow studies (including relevant details 
necessary to replicate the results) and five years of historical data 
on planned and unplanned outages and their effect on reactive power. 
The Ohio Commission echoes these sentiments, recommending that 
applicants, in addition to submitting historical data on plant outages, 
should detail the effects of these outages on reactive power.
    WEPCO argues that under the delivered price test, transmission 
capacity allocation becomes vitally important and thus becomes an 
unnecessary centerpiece of controversy. According to WEPCO, the 
delivered price test relies heavily on relatively arbitrary procedures 
for allocating power competing in destination markets to suppliers, 
because in most cases, there is not enough information to specify which 
generators serve which markets. Therefore, WEPCO explains, rules must 
be designed for assigning shares of power flows to generation owners. 
An example would be to assign the output of a local generator to the 
local market up to the limit of the control area load.
Commission Conclusions
    We adopt in this Rule the NOPR requirements relating to the 
determination of transmission capability. We note that transmission 
allocation is a key issue in defining relevant geographic markets in 
the analysis of constrained networks. However, it is not clear to what 
arbitrary procedures for allocating transmission capability in the 
delivered price test WEPCO is referring. In the NOPR, we did not 
propose a particular method of allocating limited transmission 
capability among suppliers of economic generation capacity in the same 
market, but invited comments on various approaches. A variety of 
allocation methods are possible, and the Commission has acknowledged 
that certain methods provide more accurate and reasonable results than 
others (i.e., pro-rata as opposed to least-cost). Applicants must 
describe and support the method used and show the resulting transfer 
capability allocation. We will not at this time specify particular 
rules or require a single method for transmission allocation. However, 
since transmission allocation is a key parameter in defining relevant 
markets, there are benefits to sensitivity analysis using different 
allocation methods. We encourage such analysis.
    Commenters generally agree with our proposed treatment of 
transmission capability on interfaces that would become internal to the 
merged firm after the merger. We also have addressed this issue in 
several merger cases.\61\ We therefore adopt the NOPR's proposals 
regarding the treatment of these interfaces (i.e., applicants may 
allocate sellers unreserved capacity over their internal interfaces if 
(1) the merged company would not have adequate economic generating 
capacity to use the interface capability fully; (2) applicants have 
committed that the portion of the interface capability allocated to 
third parties will in fact be available to such parties; or (3) 
alternate suppliers have purchased the transmission capability on a 
long-term basis). External interfaces, as NARUC and the Ohio Commission 
also point out, should be examined, and addressed in applicants' 
analysis.
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    \61\ See e.g., APS/Duquesne, Louisville Gas and Electric Co., 
Kentucky Utilities Co., and PowerGen plc, 91 FERC para. 61,321 
(2000).
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    We agree with FTC Staff and NRECA that short-term constraints can 
have large effects, and we intend to continue to examine them. In 
response to commenters' suggestions regarding further data 
requirements, we believe that such information might be useful in some 
cases, but should not be required for all merger applications. If 
further information is needed in a particular case to accurately 
determine transmission capability, we will require it.

Summary of Supplier Presence

Background
    The NOPR proposed requiring applicants to provide a table 
summarizing supplier presence in each of the relevant destination 
markets. The table would include the market designation, the product, 
the name of each supplier, and the amount of generation capacity each 
supplier can economically deliver to the market after accounting for 
available transmission capability. This summary information is 
particularly useful in identifying the suppliers in a relevant market 
and their relative market shares.
Comments and Commission Conclusions
    No specific comments were received on this issue. We adopt the 
NOPR's proposal. The specific filing requirements for this summary of 
supplier presence are set out in Sec. 33.3(d)(9) of the revised 
regulations.

E. Historical Data

Background
    In the NOPR, we proposed that applicants file historical data that 
can be used to corroborate the results of the competitive analysis 
screen. We explained that we understood that applicants depend on 
publicly available information for the majority of the screen analysis 
and that some detailed data may not be generally available for all 
market participants. However, relevant data regarding applicants' own 
transactions and transmission systems are available to the applicants 
and we proposed that this data must be filed. Below we discuss the 
types of relevant data set forth in the NOPR.
    Trade data: The Commission proposed that applicants file actual 
trade data regarding sales and purchases in which applicants 
participated for the most recent two years for which data are 
available. These data will be used to corroborate the suppliers 
identified as participating in the relevant destination market and the 
extent of their participation. We proposed that applicants must provide 
an explanation of any significant differences between the results 
obtained by the competitive analysis screen and recent trade patterns. 
We also proposed that applicants file trade data regarding all 
electricity sales and purchases in which they participated, identifying 
the seller, the buyer, the characteristics of the product traded and 
the price.
    Transmission service data: The competitive analysis screen 
evaluates the ability of suppliers to reach relevant

[[Page 70999]]

markets economically and physically. One of the critical components of 
the screen analysis is the availability of transmission capacity. We 
proposed that applicants must file estimates of ATC and TTC used in the 
competitive analysis screen, as well as historical transmission service 
information, which is valuable to corroborate the results. 
Specifically, the Commission proposed that applicants submit a 
description of all instances in the two years preceding the application 
in which transmission service on systems owned or operated by the 
applicants had been denied, curtailed or interrupted. This description 
must, to the extent such data are available from OASIS sources, 
identify the requestor, the type, quantity and duration of service 
requested, the affected transmission path, the period of time covered 
by the service requested, the applicants' response, the reasons for the 
denial and the reservations or other use anticipated by the applicants 
on the affected transmission path at the time of the request.
Comments and Commission's Conclusion
    No specific comments were received on this issue. We, therefore, 
adopt the NOPR's proposal for historical trade and transmission service 
data. The specific filing requirements for this historical trade and 
transmission service data are set out in Secs. 33.3(d)(11) and 
33.3(d)(12).

F. Concentration Statistics and Related Matters

Background
    Under the Policy Statement, the final step of the competitive 
analysis screen is to assess market concentration. Applicants must file 
pre- and post-merger market concentration statistics calculated in 
accordance with the preceding sections. Both HHIs and single-firm 
market share statistics must be presented.
    The HHI statistics are compared with the thresholds given in the 
Guidelines.\62\ If the thresholds are not exceeded, no further analysis 
need be provided in the application. If an adequately supported screen 
analysis shows that the horizontal merger would not significantly 
increase concentration, and there are no interventions raising 
substantial concerns regarding the merger's effect on competition that 
cannot be resolved on the basis of the written record, the Commission 
does not look further at the effect of the merger on competition. If, 
however, the HHI statistics exceed the thresholds, the applicants must 
either propose mitigation measures that would remedy the merger's 
potential adverse effects on competition or address the other DOJ/FTC 
merger analysis factors.
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    \62\ The Policy Statement addresses three ranges of market 
concentration as described in the Guidelines: (1) An unconcentrated 
post-merger market--if the post-merger HHI is below 1000, regardless 
of the change in HHI the merger is unlikely to have adverse 
competitive effects; (2) a moderately concentrated post-merger 
market--if the post-merger HHI ranges from 1000 to 1800 and the 
change in HHI is greater than 100, the merger potentially raises 
significant competitive concerns; and (3) a highly concentrated 
post-merger market--if the post-merger HHI exceeds 1800 and the 
change in the HHI exceeds 50, the merger potentially raises 
significant competitive concerns; if the change in HHi exceeds 100, 
it is presumed that the merger is likely to create or enhance market 
power.
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    The NOPR solicited comment on the specific methods used to 
calculate market share and concentration statistics, especially the 
HHI.
Comments
    NASUCA argues that benchmarks such as the HHI index used for the 
determination of market power should not be based on present industry 
structure and price levels because these do not fully reflect 
competitive forces. The New York Commission argues the HHI analysis is 
not effective for evaluating market power because the HHI may not 
reflect ``unilateral market power.'' Furthermore, the HHI does not 
provide accurate results for determining the financial resources 
available to the merged firm in relation to the financial resources 
available to current and potential competitors in the industry. Midwest 
ISO Participants contend that an HHI analysis is not necessary if the 
total generation market share of the merging entities is 20-25 percent 
of the total generation that can supply the territory of the ISO to 
which they belong or have committed to join.
    APPA/Transmission Access Policy Study Group contends that recent 
experience in partially deregulated markets suggests that certain 
assumptions underlying the Commission's reliance on HHI statistics 
(i.e., (a) a relatively homogeneous product market, (b) a geographic 
market that can be defined consistent with a variety of products, and 
(c) a set of competitors, none of whom is artificially advantaged or 
disadvantaged in the future) are frequently invalid. Along with WEPCO, 
it suggests the Commission consider various situations in which public 
utility mergers could take place (e.g., stranded cost recovery, 
predatory pricing, and price discrimination).
    Indiana Consumer Counselor argues that HHI statistics do not fully 
capture a merger's effect on the merged firm's incentive to withhold 
capacity from the market. It argues the Commission should look at the 
size of the merged firm relative to the total generation that can 
supply a specific destination market, as well as the amount of excess 
capacity in the market. If the excess capacity from other suppliers is 
greater than the merged firm's capacity, any attempt by the newly 
merged firm to withhold generation would be disciplined by the excess 
capacity of other suppliers. Otherwise the merged firm would have 
incentive to withhold capacity regardless of whether the HHI statistics 
indicate a screen violation.
Commission Conclusion
    We recognize, as noted by commenters, that the HHI statistic is not 
a perfect or conclusive measure of a merger's competitive effect. While 
some commenters raise valid issues in regard to the HHI, we note that 
its usefulness is primarily as screening criteria. Should a proposed 
merger fail the screen, the Commission will look to additional factors 
in its determination of whether a proposed merger would adversely 
affect competition. Market participants should make the Commission 
aware of other factors because they are in a better position to 
identify those aspects of the market that are important to doing a 
competitive analysis. However, we also note that a violation of the 
Appendix A screen does not conclusively demonstrate that the horizontal 
aspect of a proposed merger would have anticompetitive consequences. If 
the screen is violated, the Commission will take a closer look at 
whether the merger would harm competition. If not, and no intervenors 
make a convincing case that the merger has anticompetitive effects 
despite passing the screen, the horizontal analysis stops there. The 
facts of each case (e.g., market conditions, such as demand and supply 
elasticity, ease of entry and market rules, as well as technical 
conditions, such as the types of generation involved) determine whether 
the merger would harm competition. When there is a screen failure, 
applicants must provide evidence of relevant market conditions that 
indicate a lack of a competitive problem or they should propose 
mitigation.\63\
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    \63\ Since the NOPR, we have had a significant number of cases 
where applicants have provided such evidence, and we encourage them 
to continue that practice. For example, in PECO/ComEd we noted that 
Applicants' screen failures occurred ``over a scattering of markets 
and time periods.'' 91 FERC para. 61,036 at 61,134. In NSP/New 
Century, Applicants attempted to isolate three potential sources of 
merger-related changes in concentration ``due to: (1) Combining 
NSP's and SPS's market shares; (2) changes in NSP's or SPS's market 
share due to joining the [Midwest ISO] or integrating directly; and 
(3) changes in the composition of relevant markets resulting from 
either integration plan, but not related to changes in NSP's or 
SPS's market shares.'' 90 FERC para. 61,020 at 61,129. In PECO/
ComEd, applicants argued that although the ComEd destination market 
was highly concentrated and the merger-related increase in 
concentration violated the Appendix A screen, they did not have the 
ability to withhold output because their generating units were 
almost entirely nuclear, making it difficult to ramp up or down. We 
agreed with this argument. In addition, we found that market 
conditions were not conducive to a profitable withholding strategy, 
since the relevant portion of the market supply curve was highly 
elastic for most hours of the year, so applicants had little 
incentive to withhold output.

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[[Page 71000]]

    The specific filing requirements for concentration statistics are 
set out in Sec. 33.3(c)(4) of the revised regulations.

G. Mitigation Measures and Analysis of Other Factors

Background
    In the NOPR the Commission proposed that in lieu of addressing the 
additional factors that would lessen concerns regarding the adverse 
competitive effect of a proposed merger, applicants may propose 
mitigation measures. In these proposals applicants must be specific and 
demonstrate the proposed measures adequately mitigate any adverse 
effects of the merger. Where such measures are proposed, the 
application must also include, to the extent possible, a separate 
analysis demonstrating the effect of the proposal on market 
concentration.
    Mitigation measures need not result in decreases in market 
concentration.\64\ Where such other measures are proposed, the 
application must include an analysis demonstrating how the proposed 
measure will ensure that the merger will not adversely affect 
competition in markets where the screen analysis shows a significant 
adverse effect on concentration.
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    \64\ For example, certain behavioral measures--in contrast to 
structural remedies such as divestiture--do not transfer control 
over resources from the merged company to an existing or new market 
participant. In such cases, the market shares of the merging 
companies would not change and, therefore, the merger would not 
change market concentration.
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    Where the competitive analysis screen yields concentration results 
that exceed the thresholds, but mitigation measures are not proposed, 
applicants must provide additional analysis. The Guidelines describe 
four additional factors to examine in situations where merger-induced 
concentration exceeds the specified thresholds.\65\ Based on the 
Guidelines, the Commission proposed in the NOPR that applicants 
evaluate the following four factors if the results of the screen 
analysis show that the concentration thresholds are exceeded: (1) The 
potential adverse competitive effects of the merger; (2) whether entry 
by competitors can deter anticompetitive behavior or counteract adverse 
competitive effects; (3) the effects of efficiencies that could not be 
realized absent the merger; and (4) whether one or both of the merging 
firms is failing and, absent the merger, the failing firm's assets 
would exit the market. These factors can be used to determine if a 
merger raises significant competitive concerns and, if so, whether 
there are countervailing considerations such that the merger is still 
consistent with the public interest.
---------------------------------------------------------------------------

    \65\ These factors are those discussed in steps two through five 
of the DOJ Guidelines.
---------------------------------------------------------------------------

    We proposed that the applicants' analysis of these additional 
factors be consistent with the standards discussed in the Guidelines. 
For example, the Guidelines require that in order to be considered an 
effective mitigating factor, entry must be timely, likely and 
sufficient in magnitude to deter or counteract the adverse competitive 
effects of concern.\66\ The Guidelines suggest that entry must occur 
within two years of the merger to be considered timely, and that all 
phases of entry must occur within the two-year period, including 
planning, design, permitting, licensing and other approvals, 
construction and actual market impact.\67\ We noted in the NOPR that 
given the current lead times for bringing new generation or 
transmission capacity on line, it is unlikely that entry can be a 
mitigating factor unless facilities are already in the planning or 
construction stages at the time of the application.\68\
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    \66\ Guidelines, 57 FR at 41,561.
    \67\ Id. at 41,561-562.
    \68\ For example, we found in Primergy that timely entry would 
not occur and thus was not a mitigating factor to the 
anticompetitive effects of the proposed merger. 79 FERC para. 61,158 
at 61,695-696.
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Comments
    Many commenters consider ISOs to be one means to mitigate market 
power concerns and barriers to market entry. They assert that ISOs 
support competitive electricity markets by offering: (1) Independent 
operation of the transmission grid, (2) expanded supply alternatives 
through the elimination of pancaked rates, (3) the ability to manage 
and eliminate transmission constraints, and (4) increased reliability. 
They further maintain that an ISO can simplify the analysis of a merger 
because the ISO can define the relevant market for screening purposes.
    Industrial Consumers share the belief that large regional ISOs can 
mitigate market power. However, it asserts that effective competition 
in the electric industry cannot occur while small, single-state ISOs 
exist, so it urges the Commission to toughen ISO conditions.
    APPA/TAPSG and the FTC Staff advocate structural remedies as 
mitigation measures, alleging that structural remedies are generally 
more effective and less costly to enforce than are behavioral remedies. 
Nonetheless, the FTC Staff acknowledges that there may be instances in 
which behavioral remedies, such as price caps, are appropriate. To 
ensure that a rate cap effectively reduces market power, the FTC Staff 
recommends the Commission require adjustments in rate caps over time to 
reflect anticipated changes in cost resulting from technological 
advancements.\69\ NRECA advocates structural remedies only in 
extraordinary circumstances.\70\ The Ohio Commission recommends the 
filing requirements request proposals for mitigation measures that 
consider factors such as the economic value of transmission reliability 
and alternatives to traditional power supply.
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    \69\ The FTC Staff comments that during periods of moderate 
inflation, a rate cap without an inflation adjustment may provide a 
rough substitute for a technology adjustment. The FTC Staff further 
says that in periods of deflation or substantial inflation, there 
would be greater reasons to differentiate the inflationary and 
technological effects on costs.
    \70\ NRECA defines extraordinary circumstances as including 
mergers above its moratorium threshold of 1,000,000 metered 
accounts, mergers of registered holding companies, and mergers of 
companies exhibiting excessive market power.
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    NARUC, as stated in its merger resolution, advocates disapproval or 
conditioning of proposed mergers that adversely affect generation 
competition. APPA/TAPSG recommends mandatory divestiture of generation 
when a merger would result in more than a de minimis increase in 
generation capacity concentration in a relevant market.
    Some commenters further advocate conditioning merger approval on: 
(1) The applicants' recognition that the Commission has authority to 
reopen and/or impose additional conditions; (2) transmission owners 
comparable treatment of themselves and their customers; and (3) the 
applicants' compliance with conditions prior to consummation of the 
merger.
    NASUCA, NARUC and the Ohio Commission urge the Commission to 
require horizontal merger applicants to propose a range of mitigation 
measures (e.g., join an ISO,\71\ behavioral rules, functional 
unbundling, structural

[[Page 71001]]

separation, divestiture) if their competitive analysis screen reveals 
the existence of post-merger market power above acceptable levels or 
discloses transmission constraints or other barriers to market entry by 
rivals. Such proposals would balance the full costs and benefits of the 
value of reliability and practical engineering of the network.
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    \71\ Ohio Commission also suggests that the regulations require 
that any mitigation measure involving an ISO that does not meet the 
minimum ISO criteria should be co-terminus with existing reliability 
council boundaries.
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    Ohio Commission further wants the filing regulations to require 
merger applicants to explain how they will eliminate or reduce pancaked 
rates, both inside and outside of their merged territories.
    WEPCO believes it is essential that applicants and intervenors know 
with specificity the Commission's requirements for both market power 
analysis and mitigation. WEPCO states that if requirements are not 
specified, applicants face second-guessing by intervenors or Commission 
staff on the grounds that some other form of analysis would produce 
different results. It is essential that questions about the data and 
methodology for performing the screen not become a basis for requiring 
hearings. Also, there needs to be guidance from the Commission that 
technical violations of the screen do not need to be mitigated if there 
is clear evidence that competition will not be injured.
    Antitrust Institute argues the Commission should view with 
skepticism any claims that a public utility merger will improve 
efficiency, because experience shows that most mergers fail to achieve 
the expected level of benefits. It recommends that the filing 
requirements place more of a burden on applicants making efficiency 
arguments in support of a merger. Antitrust Institute wants applicants 
to specify any discount rate used to quantify any benefits specified, 
including the component intended to apply to the increased riskiness of 
distant projections compared to near-term projections. It also wants 
stand-alone cost estimates based on the assumption that all prudent and 
reasonable steps to operate efficiently would be undertaken by each of 
the merging parties continuing to act as individual firms. Finally, 
Antitrust Institute wants any claimed benefits that are derived from 
capacity deferrals to be shown in terms of the present value of 
delaying capital costs less increases in fuel costs implied by the 
postponements.
    The Ohio Commission argues that merger savings should benefit 
jurisdictional ratepayers as well as shareholders and that applicants' 
proposed allocation of merger savings among wholesale and state-
jurisdictional customers should be disclosed in the merger application.
Commission Conclusions
    We believe the instructions on mitigation proposals as outlined 
above and in the NOPR will give the Commission the information it needs 
to analyze the impact of a proposed merger on the market, and we adopt 
them. As discussed above, these instructions include the requirement 
for further analysis demonstrating the effectiveness of proposed 
mitigation measures (regardless of whether they have a direct impact on 
concentration statistics). In addition, if concentration statistics 
exceed the thresholds and no mitigation proposals are made, applicants 
must provide analysis addressing the four additional factors described 
above.
    Regarding the concern we expressed in the NOPR that entry at the 
generation and/or transmission level may take more than two years to 
occur, we clarify that in order for entry to be considered an effective 
mitigating factor, entry must occur no later than two years from the 
date the merger is consummated. This could mean, as we noted in the 
NOPR, that some stages of entry (e.g., planning, approvals) must start 
before the merger is consummated.
    We agree with commenters who generally recognize RTOs as beneficial 
in mitigation proposals.\72\ RTOs can mitigate market power, eliminate 
rate pancaking and better manage grid congestion, thereby enlarging 
geographic markets. Our approval of some recent mergers recognized 
applicants' voluntary commitment to join Commission approved RTOs.\73\
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    \72\ After the issuance of the NOPR, the Commission amended its 
regulations under the FPA to facilitate the formation of Regional 
Transmission Organizations (RTOs). We required each public utility 
that owns, operates, or controls facilities for the transmission of 
electric energy in interstate commerce to make certain filings with 
respect to forming and participating in an RTO. The Commission 
codified minimum characteristics and functions that a transmission 
entity must satisfy in order to be considered an RTO. See Regional 
Transmission Organizations, Order No. 2000, 65 Fed. Reg. 809 (Jan. 
6, 2000), FERC Statutes and Regulations para. 31,089 (1999), order 
on reh'g, Order No. 2000-A, 90 FERC para. 61,201 (2000). The NOPR 
and comments received in response to the NOPR preceded Order No. 
2000. Because RTO requirements are more stringent than those of 
independent system operators (ISOs), we believe that comments 
submitted regarding the market power mitigation properties of ISOs 
apply equally to RTOs.
    \73\ See, e.g., CP&L/Florida Progress, and UtiliCorp/St. 
Joeseph.
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    We continue to believe that appropriate mitigation measures can 
alleviate concerns regarding a proposed merger's effect on the market. 
We do not believe that we should outline specific actions that 
applicants must take as mitigation if concentration statistics exceed 
the thresholds, as some commenters have suggested. As we discussed in 
the NOPR, the Policy Statement, and in many past merger orders, there 
are numerous mitigation measures that can be effective. However, the 
adequacy of specific mitigation proposals must still be investigated on 
a case-by-case basis.\74\
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    \74\ In regard to comments on increased efficiency claims, we 
reiterate that the burden is on applicants to demonstate that claims 
of increased efficiencies are valid. We will not rely on unsupported 
claims as effective mitigation.
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    Applicants must analyze how proposed mitigation will be effective. 
In addition, they must demonstrate the proposed mitigation measures 
will continue to be effective unless Applicants can show that other 
developments will make continuing mitigation unnecessary. As we 
discussed in the Policy Statement, we do not intend to rely on post-
merger review or on new remedies imposed after a merger is approved. 
Therefore, we will still entertain proposals by applicants to implement 
interim mitigation measures that would eliminate market power concerns 
during the period that it takes to put in place the long-term remedies 
necessary to address the anticompetitive effects of a proposed merger. 
Of course, the Commission can use its authority under section 203(b) of 
the FPA to further condition mergers if mitigation measures prove or 
become ineffective.
    The specific filing requirements concerning mitigation measures are 
set out in Sec. 33.3(e). The specific filing requirements for 
additional factors are set out in Sec. 33.3(f) of the revised 
regulations.

H. Merger Applications That Are Exempt From Filing a Competitive Screen

Background
    There are mergers where the filing of a full-fledged horizontal 
screen or vertical competitive analysis is not warranted because it is 
relatively easy to determine that they will not harm competition (e.g., 
one of the merging parties operates entirely on the East Coast and the 
other merging party operates entirely on the West Coast). For example, 
in Duke/PanEnergy we found that even though applicants had not 
performed a complete Appendix A analysis, the generating facilities of 
PanEnergy are so small and are located at such a great distance from 
Duke Power Company's market that

[[Page 71002]]

consolidating them is likely to have a negligible effect on market 
concentration.\75\
---------------------------------------------------------------------------

    \75\ Duke, 79 FERC at 62,037 (1997).
---------------------------------------------------------------------------

    Similarly, some mergers that only incidentally involve public 
utilities would not require a full-fledged competitive analysis. An 
example is when major financial firms that have power marketing 
subsidiaries change their ownership structure in some way.
    Therefore, with regard to horizontal mergers, a merger applicant 
need not provide the full competitive analysis screen if the applicant 
demonstrates the merging entities do not operate in the same geographic 
markets or, if they do, that the extent of such overlapping operation 
is de minimis. The Commission sought comments regarding the appropriate 
threshold for the de minimis test.
Comments
    The FTC Staff suggests the Commission remove or restrict its 
proposed de minimis exception to the filing requirements for 
geographically noncontiguous operations. The Commission should consider 
the possibility that mergers of geographically noncontiguous operations 
will nonetheless create competition problems. The FTC Staff recognizes 
the appeal of ``safe harbor'' provisions, or what the Commission refers 
to as abbreviated filing requirements, since they reduce the regulatory 
burden where anticompetitive effects are especially unlikely. However, 
the presence of abbreviated filing requirements create strong 
incentives for companies to portray acquisitions in such a way as to 
qualify for abbreviated filing requirements. In the FTC Staff's 
experience, it is important to seek independent verification of the 
information used to qualify for abbreviated filing requirements.
    The FTC Staff itself recognizes certain classes of transactions 
that are exempted from reporting because, based on the FTC Staff's 
experience, they are not likely to harm competition. But, where that 
cannot be determined, merging companies should submit a basic amount of 
information.
    NRECA comments that the appropriate de minimis test is not merely 
the extent of geographic overlap. Noncontiguous horizontal mergers, it 
points out, can have substantial adverse effects on competition. NRECA 
lists the following examples: regulatory evasion, control of critical 
regional transmission interfaces, and other characteristics.
    If one or more merger applicants controls a constrained 
transmission interface, NRECA states, the critical market may be a 
relatively small market area. Market dynamics are such that two non-
contiguous merging companies could control generation resources on 
either side of a constraint and could use that control to their 
financial advantage. Absent such a constraint, NRECA states, geographic 
overlap is less relevant as a stand-alone determinant of potential 
market dominance in an open access market.
    Sempra proposes that if an application meets certain conditions 
suitable for abbreviated filing requirements, the applicants would be 
entitled to a rebuttable presumption that the merger or disposition is 
consistent with the public interest and should receive approvals within 
90 days of filing the application.
    Finally, Missouri Commission notes that by proposing safe harbor 
treatment (i.e., abbreviated filing requirements) of certain mergers, 
the NOPR anticipated that a merger could proceed to approval even 
without all the information it stated was required for its review. 
This, in its view, incorrectly shifts the burden of proof from 
applicants to intervenors, contrary to section 203 of the FPA. Missouri 
Commission concludes the Commission should ensure that merger 
applicants produce nothing short of the best and most complete data, 
that the data are subject to check, and that gaps in data and analysis 
are filled.
Commission Conclusion
    We agree with commenters that the Commission must consider whether 
merger applications qualify for review under abbreviated filing 
requirements. There will be cases that seem to qualify, such as those 
where geographic market overlap among merging entities is minimal or 
non-existent, but which require further analysis. We are aware that 
even though merging firms might not currently compete in common 
geographic markets, one firm might reasonably be perceived as a 
potential competitor in a market in which the other firm competes.\76\ 
Under these circumstances, the Commission would be unlikely to consider 
merger applications for review under the abbreviated filing 
requirements. However, we would not reach such a conclusion without 
examining the specifics of each case. Moreover, the Commission has 
demonstrated that it is concerned about cases that involve a vertical 
combination of generation and transmission assets even if there is 
little or no overlap between generation activities.\77\ The Commission 
can also ensure that abbreviated filing requirements are appropriate by 
requesting additional information from the applicants when deemed 
necessary. As a result of the foregoing considerations, we will not 
require a merger applicant to provide the full competitive analysis 
screen if: (1) The applicant demonstrates that the merging entities do 
not currently operate in the same geographic markets, or if they do, 
that the extent of such overlapping operation is de minimis; and (2) no 
intervenor has alleged that one of the merging entities is a perceived 
potential competitor in the same geographic market as the other.\78\
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    \76\ A firm may exert a salutary influence on behavior in a 
market without actually competing in it. See e.g., FTC v. Proctor & 
Gamble Co. 386 U.S. 568 (1967); U.S. v. Falstaff Brewing Corp., 410 
U.S. 426 (1973).
    \77\ See, e.g., AEP/CSW, NSP/New Century, and CPL/Florida 
Progress.
    \78\ We understand that, in responding to interventions raising 
concerns about perceived potential competition, applicants may find 
it necessary to submit data on their market strategies. We 
appreciate the commercial sensitivity of information pertaining to 
applicants' market strategies, and the concern applicants may have 
about possible disclosures of this information to competitors. 
Applicants are free to claim confidentiality for this information, 
we will presume that this information falls within the exemption 
from public disclosure under the Freedom of Information Act for 
``trade secrets and commercial or financial information obtained 
from a person and privileged or confidential.'' 18 CFR 
388.107(d)(2000). If parties seek access to this information, and we 
determine that limited disclosure is necessary to satisfy the due 
process rights of intervenors to challenge relevant evidence relief 
upon by the applicants, we will allow such access to parties' 
attorneys and experts only under the terms of an appropriate 
protective order. See, e.g., model protective order at 
www.ferc.fed.us/alj/index.html. Such a protective order would 
prevent broader dissemination or use of the sensitive information 
for business purposes or commercial advantage.
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    Furthermore, we will not require section 203 applicants to provide 
a competitive analysis under Secs. 33.3 or 33.4 of the regulations if: 
(1) The application is a specific RTO filing that directly responds to 
Order No. 2000; (2) the transaction is simply an internal corporate 
reorganization; or (3) the transaction only involves a disposition of 
transmission facilities.\79\ Our decision not to require RTO 
applications to provide a competitive analysis is consistent with our 
strong belief that participation in RTOs is pro-competitive. Moreover, 
the standards set forth in Order No. 2000 require

[[Page 71003]]

extensive information from RTO applicants that we believe will 
demonstrate whether the proposal is in the public interest. It also has 
been our experience that anticompetitive effects are unlikely to arise 
with regard to internal corporate reorganizations or transactions that 
only involve the disposition of transmission facilities.
---------------------------------------------------------------------------

    \79\ We clarify that by exemption, we mean that an applicant 
need not tender a competitive analysis with its filing. If the 
Commission determines that a filing raises competitive issues 
nonetheless, the Commission will evaluate those issues and direct 
the applicant to submit any data that the Commission determines is 
necessary to satisfy its concerns.
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VI. Guidelines for Vertical Competitive Analysis

A. General Vertical Issues

Background
    We noted in the Policy Statement that we intended to analyze 
mergers between public utilities and firms that provide inputs for 
electricity generation (``vertical'' mergers).\80\ We also note that 
the same merger may have both horizontal and vertical aspects.
---------------------------------------------------------------------------

    \80\ Policy Statement at p. 30,113.
---------------------------------------------------------------------------

    Since the Policy Statement was issued, the Commission has acted on 
a number of vertical mergers.\81\ These mergers involved the 
combination of interests in electric generation and gas assets or the 
combination of interests in electric generation and transmission 
assets. The Commission has developed a basic approach for assessing 
whether a vertical merger is likely to adversely affect competition in 
electricity markets. This approach has been informed by the DOJ/FTC 
approach to evaluating vertical mergers and by the analytic framework 
described in the Policy Statement. In the NOPR, we proposed an analytic 
approach and the filing requirements to support it.
---------------------------------------------------------------------------

    \81\ See e.g., Enova, AEP/CSW, Dominion/CNG, Long Island 
Lighting Co. 82 FERC para. 61,214, reh'g denied, 83 FERC para. 
61,076 (1988) (LILCO), NorAm, Duke/PanEnery, PG&E Corporation and 
Valero Energy Corporation, 80 FERC para. 61,041 (1997) (PG&E/
Valero); Destec Energy, Inc. and NGC Corporation, 79 FERC., para. 
61,373 (1997) (Destec/NGC); Enron Corporation, 78 FERC & 61,179 
(1997) Enron.
---------------------------------------------------------------------------

    The Commission proposed to streamline this vertical analytic 
approach and establish abbreviated filing requirements and limitations 
on the scope of our review. This proposal would reduce the number of 
applications that will require a complete analysis of the vertical 
aspects of a proposed merger. For example, a merger cannot impair 
competition in ``downstream'' electricity markets if it involves an 
input supplier (the ``upstream'' merging firm) that sells: (1) An input 
that is used to produce a de minimis amount of the relevant product, or 
(2) no product into the downstream electricity geographic market. If 
such a showing is made, an applicant will not be required to file 
additional information regarding the vertical aspects of a proposed 
merger.
    The NOPR discussed establishing filing requirements for the 
vertical competitive analysis that have counterparts in the horizontal 
screen analysis, such as defining relevant downstream geographic 
markets using a delivered price test. Filing requirements for other 
parts of the vertical analysis, such as defining upstream geographic 
markets, were set forth in more general terms. We solicited comments on 
both the reasonableness of the analytic approach and the adequacy of 
the information required.
Comments
    EEI suggests circumstances in which a full competitive analysis is 
not required: where storage of the upstream product prevents the 
supplier from targeting price increases for specific seasonal periods; 
the price of the upstream product is constrained by substitutes; the 
upstream supplier supplies only minimal shares; or parties have no 
significant involvement in generation.
Commission Conclusion
    As we said in the NOPR, there will be cases of vertical mergers in 
which a full vertical competitive analysis is not required. For 
example, as EEI states, and as we have concluded in previous merger 
cases, if applicants have no significant involvement in generation, the 
applicants might be able to demonstrate a lack of competitive harm 
without completing a full vertical competitive analysis.\82\ In this 
final rule, the Commission establishes certain abbreviated filing 
requirements and limitations on the scope of our review with respect to 
vertical merger applications.\83\ This should reduce the number of 
applications that will require a complete analysis of the vertical 
aspects of a proposed merger involving a jurisdictional public utility.
---------------------------------------------------------------------------

    \82\ See, Illinova Corporation and Dynergy Inc., 89 FERC para. 
61,163 (1999).
    \83\ These specific filing requirements are set forth in 
Sec. 33.4 of the revised regulations.
---------------------------------------------------------------------------

    In cases where more complete information is necessary for the 
Commission to determine the competitive effects of a vertical merger, 
we are adopting a four-step analysis: (1) Define the relevant products 
traded by the upstream and downstream merging firms; \84\ (2) define 
the relevant downstream and upstream geographic markets; (3) evaluate 
competitive conditions using market share and concentration HHI 
statistics in the respective geographic markets; and (4) evaluate the 
potential adverse effects of the proposed merger in these markets and, 
if appropriate, other factors that can counteract such effects, 
including ease of entry by competitors into either the upstream market 
or the downstream market and merger-related efficiencies.
---------------------------------------------------------------------------

    \84\ There may be several relevant upstream input products (such 
as fuel, transportation and turbine manufacturers).
---------------------------------------------------------------------------

B. Vertical Analytic Guidelines--Introduction

    As discussed earlier, we are concerned as to whether mergers will 
adversely affect competition in electricity markets, which can result 
in higher prices or reduced output. Horizontal mergers can achieve this 
by eliminating a market competitor and allowing the exercise of market 
power by the newly merged firm. Vertical mergers do not directly 
eliminate a competitor, but may create or enhance the incentive and/or 
ability for the merged firm to adversely affect prices and output in 
the downstream electricity market and to discourage entry by new 
generators.\85\ This effect can be brought about by: (1) Foreclosure/
raising of rivals' costs; (2) facilitating coordination; and (3) 
regulatory evasion.\86\
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    \85\ Horizontal mergers may give rise to a higher market share 
for the merged entity and increase concentration in the market. 
Market share and concentration are not directly affected by a solely 
vertical merger.
    \86\ See Enova, 79 FERC para. 61,372 at 62,560.
---------------------------------------------------------------------------

Foreclosure/Raising Rivals' Costs

Background
    A merger between an entity that owns downstream electric generation 
and one that supplies upstream inputs to electric generation to 
competitors of the downstream firm may create or enhance the incentive 
and/or ability for the upstream firm to restrict access to these inputs 
to downstream competitors. This can be accomplished through pricing, 
marketing and operational actions that raise the input costs of 
downstream competitors of the newly merged firm or by otherwise 
restricting such competitors' input supply.\87\ Raising rivals' costs 
can also deter entry of rival generators in the downstream market.\88\ 
A vertical merger can create or enhance the incentive and ability of 
the merged firm to adversely affect electricity prices or output in the 
downstream market by raising rivals' input costs if market power could 
be exercised in both the upstream and downstream geographic

[[Page 71004]]

markets. Under these circumstances, generators purchasing from the 
upstream merging firm might not be able to turn to alternative 
suppliers to avoid an increase in input prices. Similarly, customers of 
the merging downstream firm might not be able to turn to alternative 
electricity suppliers to avoid an increase in electricity prices. The 
Commission requested comments on the extent to which vertical mergers 
can result in foreclosure or ``raising rivals costs'' problems.
---------------------------------------------------------------------------

    \87\ Foreclosure can also result from a vertical merger if the 
downstream merging firm refuses to purchase from input suppliers 
other than its upstream affiliate.
    \88\ See, Enova, 79 FERC para. 61,372 at 62,560.
---------------------------------------------------------------------------

Comments
    Several parties want to eliminate the need for a detailed vertical 
analysis once it becomes clear that merging firms lack the ability to 
raise rivals' costs. For example, EEI states that when a downstream 
firm has easy access to alternative suppliers of natural gas or a dual-
fired generation facility has low-cost fuel oil alternatives, the 
upstream firm has no market power. Similarly, Southern points out that 
a large number of natural gas storage facilities can protect against a 
withholding of natural gas services by suppliers. In either case, the 
analysis should stop, since it is clearly demonstrated the merged party 
has no ability to raise rivals' costs, even if it has the incentive.
Commission Conclusion
    The Commission is sensitive to the burden imposed on applicants and 
intervenors by the merger filing process, which is why it has proposed 
abbreviated filing requirements in certain cases where a merger is 
unlikely to adversely affect prices or output. Because the details of 
particular cases can differ considerably, the Commission has reviewed 
and will continue to review mergers on a case-by-case basis. This 
allows cases that will not adversely affect prices or output to be 
approved quickly. However, a well-supported quantitative analysis is 
required to provide evidence of a proposed merger's lack of competitive 
impact. This is especially necessary in cases where applicant sets 
forth mitigating circumstances. Furthermore, this avoids delays in 
examining mergers because we are less likely to need additional data 
after the application is filed. As a result, we adopt in this Rule the 
proposals set forth in the NOPR.

Facilitating Anticompetitive Coordination

Background
    A vertical merger can facilitate anticompetitive coordination \89\ 
in either the upstream or downstream markets if the merger either: (1) 
Creates or enhances the ability of competing firms to agree to raise 
prices or restrict output or (2) dampens the incentive for firms to 
compete aggressively on price or service. In addition, anticompetitive 
coordination can occur if information that would facilitate coordinated 
behavior is shared between the upstream firm and its customers, and 
there are substantial transactions between the upstream merging firm 
and non-affiliated customers.\90\
---------------------------------------------------------------------------

    \89\ ``Anticompetitive coordination'' refers generally to the 
exercise of market power through the concurrence of other (non-
merging) firms in the market or on coordinated responses by those 
firms. See supra note 9. We emphasize that in the electric utility 
industry, the terms ``coordination'' and ``Coordinating activities'' 
have specific meanings. For example, coordinating with other firms 
in downstream electricity markets in the creation of regional 
transmission organizations would not raise competitive concerns. The 
Commission has also long encouraged technical coordination in order 
to promote reliability.
    \90\ One example of potential anticompetitive coordination is 
the anticompetitive exchange of information. If the downstream 
merging firm obtains price quotes and other sensitive competitive 
information from other (non-merging) upstream suppliers it could 
transfer that information to its upstream merging partner. The 
exchange of such information among upstream input suppliers can be 
potentially useful in agreeing to raise prices or restrict output to 
all downstream customers.
---------------------------------------------------------------------------

    The Commission is aware that the mechanisms through which a 
vertical merger could facilitate anticompetitive coordination and the 
conditions under which such coordination would result in competitive 
harm are complex and subject to debate. We solicited comments on 
anticompetitive coordination and how, or if, it should be addressed in 
the analysis.
Comments
    The FTC Staff suggests that since firms have little incentive to 
accurately estimate their own abilities to engage in anticompetitive 
conduct, their analyses should be validated independently. However, 
Southern states the Commission should not be concerned about 
anticompetitive conspiracies, since the Sherman Act already makes such 
anticompetitive behavior illegal. These statements were echoed by EEI, 
saying that true coordination problems occur in only limited 
circumstances and thus may not be worth our concern.
Commission Conclusion
    We disagree with Southern's assertion that the Commission should 
not be concerned with anticompetitive coordination. We are statutorily 
required to protect the public interest, and the courts have held that 
our authority under the FPA carries with it the responsibility to 
consider anticompetitive effects of regulated aspects of utility 
operations, and to give reasoned consideration to the bearing of 
competition policy on jurisdictional matters.\91\ Therefore, it is 
important to preserve the Commission's ability to collect information 
so it can evaluate the possibility of anticompetitive coordination. As 
a result, we adopt in this Rule the proposals set forth in the NOPR.
---------------------------------------------------------------------------

    \91\ See, e.g., Gulf States Utilities v. FPC, 411 U.S. 747 
(1973) reh'g denied, 412 U.S. 944 (1973); and Alabama Power Co., et 
al., v. FPC, 511 F.2d 383 (DC Cir. (1974)).
---------------------------------------------------------------------------

    The Commission acknowledges the FTC Staff's concerns that 
incentives exist for applicants to understate their ability to engage 
in anticompetitive behavior. Similarly, we also recognize the tendency 
for intervenors to overstate the potential for anticompetitive behavior 
on the part of prospective merging parties. These are additional 
reasons why the Commission believes it is important to examine section 
203 transactions on a case-by-case basis. This affords the opportunity 
to review competitive analyses presented by both sides and to make our 
decisions based on the best possible information and analysis.

Regulatory Evasion

Background
    In the NOPR, the Commission solicited comments on the potential for 
vertical mergers to result in regulatory evasion. For example, after 
merging with an upstream input supplier, a downstream electric 
utility's input purchases would be ``internal'' to the firm. The 
merger, therefore, may create the incentive for the merging upstream 
input supplier to inflate the transfer prices of inputs sold to the 
downstream regulated utility if it can evade regulatory scrutiny. 
Profits would increase for the vertically-integrated firm, but would 
accrue to the unregulated affiliate. Higher electricity prices could 
result from such a strategy.
    In the NOPR, we also solicited comments on our proposed treatment 
of mergers in which regulatory evasion is a concern and how ongoing 
changes in the industry, such as the development of regional 
transmission organizations and retail access, might affect our 
approach.
Comments
    EEI argues the Commission should not be concerned about regulatory 
evasion because it is a retail issue. It states that in a deregulated 
wholesale power market regulatory evasion is not

[[Page 71005]]

an issue.\92\ Where downstream prices are determined by the market, 
rather than cost-based regulation, the downstream firm cannot increase 
its profits by charging itself excessive transfer prices for inputs. 
Further, as various regions of the country implement regional 
transmission organizations, regional tariffs and retail access, 
regulatory evasion by the transmission provider will become more 
difficult. Thus, according to EEI, the potential for regulatory evasion 
is diminishing. Southern Company raises similar arguments.
---------------------------------------------------------------------------

    \92\ Regulatory evasion could effect requirements service 
customers in wholesale electricity markets. However, this is less 
likely to be a concern if wholesale markets are competitive.
---------------------------------------------------------------------------

    However, NRECA remarks regulatory evasion will occur increasingly 
as merged utilities cover large numbers of states and encompass a wider 
scope in the energy industry and as merged companies seek the shelter 
of regulatory gaps.
    NRECA comments the risk of regulatory evasion is not restricted to 
vertical mergers. NRECA explains the AEP and CSW merger illustrates 
opportunities for regulatory evasion that ``pit state regulators 
against the Commission.'' \93\ It also believes that in the past, the 
Commission has deferred to state regulators to address retail market 
power issues, even where it is known that those states do not intend to 
inquire into the merger's possible adverse effects on competition. The 
Commission's policy, according to NRECA, is to avoid review of retail 
market effects, absent a direct plea from the state to do so. It 
asserts that this fails to satisfy the Commission's public interest 
mandate. NRECA also says that state regulators are unlikely to take the 
political risks associated with admitting a lack of authority or 
inviting the Commission into retail market analysis. Where the state 
lacks the interest or resources to review the competitive effects of 
mergers, or where the merger applicant has sufficient political clout 
to limit state review, the retail market effects of proposed mergers 
are essentially beyond any government review.
---------------------------------------------------------------------------

    \93\ NRECA at 25. In the merger as originally proposed, eleven 
states were directly affected, yet, says NRECA, the merging parties 
asserted that only four states (all within CWS's territory) had 
clear authority to approve or reject the merger.
---------------------------------------------------------------------------

    Where regulatory evasion is a concern and a merger fails the 
competitive analysis screen, NRECA favors conditioning approval of the 
merger on effective structural mitigation. It believes that it is 
critical, where the Commission decides to condition a merger on ISO 
participation, that the ISO be an established one, not one that is 
merely being discussed or proposed. Also, large mergers can create 
single companies that are larger than the proposed ISO in the relevant 
region, which could allow the merged company to use its position to 
control prices.
Commission Conclusion
    As noted earlier, regulatory evasion can affect retail electricity 
prices. However, consistent with our position taken in the Policy 
Statement, the Commission does not intend to address regulatory evasion 
concerns that affect retail electricity prices unless a state lacks 
adequate authority to consider such matters and requests us to do 
so.\94\ NRECA explains that certain mergers create opportunities for 
regulatory evasion of state authority. We maintain that the state 
commissions are the more appropriate forum to address these issues.
---------------------------------------------------------------------------

    \94\ Policy Statement at 30,128.
---------------------------------------------------------------------------

C. Merger Applications That Are Exempt From Filing a Full Vertical 
Analysis

Relevant Products (Inputs) Supplied by the Upstream Merging Firm Are 
Used To Produce a De Minimis Amount of the Relevant Downstream Products

Background
    As discussed earlier, there are instances in which only minimal 
information and analysis would be necessary to confirm that a vertical 
merger poses no competitive concern. One such instance is when the 
upstream merging firm sells a product that is used to produce only a de 
minimis amount of the relevant product in the downstream geographic 
market. The Commission expects that vertical mergers that fall into 
this category will be relatively easy to identify. An example is when 
the upstream merging firm supplies one energy source, but almost all of 
the energy in the downstream market is produced from generating 
capacity which uses a different energy source. In cases similar to 
this, a vertical merger should pose no competitive concern.\95\
---------------------------------------------------------------------------

    \95\ See, Duke/PanEnergy, 79 FERC para. 61,236 at 62,039.
---------------------------------------------------------------------------

    The Commission proposed that applicants desiring to make such a 
showing identify products sold by the upstream and downstream merging 
firms and identify the suppliers in the downstream market (by type of 
generation, e.g., gas-fired, coal-fired, etc.) that could compete with 
the downstream merging firm in providing downstream products. When 
identifying the downstream suppliers, it is necessary to determine 
whether customers affected by the merger could turn to alternative 
suppliers in the event of a post-merger price increase. The Commission 
additionally proposed that applicants define the downstream geographic 
market. As we stated in the NOPR, because of the wide variety of 
factual scenarios presented in merger applications, we did not propose 
thresholds for the proportion of output in the downstream geographic 
market that is accounted for by the inputs sold by the upstream merging 
firm or other ``bright line'' tests for such de minimis determinations.
Comments and Commission Conclusions
    No specific comments were received on this issue, although comments 
regarding ``Merger Applications That are Exempt from a Competitive 
Screen'' (Section V.H) and ``Vertical Analytical Guidelines'' (Section 
VI.B) apply in this case. Based on the discussion in these sections, we 
adopt the NOPR requirements relating to this component of the vertical 
competitive analysis. However, to ensure the analysis provided by 
applicants supports a showing that a proposed merger qualifies for 
abbreviated filing requirements, we will additionally require that.\96\ 
(1) The applicant demonstrates that the merging entities do not 
currently operate in the same geographic markets, or if they do, that 
the extent of such overlapping operation is de minimis; and (2) no 
intervenor has alleged that one of the merging entities is a perceived 
potential competitor in the same geographic market as the other.
---------------------------------------------------------------------------

    \96\ See supra note 29.
---------------------------------------------------------------------------

The Upstream Merging Firm Does Not Sell Products in the Relevant 
Geographic Market in Which the Downstream Merging Firm Resides

Background
    A vertical merger involving an upstream firm that does not sell 
into the relevant downstream geographic market would not affect 
competition in that market. The Commission proposed that applicants 
desiring to make such a showing identify: (1) The products sold by the 
upstream and downstream merging firms; (2) all downstream suppliers who 
purchase inputs from the upstream merging firm; and (3) determine if 
those downstream suppliers compete with the merging firm to supply 
downstream products. For these abbreviated filing requirements, we 
proposed applicants

[[Page 71006]]

must justify their analyses and provide all supporting data and 
documentation.
    We solicited comments on the reasonableness and efficacy of the 
proposed abbreviated filing requirements provisions; approaches to 
approximating the downstream geographic market; and appropriate de 
minimis thresholds for the amount of downstream output produced by 
inputs sold by the upstream merging firm.
Comments and Commission Conclusion
    As in the previous section, no specific comments were received for 
this issue, although comments summarized regarding ``Merger 
Applications That are Exempt from a Competitive Screen'' (Section V.H) 
and ``Vertical Analytical Guidelines'' (Section VI.B) apply in this 
case. Based on the discussion in these sections, we adopt the NOPR 
requirements, as relating to this component of the vertical competitive 
analysis. However, to ensure that the analysis provided by applicants 
supports a showing that a proposed merger qualifies for abbreviated 
filing requirements, we will additionally require that: \97\ (1) 
Applicants demonstrate that the merging entities do not currently 
operate in the same geographic markets, or if they do, that the extent 
of such overlapping operation is de minimis; and (2) no intervenor has 
alleged that one of the merging entities is a perceived potential 
competitor in the same geographic market as the other.
---------------------------------------------------------------------------

    \97\ See supra note 29.
---------------------------------------------------------------------------

D. Components of the Analysis as Proposed in the NOPR

Relevant Products and Relevant Geographic Market

Background
    In this section we first discuss the methods of identifying the 
relevant products and defining the relevant geographic market as set 
forth in the NOPR.

Downstream Market

    We proposed that applicants be required to identify and define the 
relevant products sold in the downstream electricity market affected by 
current and prospective business activity of the upstream merging firm. 
We sought comments on how, if at all, our approach for defining 
relevant products in the downstream market should differ from that used 
for horizontal mergers. We also asked for comments on any alternative 
approaches. No specific comments were offered, although all the 
horizontal ``Relevant Products'' comments apply to the downstream 
markets in a vertical case.

Upstream Market

    We proposed that applicants must identify the products produced by 
the upstream merging firm and used by the downstream merging firm and/
or its competitors in the production of relevant downstream electricity 
products. Upstream products can be grouped together whenever they are 
good substitutes for each other from the buyer's perspective. Products 
may also be differentiated with respect to time, since supply and 
demand conditions vary considerably over the year.
    We also proposed the relevant products identified by the applicant 
must be explained and well-documented. The Commission sought comments 
on the proposed approach, any alternative approaches to defining 
relevant input products, and how such approaches will vary for 
different types of inputs.

Geographic Markets--Downstream Market

    Defining the downstream geographic market consists of identifying 
the customers potentially affected by the merger and the suppliers that 
can compete with the merging firm to supply a relevant electricity 
product. In the regulations for the horizontal screen analysis, 
relevant geographic electricity markets are defined using the delivered 
price test and if applicants so choose, additional methods that are 
adequately supported. Under the delivered price test, a supplier is 
considered to be in the market if it has generating capacity from which 
energy can be made available and delivered to the market at a price, 
including transmission and ancillary services, no more than five 
percent above the market price.
    In the NOPR, the Commission proposed that the relevant downstream 
geographic market in a vertical merger would be defined similarly to 
those in the proposed regulations for the horizontal analytic 
framework. However, we sought comments on the appropriateness of the 
delivered price test analysis for analyzing downstream markets in 
vertical mergers. We also solicited comments on any alternative 
approaches to defining downstream geographic markets in a vertical 
merger.

Geographic Markets--Upstream Market

    In the NOPR, the Commission did not propose precise filing 
requirements for defining upstream geographic markets. One reason was 
that the Commission had not yet acted upon an application for a merger 
with vertical aspects that required a rigorous definition of the 
upstream geographic market. Another reason was that the types of 
analysis and data needed to define geographic upstream markets may vary 
from input to input. The Commission expected to better understand the 
data and analysis needed to define geographic input markets--if such 
analysis proved necessary--as we evaluated proposed vertical mergers. 
Until such time, the Commission proposed that applicants approximate 
the upstream geographic market for each relevant upstream product and 
submit data and documentation necessary to support their analyses. Such 
approximate definitions of the upstream geographic market could be 
based on historical trade data. We proposed that applicants define the 
smallest reasonable geographic markets.
    We proposed that applicants fully explain, justify and document 
their analysis, including all supporting data and documentation. We 
sought comment on appropriate approaches to defining upstream 
geographic markets in vertical mergers.
Comments and Commission Conclusion
    No specific comments were submitted with respect to relevant 
products and geographic markets in a vertical analysis. However, 
comments on horizontal ``Relevant Geographic Markets'' apply to 
downstream markets when considering a vertical analysis. We also note 
that the Commission has provided guidance on defining upstream relevant 
geographic markets involving mergers of companies with interests in 
generation and delivered gas in Dominion. Accordingly, as discussed in 
this section, we adopt the NOPR requirements. The filing requirements 
for this aspect of the analytic framework are set forth in 
Secs. 33.4(c)(1) and 33.4(c)(2) of the revised regulations.

Evaluating Competitive Conditions in Geographic Markets

Upstream Market

Background
    The NOPR proposed that Applicants assess competitive conditions in 
the upstream market by calculating market shares for each supplier and 
market concentration using the HHI statistic. Upstream geographic 
markets that are ``highly concentrated'' under the Guidelines standard 
(i.e., an HHI of 1800 or above) are considered to be conducive to the 
exercise of market power and therefore warrant additional analysis. We 
sought comments on this approach to assessing market shares and

[[Page 71007]]

concentration in the upstream market, along with any alternative 
approaches.
Comments
    EEI suggests the Commission find that an upstream merging firm has 
no ability to raise input prices for rival generators in cases where 
either the HHI statistic is less than 1800 or the firm's upstream 
market share is less than twenty percent. In either instance, it 
suggests the Commission require no further analysis.
Commission Conclusion
    We adopt the proposals set forth in the NOPR. We note, however, 
that a certain degree of discretion is necessary in evaluating merger 
proposals. We are not persuaded by EEI's argument that we should 
conclude that the merged firm can not raise rivals' costs if the 
upstream merging firm's market share is less than twenty percent. The 
Commission expects analyses to provide adequate information with which 
to judge the merger's competitive effect. The specific filing 
requirements for assessing the competitive conditions in the upstream 
market are set forth in Sec. 33.4(c)(3)(ii) of the requirements.

Downstream Market

Background
    We proposed that once the downstream geographic market has been 
defined, applicants assess competitive conditions by calculating market 
shares for the suppliers identified in the delivered price test and 
using them to compute the HHI market concentration statistic.
    The NOPR also proposed the Commission require that for a vertical 
merger, downstream market share statistics reflect the ability of 
buyers in the downstream market to switch--in response to a price 
increase--from generation served by the upstream merging firm. 
Specifically, applicants would identify the upstream suppliers who sell 
or deliver inputs to each generating unit or plant in the downstream 
geographic market. All generation capacity served by the same input 
supplier would be considered together and therefore be assigned a 
market share, i.e., treated as if it were owned or controlled by a 
single firm.\98\
---------------------------------------------------------------------------

    \98\ See, Enova, 79 FERC para. 61,372 at 62,562. If multiple 
upstream suppliers serve a single generating plant or unit, 
applicants' analysis must take this into account.
---------------------------------------------------------------------------

    While the Commission has not explicitly required HHI statistics for 
relevant geographic markets in prior vertical merger cases, the HHI 
statistic is, along with market share, a generally accepted indicator 
of competitive conditions in a relevant market.\99\ As a general 
matter, markets that are ``highly concentrated'' under the Guidelines 
standard (i.e., an HHI of 1800 or above) are considered to be conducive 
to the exercise of market power and, therefore, warrant additional 
analysis.\100\ We sought comments on this approach to assessing market 
shares and market concentration in the downstream market, along with 
any alternative approaches.
---------------------------------------------------------------------------

    \99\ The DOJ 1984 Merger Guidelines address vertical mergers and 
discuss both market share and HHI statistics. See DOJ 1984 Merger 
Guidelines at 46.
    \100\ The DOJ 1984 Merger Guidelines use a ``highly 
concentrated'' market as a threshold for further investigating the 
competitive effect of a vertical merger. See DOJ 1984 Merger 
Guidelines at 46. Because concentration thresholds are indicators 
that additional investigation is warranted, the Commission proposed 
to look further at mergers with an HHI near 1800 or above.
---------------------------------------------------------------------------

Comments
    EEI comments that in some cases upstream markets may not display 
the characteristics they suggest and it would be necessary also to 
evaluate downstream geographic markets. They suggest that the capacity 
of generators be attributed to the suppliers of the upstream input only 
for upstream firms that have both the incentive and ability to bring 
about a price increase for the input. For example, non-vertically 
integrated firms cannot gain from higher generation prices as a 
consequence of raising the price of inputs. This may overstate market 
concentration and point to a market power problem that does not exist.
Commission Conclusion
    We adopt the proposals set forth in the NOPR. Concerning EEI's 
comment regarding generation attribution, we note that the method 
proposed is a reasonable way--in the case of mergers involving the 
combination of generation and delivered gas supply--to portray the 
existing arrangements between upstream delivered gas suppliers and 
generators in the downstream relevant market. We agree with EEI that it 
is important ultimately to determine whether the merged firm will have 
the ability and incentive to adversely affect prices or output. 
However, this analysis is logically performed after a structural 
assessment of the downstream and upstream markets is complete. In fact, 
the Commission routinely evaluates the structural characteristics of 
upstream and downstream relevant markets and then goes on to consider 
additional factors pertaining to whether the merged firm would have the 
ability and incentive to adversely affect prices and output.
    We also note that a number of important considerations in 
evaluating downstream markets have arisen in recent merger cases. For 
example, in AEP/CSW \101\ we found that applicants had not properly 
modeled the possible vertical foreclosure scenarios in which AEP or CSW 
could use its transmission system to frustrate competition. We agreed 
with intervenors that, by looking only at suppliers that were ``first-
tier'' to one applicant and buyers that were ``first-tier'' to the 
other applicant, the applicants excluded many foreclosure scenarios. 
Moreover, by looking only at the least-cost contract path, applicants 
ignored foreclosure scenarios. Their analysis focused solely on whether 
the merger created the incentive to increase prices, thus ignoring 
cases where the merger enhanced that incentive and cases where the 
merger created or enhanced the ability to raise prices. Applicants 
concluded that because the change in market concentration under a 
particular foreclosure scenario did not exceed the horizontal merger 
standard, the merger did not create or enhance vertical market power. 
However, as we explained in Dominion, the market concentration level, 
as opposed to the change in market concentration, is the relevant 
measure, since highly concentrated upstream and downstream markets are 
necessary, but not sufficient, conditions for a vertical foreclosure 
strategy to be effective.
---------------------------------------------------------------------------

    \101\ See, American Electric Power Company, 90 FERC para. 
61,242.
---------------------------------------------------------------------------

    The specific filing requirements for assessing the competitive 
conditions in the downstream market are set forth in Sec. 33.4(c)(3)(i) 
of the regulations.

E. Mitigation Measures and Analysis of Other Factors as Proposed in the 
NOPR--Introduction

    Where applicants' analysis produces concentration results that 
raise concerns, the Commission proposed that applicants evaluate 
additional factors to help determine whether a proposed merger would be 
likely to harm competition in electricity markets. Applicants would 
evaluate these factors only if competitive conditions in the upstream 
and downstream markets indicate that the merger could raise rivals' 
costs or facilitate coordination, as described in the following 
sections. In lieu of addressing these additional factors, applicants 
could propose mitigation measures. Proposals must be specific, and 
applicants would have to demonstrate that proposed measures

[[Page 71008]]

would adequately mitigate any adverse effects of the merger.
    If applicants choose not to propose mitigation, the factors that 
applicants would have to evaluate in this stage of the analytic 
framework are those set out in sections 2 through 5 of the Guidelines: 
potential adverse competitive effects, ease of entry by competitors, 
merger-related efficiencies, and whether one of the merging firm's 
assets would exit the market but for the merger. The first three of 
these factors can counteract any potential competitive harm indicated 
by market share and concentration statistics. Regarding entry, the 
Commission sought comments on the circumstances under which entry into 
either the upstream or downstream markets would be sufficient to 
mitigate the potential competitive harm of a proposed merger and the 
circumstances under which entry into both markets would be 
necessary.\102\ The first of these factors looks more specifically at 
the circumstances under which adverse competitive effects would 
materialize. Below, we discuss the requirements for evaluating such 
circumstances for mergers posing foreclosure/raising rivals' costs and 
anticompetitive coordination concerns.
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    \102\ See DOJ 1984 Merger Guidelines Secs. 4.211 and 4.212.
---------------------------------------------------------------------------

Foreclosure/Raising Rivals' Costs

Background
    If in the competitive analyses both the upstream and downstream 
markets are found to be conducive to the exercise of market power, we 
proposed that applicants demonstrate that raising rivals' costs would 
be difficult if the applicants believe the newly merged firm's ability 
to pursue anticompetitive policies has been overstated by assumptions 
in the analysis. In doing so, we proposed that applicants be required 
to provide adequate information, supported by data and documentation, 
regarding how the merged firm could raise its rivals' costs. The 
information must include (as necessary), but is not limited to: (1) 
Types of products or services sold by the upstream firm to each 
downstream competitor; (2) terms of contracts under which products or 
services are sold and the duration of such contracts; (3) a description 
of the prices, availability, quality and input delivery points of 
inputs sold to downstream competitors; and (4) information on 
generation unit scheduling, anticipated technological improvements, and 
marketing that is provided by customers to the upstream firm, 
particularly any market-sensitive information that may be subject to 
confidentiality provisions.\103\
    We sought comments on how such data can be made available to 
interveners under protective order procedures. The Commission also 
sought comments on other considerations that may affect a finding that 
a proposed vertical merger would be likely to impair competition in 
electricity markets and how such considerations should be analyzed.
---------------------------------------------------------------------------

    \103\ See, Vastar Resources, Inc., et al., 81 FERC para. 61,135 
at 61,633.
---------------------------------------------------------------------------

Comments

    NRECA states that the Commission should avoid routine use of 
protective orders because they interfere with case processing and 
undermine the public's right to know and because of the need for 
intervenors to assist the Commission in analyzing the effects of a 
merger on competition.
    On the opposite side, EEI asserts that as the Commission 
increasingly handles commercially sensitive information, we must guard 
against unnecessary disclosure. It notes that both the FTC Staff and 
DOJ, but not the Commission, have statutory protections preventing 
disclosure of commercially sensitive information. EEI urges the 
Commission to consider that the release of commercially sensitive 
information can harm vital competition in the market or create 
strategic advantages for some of the participants in the market and can 
distort the efficient distribution of resources. EEI further recommends 
the Commission restrict the filing requirements to only the information 
that is necessary to support the screen analysis.
    The FTC Staff suggests the Commission obtain authority to subpoena 
(and hold under strong confidentiality provisions) the decision, 
planning and marketing documents of the merging parties, as well as 
related documents from competitors, suppliers, customers, and trade 
associations. It also comments that the Commission may wish to pursue 
authority to depose pertinent personnel from the merging parties and 
from third parties under similar confidentiality conditions.
    Also, the FTC Staff states that instead of asking merging parties 
to supply estimates about the operations of other firms, including 
current or future competitors, the Commission should subpoena data from 
the third parties themselves, since in its experience, subjective 
assessments by one party about the operations of other parties can 
contain considerable error and bias, especially when the merging 
parties have incentives to portray markets as highly competitive. The 
FTC Staff explains that going straight to third parties enables its 
staff to cross-check important facts, such as market share data, with 
multiple information sources. Such procedures, it says, should lead to 
reasonably timely and accurate data to better support the Commission's 
decisions.
    In addition, all comments provided under the ``Foreclosure/Raising 
Rivals' Cost'' subsection under ``Vertical Analytic Framework'' apply 
here.

Commission Conclusion

    The Commission is mindful of the delicate balance between the 
public's (including intervenors') right to know and the protection not 
only of certain commercially-sensitive information, but of the 
competitive marketplace itself. Thus, the Commission will not forego 
the use of protective orders, but will instead make careful use of them 
if needed to gather and analyze market-sensitive information. The 
Commission will not place restrictions on itself as to the types of 
data it will collect, but will take into account the desire of 
applicants to protect their competitive positions.
    We will require that applicants evaluate whether customers of the 
upstream input supplier can switch to alternative inputs to avoid a 
price increase by the upstream merging firm. If switching to 
alternative inputs is possible, the merger may not create or enhance 
the ability of the merging firm to affect output and prices in the 
upstream market.
    We will require that applicants provide data showing how regulatory 
requirements governing the conduct of upstream input suppliers (such as 
open access provisions applicable to gas pipelines under Order No. 636) 
\104\ could counteract any competitive harm posed by a merger.
---------------------------------------------------------------------------

    \104\ See Pipeline Service Obligations and Revisions to 
Regulations Governing Self-Implementing Transportation Under Part 
284 of the Commission's Regulations, and Regulation of Natural Gas 
After Partial Wellhead Decontrol, Order No. 636, FERC Stats. and 
Regs. para. 30,939 (April 8, 1992), order on reh'g, Order No. 636-A, 
FERC Stats, & Regs. para. 30,950 (August 2, 1992), order on reh'g, 
Order No. 636-B, 61 FERC para. 61,272 (November 27, 1992), reh'g 
denied, Order No. 636-C, 62 FERC para. 61,007 (January 8, 1993), 
order aff'd in part and remanded in part, United Distribution 
Companies, v. FERC, 88 F.3d 1105 (D.C. Cir. 1996); order on remand, 
Order No. 636-C, 78 FERC para. 61,816 (1997).
---------------------------------------------------------------------------

    Finally, a merged company has no incentive to adversely affect 
prices through a raising rivals' costs strategy unless such behavior is 
profitable or can be used to maintain sales, market share

[[Page 71009]]

or profits. Therefore, we will require that applicants provide data and 
an assessment of the profitability of a raising rivals' costs strategy 
if this data could be helpful to determine whether such incentive 
exists.
    The filing requirements for this aspect of the analytic framework 
are set forth in Sec. 33.2(g)(4) of the revised regulations.

Facilitating Anticompetitive Coordination

Background
    As discussed earlier, a vertical merger could harm competition in 
the downstream market by facilitating anticompetitive coordination in 
either the upstream or the downstream markets. Comments were solicited 
on how a vertical merger could facilitate anticompetitive coordination; 
the conditions under which coordination would impair competition in 
electricity markets; and the significance of coordination problems.
Comments
    The FTC Staff remarks that in order to assess coordinated 
interaction, more than market share statistics need to be gathered. The 
Horizontal Merger Guidelines focus on the conditions likely for 
collusion to take place. Successful coordinated interaction includes 
reaching agreement on profitable coordination among companies, 
detecting deviations from that agreement, and punishing any such 
deviation. A better analysis of the increased likelihood of coordinated 
interaction, according to the FTC Staff, results when market share 
statistics are supplemented with other sources of information. For 
example, market share statistics would not reveal the fact that a 
merger might adversely affect competition by eliminating a maverick 
firm.
    To better address coordinated interaction concerns, the FTC Staff 
recommends that the Commission go beyond market share analysis to 
potentially useful third party information. The FTC Staff suggests that 
since firms have little incentive to accurately estimate their own 
abilities to engage in anticompetitive conduct, self-reported estimates 
should be validated independently. Otherwise, the Commission may be 
relying on inaccurate data.
Commission Conclusion
    We agree with the FTC Staff that when anticompetitive coordination 
is a concern, our analysis may have to go beyond market share and 
concentration analysis to third-party information. In such cases, the 
Commission could implement procedures under which such information 
could be collected. We also note that in approving certain mergers we 
can take steps to avoid structures and relationships that encourage 
anticompetitive coordination. At the very least, we will monitor the 
behavior of merged companies and adjust the scope of our investigations 
into future mergers accordingly.
    Therefore, we believe that the instructions outlined in the NOPR 
concerning anticompetitive coordination will generally give the 
Commission the information it needs to analyze the impact of a proposed 
merger on the market, and we adopt them.

F. Remedy--Concerning Vertical Mergers

Background
    The NOPR proposed that if a vertical merger raises competitive 
concerns after accounting for the additional factors described in the 
previous section, the merger may be made acceptable if certain remedial 
actions are taken. The NOPR cited Enova, where the Commission specified 
certain remedies that would address the competitive concerns presented 
by that merger. The remedies included a code of conduct, restrictions 
on affiliate transactions and an electronic gas reservation and 
information system.\105\
---------------------------------------------------------------------------

    \105\ Enova, 79 FERC para. 61,372 at 62,565 (1997).
---------------------------------------------------------------------------

Comments and Commission Conclusion
    No comments were received on this issue. We therefore adopt the 
proposals set forth in the NOPR.

VII. Effect on Rates--Revised Requirements for Ratepayer 
Protections

Background

    In the Policy Statement, we determined that ratepayer protection 
mechanisms (e.g., open seasons to allow early termination of existing 
service contracts or rate freezes) may be necessary to protect the 
wholesale customers of merger applicants. If the proposed merger raises 
substantial issues of fact with regard to its impact on rates, we 
stated we will consider further investigation of the matter or set it 
for hearing.\106\
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    \106\ Policy Statement at 30,111, 30,121-24, and n.5. See also, 
Morgan Stanley, 79 FERC at 61,504-05; Duke/PanEnergy, 79 FERC at 
62,039-41; Enova, 79 FERC at 62,566; Destec, 79 FERC at 62,574-75; 
LILCO, 80 FERC at 61,079-80; FirstEnergy, 80 FERC at 61,098; NorAm, 
80 FERC at 61,382-3.
---------------------------------------------------------------------------

    Thus, in the NOPR we proposed that all merger applicants 
demonstrate how wholesale ratepayers will be protected and that 
applicants will have the burden of proving that their proposed 
ratepayer protections are adequate. Specifically, we proposed that 
applicants must clearly identify what customer groups are covered 
(e.g., requirements customers, transmission customers, formula rate 
customers, etc.), what types of costs are covered, and the time period 
for which the protection will apply.

Comments and Commission Conclusion

    No specific comments were received on this issue. We adopt the 
proposals set forth in the NOPR. We emphasize, however, that if 
applicants do not offer any ratepayer protection mechanism, they must 
explain how the proposed merger will provide adequate ratepayer 
protection. Accordingly, we are adopting Sec. 33.2(g) as proposed in 
the NOPR.

VIII. Effect on Regulation--Revised Requirements Concerning the 
Impact on State and Commission Regulatory Jurisdiction

Background

    In the Policy Statement we stated that, in merger filings involving 
public utility subsidiaries of registered holding companies, applicants 
must either commit to abide by the Commission's policies with respect 
to intra-system transactions within the holding company structure or be 
prepared to go to hearing on the issue of the effect of the proposed 
registered holding company structure on effective regulation by the 
Commission.\107\ Thus, in the NOPR we proposed that, for all merger 
applications involving public utility subsidiaries of registered 
holding companies, applicants include a statement indicating such a 
commitment.
---------------------------------------------------------------------------

    \107\ Policy Statement at 30,112 and 30,124-25. See also, Duke/
PanEnergy, 79 FERC at 61,041-42; Morgan Stanley, 79 FERC at 61,505; 
Enova, 79 FERC at 62,566-67; Destec, 79 FERC at 62,575; LILCO, 80 
FERC at 61,080; FirstEnergy, 80 FERC at 61,098-99; Noram, 80 FERC at 
61,383; and Atlantic City/Delmarva, 80 FERC at 61,412-13 and n.60.
---------------------------------------------------------------------------

Comments

    Several commenters raise issues concerning gaps that may result if 
the Public Utility Holding Company Act of 1935 (PUHCA) is repealed or 
amended. Specifically, AFPA recommends the Commission seek to retain 
full antitrust jurisdiction, and antitrust standards of PUHCA, if 
current proposed legislation is successful. APPA states the 
Commission's antitrust standards should be revised rather than 
eliminated to prevent horizontal monopolies and other abuses.

[[Page 71010]]

Commission Conclusion

    We conclude that, as proposed in the NOPR, for all merger 
applications involving public utility subsidiaries of registered 
holding companies, applicants must include a commitment to abide by the 
Commission's policies with respect to intra-system transactions within 
the holding company structure or be prepared to go to hearing on the 
issue of the effect of the proposed registered holding company 
structure on effective regulation by the Commission.
    Since a regulatory gap can also occur on the state level, a merger 
applicant must state whether the affected state commissions have 
authority to act on the proposed merger. Where the affected state 
commissions have such authority, the Commission will not set for 
further investigation or hearing the matter of whether the transaction 
will impair effective regulation by the state commissions. However, if 
affected state commissions lack authority over the merger and raise 
concerns about the effect on regulation, we will consider, on a case-
by-case basis, whether to set this issue for hearing.\108\ This 
information must be included in the applicants' explanation of the 
effect of the transaction on regulation required in Sec. 33.2(g)(1) of 
the revised regulations.
---------------------------------------------------------------------------

    \108\ Policy Statement at p. 30,125.
---------------------------------------------------------------------------

IX. Emerging Issues

Introduction

    In the NOPR, the Commission solicited comments on a number of 
emerging issues in the electric industry that could have significant 
effects on its proposed filing requirements. These issues include the 
use of computer-based simulation models; if and how to account for 
restructuring, retail competition, and other types of competitive 
issues in merger analysis; and suggestions of a moratorium on mergers 
in the electric industry. We received numerous comments in response to 
these questions, as discussed below.

A. Computer-Based Simulation Models

Background
    The use of computer models--specifically, computer programs used to 
simulate the electric power market--has been raised in comments on the 
Policy Statement and also in specific cases. In comments responding to 
the Policy Statement, DOJ recommended using computer simulations to 
delineate markets and also noted that these simulations could be 
helpful in gauging the market power of the merged firm. The Commission 
stated in the NOPR that it believed that use of a properly structured 
computer model could account for important physical and economic 
effects in an analysis of mergers and may be a valuable tool to use in 
a horizontal screen analysis. For example, a computer model might prove 
particularly useful in identifying the suppliers in the geographic 
market that are capable of competing with the merged company. It could 
provide a framework to help ensure consistency in the treatment of the 
data used in identifying suppliers in a geographic market.
    Therefore, the Commission also issued a notice of request for 
written comments and intent to convene a technical conference 
concurrently with the NOPR.\109\ As more fully explained in the notice, 
the purpose of this inquiry was to gain further input into whether and 
how computer models can be useful to the competitive analysis set forth 
in Appendix A of the Policy Statement.
---------------------------------------------------------------------------

    \109\NOPR, p. 33,383.
---------------------------------------------------------------------------

Comments
    Several commenters agree that a computer model may be useful in the 
Commission's analysis of mergers and that the Commission should develop 
in-house expertise in developing models. However, commenters also 
recommend the Commission not rush to adopt a computer model, 
acknowledging that there is no model currently available that should be 
adopted as a standard. Some commenters argue that flexibility is 
important, and that a combination of models may be needed but that the 
use of too many models may become burdensome on smaller utilities and 
public interest groups. However, commenters also note the various 
benefits of using computer models in merger analysis. For example, the 
FTC Staff explains that power-flow models can be useful in analyzing 
issues arising in both horizontal and vertical mergers; however, it 
also notes that current models address only the technical aspects of 
power flows and not the economic aspects of trading in a deregulated 
wholesale market. The FTC Staff also advises that it expects more 
flexible, reliable, and accurate models to be developed and soon become 
commercially available. It suggests the Commission remain flexible in 
its approach to merger analysis, particularly as it pertains to 
computer modeling, so as to allow competition among vendors and 
development of the best models. On the other hand, Sempra cautions 
against adopting computer models for merger analysis because 
divestiture of generation assets to unregulated entities and the 
construction of unregulated plants reduces the availability of public 
data needed to run models and because use of a model also may cause 
more disputes and thus more hearings.
    WEPCO notes that the main advantage of models of the type proposed 
by the Commission is that they simulate the interaction among all loads 
and resources in arbitraging prices in various destination markets. 
Since such a model calculates prices for each load area, WEPCO claims 
there is no need to define geographic markets, since any area in which 
the merger has a significant price effect is a relevant market. WEPCO 
points out that such modeling can be used to determine whether mergers 
eliminate competitors, to explore geographic definitions, and to 
corroborate the results of a structural analysis.
    EEI believes that future uses of computer simulation models could 
provide more complex behavioral analysis beyond the structural approach 
underlying the hypothetical monopolist test. Such an approach, EEI 
comments, will enhance the Commission's ability to remedy potential 
problems posed by proposed mergers, especially considering the need to 
avoid wasting resources with mitigation measures that impose 
unnecessary costs.
Commission Conclusions
    In large part, we agree with the comments regarding the use of 
computer-based simulation models. We believe that such modeling can be 
very useful as a complement to the analysis required under the Policy 
Statement. We note the approach to evaluating mergers under the Policy 
Statement is structural. In other words, relevant markets are first 
defined and the effect of a merger on the structure of those markets is 
examined. Simulation models, however, are non-structural in nature. 
They model market conditions and directly estimate the effects on the 
market of strategic pricing and output decisions by the merging firms. 
Market structures are changing rapidly and market design issues have 
arisen in many areas of the country. Under these circumstances, 
simulation models may produce more accurate results more efficiently 
than structural analyses.
    We note, however, that modeling may improve the analysis but there 
are many issues that must be addressed before the Commission is able to 
determine the appropriateness of any particular model (i.e., 
completeness of the model and how strategic behavior is modeled). 
Therefore, we continue to believe a technical conference is needed to

[[Page 71011]]

discuss this matter. We will convene such a conference at some future 
date. In the meantime, we continue to be open to suggestions of other 
alternative forms of analysis.

B. Retail Competition, Restructuring, and Other Newly Emerging 
Competitive Issues Raised by Section 203 Transactions

Background
    Over the past several years, the electric industry in the U.S. has 
changed dramatically, as indicated by significant levels of merger and 
acquisition activity, divestiture, the development of highly organized 
markets, and movement toward the formation of various types of RTOs. 
This has been in response to competitive pressures in the marketplace 
and regulatory initiatives at the state and federal levels. For 
example, the 1996 Policy Statement primarily addresses horizontal 
mergers; however, shortly after it was issued, a number of vertical 
electric-gas mergers were filed with the Commission. For this reason, 
we requested comments in the NOPR on whether we should expect new types 
of corporate transactions involving public utilities to emerge, what 
form they might take, and how we should analyze the competitive effects 
if such combinations are in fact presented.\110\ We sought comments on 
new kinds of mergers that may lead to the blurring of traditional 
utility services and other business lines.
---------------------------------------------------------------------------

    \110\NOPR, pp. 33,383-84.
---------------------------------------------------------------------------

    The NOPR also requested comments on how the structural changes 
occurring in the electric industry should be considered in our analysis 
of the effect that public utility mergers may have on competition. The 
NOPR inquired whether participation by merger applicants in an ISO or 
similar regional body requires modification of the Commission's merger 
analysis. Finally, we sought comments on whether it is feasible to 
address competition only at the wholesale level and to ignore changes 
in the market that arise from state retail choice programs and that 
transform retail franchise service territories into multi-state 
supplier markets.
Comments
    Many commenters call upon the Commission to account for 
restructuring and the development of RTOs in its assessment of proposed 
mergers, the effect of mergers on retail competition, and other types 
of competitive issued raised by mergers.
    In response to the Commission's questions on restructuring in the 
electric industry, the Missouri Commission suggests the Commission 
perform a comprehensive generic study of market power in the 
restructured electric power industry along the lines recommended by 
Assistant Attorney General Klein.\111\ Antitrust Institute and NASUCA 
suggest the Commission's analysis consider the effect of a merger not 
only on currently regulated but also on future, competitive markets.
---------------------------------------------------------------------------

    \111\ Missouri Commission cites ``Making the Transition from 
Regulation to Competition: Thinking About Merger Policy during the 
Process of Electric Power Restructuring,'' Address by Joel I. Klein, 
United States Department of Justice, Assistant Attorney General, 
Antitrust Division, FERC Distinguished Speaker Series (January 21, 
1998).
---------------------------------------------------------------------------

    The Missouri Commission and NASUCA further suggest that, where a 
future market is uncertain due to the absence of an ISO, the Commission 
should consider identifying the uncertainties and conditioning the 
approval of such mergers to preserve the Commission's ability to gather 
additional facts or make changes in the merged company's ownership of 
assets at a later time. The Missouri and New York Commissions assert 
that this approach could be particularly helpful with regard to 
concerns about the competitive impacts of other mergers pending in the 
same markets.\112\ However Southern argues that since many proposed 
mergers are ultimately abandoned, each prospective merger candidate 
should be treated independently of other mergers unless they have been 
consummated.
---------------------------------------------------------------------------

    \112\ NOPR, p. 33,368.
---------------------------------------------------------------------------

    Antitrust Institute recommends that mergers involving transmission 
be conditioned upon the independent ownership and management of the 
merged company's transmission. It suggests a rebuttable presumption 
favoring the merging parties' participation in an ISO, as long as 
participation is accomplished prior to consummation of the merger and 
the Commission conditions its approval of the merger to assure that the 
intended competitive conditions are put in place. The Midwest ISO 
Participants contend that the rebuttable presumption should be that 
merger applicants lack market power in generation when they are members 
of a Commission approved ISO and their total generation market share is 
no more than 20 to 25 percent of the total generation in the ISO.
    In regard to retail competition, the Missouri Commission and NASUCA 
claim the NOPR failed to account for the blurring of lines between 
wholesale and retail products; NASUCA therefore urges the Commission to 
update its traditional emphasis on wholesale bulk power products to 
include a focus on actual products and services in retail markets. 
NARUC notes that state commissions may not be able to adequately 
participate in the Commission's merger proceedings because of pending 
state proceedings on the merger. It suggests that, in accord with the 
Commission's Policy Statement, state regulators should be able to 
request that the Commission analyze the effects of a merger in concert 
with the state in order to capture the unique circumstances of retail 
markets. This, it states, should not assume that the request 
constitutes a forfeiture of a state's jurisdictional authority. The 
Ohio Commission similarly recommends the Commission consider any local 
concerns which a state brings before it, regardless of the state's 
independent authority to examine mergers.
    NRECA also submits that, in the absence of state review of a public 
utility merger's effect on retail markets, a regulatory gap would be 
created unless the Commission acts to consider such effects. APPA/
Transmission Access Policy Study Group claims that under the public 
interest test of section 203 of the FPA, the Commission must consider 
the effect of a public utility merger on retail markets because retail 
choice programs are effectively ending the substantive distinction 
between wholesale and retail power markets.
    On the other hand, WEPCO counters that retail choice does not 
require the Commission to expand its public utility merger 
investigations. This is because there is no nexus between retailing 
activities and the Commission's bulk power concerns and because retail 
choice does not affect states' authority to oversee the activities of 
electricity retailers and any retail-related merger effects. EEI points 
out that the FPA leaves retail matters to the states. EEI argues the 
Commission reached the proper balance in its Policy Statement, where we 
committed to focus on retail competition analysis only if a state lacks 
adequate authority and asks us to consider the matter.
    Finally, in regard to other types of competitive issues raised by 
mergers, Antitrust Institute recommends we require information on the 
effect of proposed mergers on potential competition and ``workably'' 
competitive markets and also require support for claims that 
competition in such markets will not be reduced. Sustainable Policy 
believes the Commission must also analyze the effects of environmental 
regulations on competition in relevant markets. Since

[[Page 71012]]

most power plants are exempt from New Source Performance Standards and 
New Source Review, such requirements may frustrate entry by competitors 
that could otherwise mitigate the merged entity's market power. In its 
view, applicants should also be required to analyze the effects of the 
merged firm holding or selling pollution entitlements.
Commission Conclusions
    Traditionally, the issue of potential competition has not arisen in 
mergers involving electric utilities, largely because utilities have 
been limited to business operations within franchised service 
territories. However, with federal and state initiatives (for example, 
open access, market-based rates for generation-based products, and 
regional transmission organizations), and product diversification by 
many increasingly integrated energy companies, companies do enter other 
markets.
    As part of its merger analysis, the Commission intends to consider 
current and reasonably foreseeable regional developments and to seek 
additional relevant data and information. For example, as stated 
earlier, applicants are required to file information regarding markets 
in which they currently sell. In cases where the effect of a proposed 
merger on potential competition is a concern, we would rely, in 
reaching a determination, on the standards of review adhered to by the 
Department of Justice and Federal Trade Commission. We acknowledge that 
additional information beyond that required here may also be necessary 
to evaluate these effects and reiterate that the Commission may require 
supplementary information as necessary.
    In addition, in regard to our consideration of a merger's impact on 
retail markets, consistent with our Policy Statement,\113\ we stand 
ready to evaluate a proposed merger's impact on retail competition if a 
state lacks adequate authority to consider such matters and requests us 
to do so. The recent developments in some markets have demonstrated the 
relationship between conditions in retail markets and wholesale market 
prices. In our analysis of mergers we will take cognizance of market 
conditions.
---------------------------------------------------------------------------

    \113\ Policy Statement at p. 30,127-28.
---------------------------------------------------------------------------

    We have considered the requests of NASUCA and the Missouri 
Commission that the Commission adopt a new policy to extend its 
analysis in all merger cases to include retail markets. We decline to 
extend the general scope of our merger review in this manner. Many of 
the concerns raised by these commenters deal with the situation where 
the state commission does not have the authority to evaluate or remedy 
the merger's effect on retail markets, e.g., when the state laws do not 
cover the particular merger under consideration or when a merger 
involving entities in one state impacts retail markets in another 
state. As we made clear in the Policy Statement and the NOPR, the 
Commission stands ready to evaluate the effect of a merger on retail 
competition if a state lacks authority in these kinds of circumstances 
and asks us to do so. NASUCA and the Missouri Commission argue that 
changes in the industry are blurring the lines between wholesale and 
retail markets, making broader exercise of our section 203 authority 
important. As we acknowledged in the NOPR, changes resulting from 
industry restructuring may make retail market development critical to a 
particular merger. For example, retail access programs that may affect 
the assumptions that underlie the competitive analysis. Moreover, our 
authority to ensure nondiscriminatory open access to unbundled retail 
transmission may be important to the competitive effects of any merger 
application. We understand that as electric restructuring continues to 
evolve, there may be further developments related to retail services 
that raise issues that are directly relevant to our review of future 
mergers under Section 203. We take this opportunity to clarify that we 
will retail market issues when circumstances warrant. However, it is 
our continuing position that our merger review should not, as a matter 
of course review a merger's impact on retail markets in that state when 
a state is clearly able to do so.

C. Moratorium on Mergers

Background
    Some commenters recommend the Commission impose a moratorium on 
merger approvals. NASUCA and APPA/Transmission Access Policy Study 
Group recommend the Commission either impose a moratorium on public 
utility mergers that may raise competitive issues or, at a minimum, 
require that the benefits of such mergers be convincingly established. 
NASUCA notes that incumbent dominant firms may be able to pick off 
rivals in their infancy before they become serious competitors. 
Similarly, the Missouri Commission argues for a brief moratorium on 
mergers because data on competition in the electric industry is scarce 
and more time is needed to develop empirical evidence and a market-
based history for making competitive evaluations.
    On the other hand, EEI opposes a moratorium on public utility 
mergers, claiming that it would delay an efficient transition to 
competition. In its view, mergers represent the natural evolution of 
the markets and even a temporary ban would impose large costs on both 
consumers and stockholders that would not be in the public interest.
Commission Conclusion
    We do not believe that a temporary moratorium on utility mergers is 
necessary. Adequate regulatory safeguards are in place that protect 
against potential adverse effects. Pursuant to section 203 of the FPA, 
the Commission has the authority to issue a merger order upon such 
terms and conditions as it finds necessary or appropriate and, for good 
cause, may issue such supplemental orders as it may find necessary or 
appropriate.

X. Regulatory Flexibility Act

    The Commission adheres to its certification in the NOPR that this 
rulemaking will not have a significant economic impact upon a 
substantial number of small entities. As stated in the NOPR, the rule 
does not regulate small entities as defined in the Small Business 
Act.\114\ A description and analysis of the rule's effect on small 
businesses is therefore not required by the Regulatory Flexibility 
Act.\115\
---------------------------------------------------------------------------

    \114\ 5 U.S.C. 601(3) (citing Sec. 3 of the Small Business Act, 
15 U.S.C. 632). Section 3 of the Small Business Act defines a 
``small-business concern'' as a business which is independently 
owned and operated and which is not dominant in its field of 
operation. 15 U.S.C. 632(a); cf. 13 CFR Part 121 (containing size 
standards for determining whether businesses in various industries 
qualify as ``small'').
    \115\ 5 U.S.C. 601-612.
---------------------------------------------------------------------------

XI. Environmental Statement

    The Commission concludes that this rule will not be a major federal 
action having a significant adverse impact on the human environment 
under the Commission's regulations implementing the National 
Environment Policy Act.\116\ The rule falls within the categorical 
exemption provided in the Commission's regulations for approval of 
actions under sections 4(b), 203, 204, 301, 304, and 305 of the Federal 
Power Act relating to issuance and purchase of securities, acquisition 
or disposition of property, mergers, interlocking directorates, 
jurisdictional determinations and accounting.\117\ Consequently, 
neither an environmental

[[Page 71013]]

assessment nor an environmental impact statement is required.
---------------------------------------------------------------------------

    \116\ 18 CFR Part 380.
    \117\ 18 CFR 380.4(a)(16).
---------------------------------------------------------------------------

XII. Information Collection Statement

    The Office of Management and Budget's (OMB) regulations in 5 CFR 
1320.11 require that it approve certain reporting and record keeping 
requirements (collections of information) imposed by an agency. Upon 
approval of a collection of information, 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. The final rule will 
affect one existing data collection, FERC-519.
    In accordance with section 3507(d) of the Paperwork Reduction Act 
of 1995,\118\ the proposed data requirements in the subject rulemaking 
have been submitted to OMB for review.
---------------------------------------------------------------------------

    \118\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    Public Reporting Burden: The total estimated burden associated with 
this proposed rule is 108,199 hours (based on number of filings during 
fiscal year 1999). We have estimated that depending on a number of 
different factors, it takes on average anywhere from 91 hours to 12,557 
hours to comply with the requirements. The number of filings in 1999 
totaled 121. The following table is broken down by categories to 
identify the types of filings submitted to the Commission under Section 
203 of the FPA. These filings include: (a) Non-merger transactions, 
i.e. divestiture of assets; (b) simple merger applications where no 
competitive concerns are raised; and (c) complex merger applications 
where horizontal competitive concerns are raised and there is a need 
for an Appendix A analysis.

----------------------------------------------------------------------------------------------------------------
                                                                                                        Total
                       Data collection                           No. of       No. of     Hours per      annual
                                                              respondents   responses     response      hours
----------------------------------------------------------------------------------------------------------------
FERC-519:
    (a) Non-merger..........................................          107            1           91        9,737
    (b) Simple merger.......................................            7            1        1,509       10,563
    (c) Complex merger......................................            7            1       12,557       87,899
                                                             ---------------------------------------------------
      Totals................................................          121            1       14,157      108,199
----------------------------------------------------------------------------------------------------------------

    Information Collection Costs: The Commission sought comments to 
comply with these requirements. No comments were received. The 
requirements were first formulated in the Commission's 1996 Policy 
Statement, and specified in the NOPR. These initiatives set in motion 
the proposed requirements, so affected entities already have incurred 
any necessary start-up costs in order to comply. The costs indicated 
below address the additional analysis that will be necessary as a 
result of the requirements of this proposed rule. It is estimated that 
in order to conduct the appropriate analysis, there will be costs 
associated with the acquisition of software (including license costs) 
and hardware. It should be noted that these entities have access, for 
other business purposes, to the ordinary office equipment needed for 
compliance, and this rulemaking has no consequential effect on the 
operating and maintaining that equipment. The annualized costs are 
based on burden hours determined by hourly rates for labor.

----------------------------------------------------------------------------------------------------------------
                                                                                  Annualized on-
                                                                    Annualized      going costs        Total
                         Data collection                          capital/start-    (operations     annualized
                                                                     up  costs          and            costs
                                                                                   maintenance)
----------------------------------------------------------------------------------------------------------------
FERC-519:
    (a) W/o analysis............................................              $0         $37,200         $37,200
    (b) Simple merger...........................................          15,300         615,528         630,828
    (c) Complex.................................................         162,000       5,123,400      5,285,400
Total Annualized costs when considering all filings:
    (a) W/o analysis $37,200  x  107 filings  x  8 = $3,980,400.
    (b) Simple merger $630,828  x  7 filings = $ 4,415,796.
    (c) Complex merger $5,285,400  x  7 filings = $36,997,800.
        Totals = $45,393,996.
----------------------------------------------------------------------------------------------------------------

    Title: FERC-519, Application for Sale, Lease or other Disposition, 
Merger or Consolidation of Facilities, or For Purchase or Acquisition 
of Securities of a Public Utility.
    Action: Proposed Data Collection.
    OMB Control No: 1902-0082.
    Respondents: Public Utilities (Business or other for profit, 
including small businesses.)
    Frequency of information: On occasion.
    Necessity of the Information: The Final Rule revises the filing 
requirements in 18 CFR Part 33 which implements Sec. 203 of the Federal 
Power Act (FPA). The proposed rule provides applicants with detailed 
guidance for preparing merger applications and is consistent with the 
policies set forth in the Policy Statement. The proposed rule is 
intended to lessen regulatory burdens on industry by eliminating 
outdated and unnecessary filing requirements, clarifying existing 
requirements, and streamlining the filing requirements for transactions 
that do not raise competitive concerns.
    The implementation of these proposed filing requirements will help 
the Commission carry out its responsibilities under the FPA in 
accordance with the objectives of the Commission's Open Access Rule 
\119\ and Order No. 2000 \120\ to promote competitive, well-functioning 
markets

[[Page 71014]]

while at the same time protecting customers by constraining market 
power through regulation. In consideration of changing market 
structures in the electric industry, the Commission must ensure that no 
significant increase in market dominance will result from a merger or 
other corporate restructuring. The Commission must also ensure that 
ratepayers will be protected from any negative effects of a merger. The 
Commission also examines barriers to entry of new competitors in the 
market. The Commission will use the data received as a result of the 
proposed filing requirements: (1) In the review of the proposed merger 
of jurisdictional facilities to ascertain whether the merger is in the 
public interest; (2) for general industry oversight; and (3) to 
expedite the corporate application review process.
---------------------------------------------------------------------------

    \119\ 61 FR 21, 540, May 10, 1996.
    \120\ 65 FR 809, January 6, 2000.
---------------------------------------------------------------------------

    The Commission received 21 comments on the proposed reporting 
requirements but none on its reporting burden or cost estimates. The 
Commission's responses to the comments are being addressed elsewhere in 
this Final Rule.
    For information on the requirements, submitting comments on the 
collection of information and the associated burden estimates, 
including suggestions for reducing this burden, please send your 
comments to the Federal Energy Regulatory Commission, 888 First Street, 
NE., Washington, DC 20426 (Attention: Michael Miller, Office of the 
Chief Information Officer, (202) 208-1415, or <a href="/cdn-cgi/l/email-protection#3b5652505e15565257575e497b5d5e4958155d5e5f154e48"><span class="__cf_email__" data-cfemail="5e3337353b70333732323b2c1e383b2c3d70383b3a702b2d">[email protected]</span></a>) 
or send comments to the Office of Management and Budget (Attention: 
Desk Officer for the Federal Energy Regulatory Commission (202) 395-
3087, fax: 395-7285.) In addition, comments on reducing the burden and/
or improving the collection of information should also be submitted to 
the Office of Management and Budget, Office of Information and 
Regulatory Affairs, Attention: Desk Officer for the Federal Energy 
Regulatory Commission, 725 17th Street, NW., Washington, D.C. 20503.

XIII. Document Availability

    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 FERC Home Page (http://www.ferc.fed.us) 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.
    From the FERC Home Page on the Internet, this information is 
available in both the Commission Issuance Posting System (CIPS) and the 
Records and Information Management System (RIMS).
    <bullet> CIPS provides access to the texts of formal documents 
issued by the Commission since November 14, 1994.
    <bullet> CIPS can be accessed using the CIPS link or the Energy 
Information Online icon. The full text of this document is available on 
CIPS in ASCII and WordPerfect 8.0 formats for viewing, printing and/or 
downloading.
    <bullet> RIMS contains images of documents submitted to and issued 
by the Commission after November 16, 1981. Documents from November 1995 
to the present can be viewed and printed from FERC's Home Page using 
the RIMS link or the Energy Information Online icon. Descriptions of 
documents back to November 16, 1981, are also available from RIMS-on-
the-Web; requests for copies of these and other older documents should 
be submitted to the Public Reference Room.
    User assistance is available for RIMS, CIPS, and the Website during 
normal business hours from our Help line at (202) 208-2222 (E-Mail to 
<a href="/cdn-cgi/l/email-protection#adfac8cfe0ccded9c8dfedcbc8dfce83cbc8c983d8de"><span class="__cf_email__" data-cfemail="481f2d2a05293b3c2d3a082e2d3a2b662e2d2c663d3b">[email protected]</span></a>) or the Public Reference Room at (202) 208-1371 
(E-Mail to <a href="/cdn-cgi/l/email-protection#8ffffaede3e6eca1fdeae9eafdeae1eceafde0e0e2cfe9eafdeca1e9eaeba1fafc"><span class="__cf_email__" data-cfemail="bececbdcd2d7dd90ccdbd8dbccdbd0dddbccd1d1d3fed8dbccdd90d8dbda90cbcd">[email protected]</span></a>).
    During normal business hours, documents can also be viewed and/or 
printed in the FERC Public Reference Room, where RIMS, CIPS, and the 
FERC Website are available. User assistance is also available.

XIV. Effective Date and Congressional Notification

    This rule will take effect January 29, 2001. The Commission has 
determined, with the concurrence of the Administrator of the Office of 
Information and Regulatory Affairs at the Office of Management and 
Budget, that this Final Rule is not a ``major rule'' as defined in 
section 251 of the Small Business Regulatory Enforcement Act of 
1996.\121\ The Rule will be submitted to both Houses of Congress and 
the Comptroller General.
---------------------------------------------------------------------------

    \121\ 5 U.S.C. 804(2).
---------------------------------------------------------------------------

List of Subjects in 18 CFR Part 33

    Electric utilities, Reporting and recordkeeping requirements, 
Securities.

    By the Commission.
Linwood A. Watson, Jr.,
Acting Secretary.

    In consideration of the foregoing, the Commission revises Part 33, 
Chapter I, Title 18 of the Code of Federal Regulations, as follows:

PART 33--APPLICATION FOR ACQUISITION, SALE, LEASE, OR OTHER 
DISPOSITION, MERGER OR CONSOLIDATION OF FACILITIES, OR FOR PURCHASE 
OR ACQUISITION OF SECURITIES OF A PUBLIC UTILITY

Sec.
33.1   Applicability.
33.2   Contents of application--general information requirements.
33.3   Additional information requirements for applications 
involving horizontal competitive impacts.
33.4   Additional information requirements for applications 
involving vertical competitive impacts.
33.5   Proposed accounting entries.
33.6   Form of notice.
33.7   Verification.
33.8   Number of copies.
33.9   Protective order.
33.10   Additional information.

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


Sec. 33.1  Applicability.

    (a) The requirements of this part will apply to any public utility 
seeking authority under section 203 of the Federal Power Act to:
    (1) Dispose by sale, lease or otherwise of the whole of its 
facilities subject to Commission jurisdiction or any part thereof of a 
value in excess of $50,000;
    (2) Merge or consolidate, directly or indirectly, facilities 
subject to Commission jurisdiction with those of any other person, if 
such facilities are of a value in excess of $50,000, including the 
acquisition of electric facilities used for the transmission or sale at 
wholesale of electric energy in interstate commerce which, except for 
ownership, would be subject to the Commission's jurisdiction; or
    (3) Purchase, acquire or take any security of any other public 
utility.
    (b) Value in excess of $50,000 as used in section 203 of the 
Federal Power Act (16 U.S.C. 824b) will be the original cost 
undepreciated as defined in the Commission's Uniform System of Accounts 
prescribed for public utilities and licensees in part 101 of this 
chapter.


Sec. 33.2  Contents of application--general information requirements.

    Each applicant must include in its application, in the manner and 
form and in the order indicated, the following general information with 
respect to the applicant and each entity whose jurisdictional 
facilities or securities are involved:
    (a) The exact name of the applicant and its principal business 
address.
    (b) The name and address of the person authorized to receive 
notices and

[[Page 71015]]

communications regarding the application, including phone and fax 
numbers, and E-mail addresses.
    (c) A description of the applicant, including:
    (1) All business activities of the applicant, including 
authorizations by charter or regulatory approval (to be identified as 
Exhibit A to the application);
    (2) A list of all energy subsidiaries and energy affiliates, 
percentage ownership interest in such subsidiaries and affiliates, and 
a description of the primary business in which each energy subsidiary 
and affiliate is engaged (to be identified as Exhibit B to the 
application);
    (3) Organizational charts depicting the applicant's current and 
proposed post-transaction corporate structures (including any pending 
authorized but not implemented changes) indicating all parent 
companies, energy subsidiaries and energy affiliates unless the 
applicant demonstrates that the proposed transaction does not affect 
the corporate structure of any party to the transaction (to be 
identified as Exhibit C to the application);
    (4) A description of all joint ventures, strategic alliances, 
tolling arrangements or other business arrangements, including 
transfers of operational control of transmission facilities to 
Commission approved Regional Transmission Organizations, both current, 
and planned to occur within a year from the date of filing, to which 
the applicant or its parent companies, energy subsidiaries, and energy 
affiliates is a party, unless the applicant demonstrates that the 
proposed transaction does not affect any of its business interests (to 
be identified as Exhibit D to the application);
    (5) The identity of common officers or directors of parties to the 
proposed transaction (to be identified as Exhibit E to the 
application); and
    (6) A description and location of wholesale power sales customers 
and unbundled transmission services customers served by the applicant 
or its parent companies, subsidiaries, affiliates and associate 
companies (to be identified as Exhibit F to the application).
    (d) A description of jurisdictional facilities owned, operated, or 
controlled by the applicant or its parent companies, subsidiaries, 
affiliates, and associate companies (to be identified as Exhibit G to 
the application).
    (e) A narrative description of the proposed transaction for which 
Commission authorization is requested, including:
    (1) The identity of all parties involved in the transaction;
    (2) All jurisdictional facilities and securities associated with or 
affected by the transaction (to be identified as Exhibit H to the 
application);
    (3) The consideration for the transaction; and
    (4) The effect of the transaction on such jurisdictional facilities 
and securities.
    (f) All contracts related to the proposed transaction together with 
copies of all other written instruments entered into or proposed to be 
entered into by the parties to the transaction (to be identified as 
Exhibit I to the application).
    (g) A statement explaining the facts relied upon to demonstrate 
that the proposed transaction is consistent with the public interest. 
The applicant must include a general explanation of the effect of the 
transaction on competition, rates and regulation of the applicant by 
the Commission and state commissions with jurisdiction over any party 
to the transaction. The applicant should also file any other 
information it believes relevant to the Commission's consideration of 
the transaction. The applicant must supplement its application promptly 
to reflect in its analysis material changes that occur after the date a 
filing is made with the Commission, but before final Commission action. 
Such changes must be described and their effect on the analysis 
explained (to be identified as Exhibit J to the application).
    (h) If the proposed transaction involves physical property of any 
party, the applicant must provide a general or key map showing in 
different colors the properties of each party to the transaction (to be 
identified as Exhibit K to the application).
    (i) If the applicant is required to obtain licenses, orders, or 
other approvals from other regulatory bodies in connection with the 
proposed transaction, the applicant must identify the regulatory bodies 
and indicate the status of other regulatory actions, and provide a copy 
of each order of those regulatory bodies that relates to the proposed 
transaction (to be identified as Exhibit L to the application). If the 
regulatory bodies issue orders pertaining to the proposed transaction 
after the date of filing with the Commission, and before the date of 
final Commission action, the applicant must supplement its Commission 
application promptly with a copy of these orders.


Sec. 33.3  Additional information requirements for applications 
involving horizontal competitive impacts.

    (a)(1) The applicant must file the horizontal Competitive Analysis 
Screen described in paragraphs (b) through (f) of this section if, as a 
result of the proposed transaction, a single corporate entity obtains 
ownership or control over the generating facilities of previously 
unaffiliated merging entities (for purposes of this section, merging 
entities means any party to the proposed transaction or its parent 
companies, energy subsidiaries or energy affiliates).
    (2) A horizontal Competitive Analysis Screen need not be filed if 
the applicant:
    (i) Affirmatively demonstrates that the merging entities do not 
currently conduct business in the same geographic markets or that the 
extent of the business transactions in the same geographic markets is 
de minimis; and
    (ii) No intervenor has alleged that one of the merging entities is 
a perceived potential competitor in the same geographic market as the 
other.
    (b) All data, assumptions, techniques and conclusions in the 
horizontal Competitive Analysis Screen must be accompanied by 
appropriate documentation and support.
    (1) If the applicant is unable to provide any specific data 
required in this section, it must identify and explain how the data 
requirement was satisfied and the suitability of the substitute data.
    (2) The applicant may provide other analyses for defining relevant 
markets (e.g. the Hypothetical Monopolist Test with or without the 
assumption of price discrimination) in addition to the delivered price 
test under the horizontal Competitive Analysis Screen.
    (3) The applicant may use a computer model to complete one or more 
steps in the horizontal Competitive Analysis Screen. The applicant must 
fully explain, justify and document any model used and provide 
descriptions of model formulation, mathematical specifications, 
solution algorithms, as well as the annotated model code in executable 
form, and specify the software needed to execute the model. The 
applicant must explain and document how inputs were developed, the 
assumptions underlying such inputs and any adjustments made to 
published data that are used as inputs. The applicant must also explain 
how it tested the predictive value of the model, for example, using 
historical data.
    (c) The horizontal Competitive Analysis Screen must be completed 
using the following steps:
    (1) Define relevant products. Identify and define all wholesale 
electricity products sold by the merging entities

[[Page 71016]]

during the two years prior to the date of the application, including, 
but not limited to, non-firm energy, short-term capacity (or firm 
energy), long-term capacity (a contractual commitment of more than one 
year), and ancillary services (specifically spinning reserves, non-
spinning reserves, and imbalance energy, identified and defined 
separately). Because demand and supply conditions for a product can 
vary substantially over the year, periods corresponding to those 
distinct conditions must be identified by load level, and analyzed as 
separate products.
    (2) Identify destination markets. Identify each wholesale power 
sales customer or set of customers (destination market) affected by the 
proposed transaction. Affected customers are, at a minimum, those 
entities directly interconnected to any of the merging entities and 
entities that have purchased electricity at wholesale from any of the 
merging entities during the two years prior to the date of the 
application. If the applicant does not identify an entity to whom the 
merging entities have sold electricity during the last two years as an 
affected customer, the applicant must provide a full explanation for 
each exclusion.
    (3) Identify potential suppliers. The applicant must identify 
potential suppliers to each destination market using the delivered 
price test described in paragraph (c)(4) of this section. A seller may 
be included in a geographic market to the extent that it can 
economically and physically deliver generation services to the 
destination market.
    (4) Perform delivered price test. For each destination market, the 
applicant must calculate the amount of relevant product a potential 
supplier could deliver to the destination market from owned or 
controlled capacity at a price, including applicable transmission 
prices, loss factors and ancillary services costs, that is no more than 
five (5) percent above the pre-transaction market clearing price in the 
destination market.
    (i) Supplier's presence. The applicant must measure each potential 
supplier's presence in the destination market in terms of generating 
capacity, using economic capacity and available economic capacity 
measures. Additional adjustments to supplier presence may be presented; 
applicants must support any such adjustment.
    (A) Economic capacity means the amount of generating capacity owned 
or controlled by a potential supplier with variable costs low enough 
that energy from such capacity could be economically delivered to the 
destination market. Prior to applying the delivered price test, the 
generating capacity meeting this definition must be adjusted by 
subtracting capacity committed under long-term firm sales contracts and 
adding capacity acquired under long-term firm purchase contracts (i.e., 
contracts with a remaining commitment of more than one year). The 
capacity associated with any such adjustments must be attributed to the 
party that has authority to decide when generating resources are 
available for operation. Other generating capacity may also be 
attributed to another supplier based on operational control criteria as 
deemed necessary, but the applicant must explain the reasons for doing 
so.
    (B) Available economic capacity means the amount of generating 
capacity meeting the definition of economic capacity less the amount of 
generating capacity needed to serve the potential supplier's native 
load commitments, as described in paragraph (d)(4)(i) of this section.
    (C) Available transmission capacity. Each potential supplier's 
economic capacity and available economic capacity (and any other 
measure used to determine the amount of relevant product that could be 
delivered to a destination market) must be adjusted to reflect 
available transmission capability to deliver each relevant product. The 
allocation to a potential supplier of limited capability of constrained 
transmission paths internal to the merging entities' systems or 
interconnecting the systems with other control areas must recognize 
both the transmission capability not subject to firm reservations by 
others and any firm transmission rights held by the potential supplier 
that are not committed to long-term transactions. For each such 
instance where limited transmission capability must be allocated among 
potential suppliers, the applicant must explain the method used and 
show the results of such allocation.
    (D) Internal interface. If the proposed transaction would cause an 
interface that interconnects the transmission systems of the merging 
entities to become transmission facilities for which the merging 
entities would have a ``native load'' priority under their open access 
transmission tariff (i.e., where the merging entities may reserve 
existing transmission capacity needed for native load growth and 
network transmission customer load growth reasonable forecasted within 
the utility's current planning horizon), all of the unreserved 
capability of the interface must be allocated to the merging entities 
for purposes of the horizontal Competitive Analysis Screen, unless the 
applicant demonstrates one of the following:
    (1) The merging entities would not have adequate economic capacity 
to fully use such unreserved transmission capability;
    (2) The merging entities have committed a portion of the interface 
capability to third parties; or
    (3) Suppliers other than the merging entities have purchased a 
portion of the interface capability.
    (5) Calculate market concentration. The applicant must calculate 
the market share, both pre- and post-merger, for each potential 
supplier, the Herfindahl-Hirschman Index (HHI) statistic for the 
market, and the change in the HHI statistic. (The HHI statistic is a 
measure of market concentration and is a function of the number of 
firms in a market and their respective market shares. The HHI statistic 
is calculated by summing the squares of the individual market shares, 
expressed as percentages, of all potential suppliers to the destination 
market.) To make these calculations, the applicant must use the amounts 
of generating capacity (i.e., economic capacity and available economic 
capacity, and any other relevant measure) determined in paragraph 
(c)(4)(i) of this section, for each product in each destination market.
    (6) Provide historical transaction data. The applicant must provide 
historical trade data and historical transmission data to corroborate 
the results of the horizontal Competitive Analysis Screen. The data 
must cover the two-year period preceding the filing of the application. 
The applicant may adjust the results of the horizontal Competitive 
Analysis Screen, if supported by historical trade data or historical 
transmission service data. Any adjusted results must be shown 
separately, along with an explanation of all adjustments to the results 
of the horizontal Competitive Analysis Screen. The applicant must also 
provide an explanation of any significant differences between results 
obtained by the horizontal Competitive Analysis Screen and trade 
patterns in the last two years.
    (d) In support of the delivered price test required by paragraph 
(c)(4) of this section, the applicant must provide the following data 
and information used in calculating the economic capacity and available 
economic capacity that a potential supplier could deliver to a 
destination market. The transmission data required by paragraphs (d)(7) 
through (d)(9) of this section must be supplied for the merging 
entities'

[[Page 71017]]

systems. The transmission data must also be supplied for other relevant 
systems, to the extent data are publicly available.
    (1) Generation capacity. For each generating plant or unit owned or 
controlled by each potential supplier, the applicant must provide:
    (i) Supplier name;
    (ii) Name of the plant or unit;
    (iii) Primary and secondary fuel-types;
    (iv) Nameplate capacity;
    (v) Summer and winter total capacity; and
    (vi) Summer and winter capacity adjusted to reflect planned and 
forced outages and other factors, such as fuel supply and environmental 
restrictions.
    (2) Variable cost. For each generating plant or unit owned or 
controlled by each potential supplier, the applicant must also provide 
variable cost components.
    (i) These cost components must include at a minimum:
    (A) Variable operation and maintenance, including both fuel and 
non-fuel operation and maintenance; and
    (B) Environmental compliance.
    (ii) To the extent costs described in paragraph (d)(2)(i) of this 
section are allocated among units at the same plant, allocation methods 
must be fully described.
    (3) Long-term purchase and sales data. For each sale and purchase 
of capacity, the applicant must provide the following information:
    (i) Purchasing entity name;
    (ii) Selling entity name;
    (iii) Duration of the contract;
    (iv) Remaining contract term and any evergreen provisions;
    (v) Provisions regarding renewal of the contract;
    (vi) Priority or degree of interruptibility;
    (vii) FERC rate schedule number, if applicable;
    (viii) Quantity and price of capacity and/or energy purchased or 
sold under the contract; and
    (ix) Information on provisions of contracts which confer 
operational control over generation resources to the purchaser.
    (4) Native load commitments.
    (i) 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.
    (ii) The applicant must provide supplier name and hourly native 
load commitments for the most recent two years. In addition, the 
applicant must provide this information for each load level, if load-
differentiated relevant products are analyzed.
    (iii) If data on native load commitments are not available, the 
applicant must fully explain and justify any estimates of these 
commitments.
    (5) Transmission and ancillary service prices, and loss factors.
    (i) The applicant must use in the horizontal Competitive Analysis 
Screen the maximum rates stated in the transmission providers' tariffs. 
If necessary, those rates should be converted to a dollars-per-megawatt 
hour basis and the conversion method explained.
    (ii) If a regional transmission pricing regime is in effect that 
departs from system-specific transmission rates, the horizontal 
Competitive Analysis Screen must reflect the regional pricing regime.
    (iii) The following data must be provided for each transmission 
system that would be used to deliver energy from each potential 
supplier to a destination market:
    (A) Supplier name;
    (B) Name of transmission system;
    (C) Firm point-to-point rate;
    (D) Non-firm point-to-point rate;
    (E) Scheduling, system control and dispatch rate;
    (F) Reactive power/voltage control rate;
    (G) Transmission loss factor; and
    (H) Estimated cost of supplying energy losses.
    (iv) The applicant may present additional alternative analysis 
using discount prices if the applicant can support it with evidence 
that discounting is and will be available.
    (6) Destination market price. The applicant must provide, for each 
relevant product and destination market, market prices for the most 
recent two years. The applicant may provide suitable proxies for market 
prices if actual market prices are unavailable. Estimated prices or 
price ranges must be supported and the data and approach used to 
estimate the prices must be included with the application. If the 
applicant relies on price ranges in the analysis, such ranges must be 
reconciled with any actual market prices that are supplied in the 
application. Applicants must demonstrate that the results of the 
analysis do not vary significantly in response to small variations in 
actual and/or estimated prices.
    (7) Transmission capability.
    (i) The applicant must provide simultaneous transfer capability 
data, if available, for each of the transmission paths, interfaces, or 
other facilities used by suppliers to deliver to the destination 
markets on an hourly basis for the most recent two years.
    (ii) Transmission capability data must include the following 
information:
    (A) Transmission path, interface, or facility name;
    (B) Total transfer capability (TTC); and
    (C) Firm available transmission capability (ATC).
    (iii) Any estimated transmission capability must be supported and 
the data and approach used to make the estimates must be included with 
the application.
    (8) Transmission constraints.
    (i) For each existing transmission facility that affects supplies 
to the destination markets and that has been constrained during the 
most recent two years or is expected to be constrained within the 
planning horizon, the applicant must provide the following information:
    (A) Name of all paths, interfaces, or facilities affected by the 
constraint;
    (B) Locations of the constraint and all paths, interfaces, or 
facilities affected by the constraint;
    (C) Hours of the year when the transmission constraint is binding; 
and
    (D) The system conditions under which the constraint is binding.
    (ii) The applicant must include information regarding expected 
changes in loadings on transmission facilities due to the proposed 
transaction and the consequent effect on transfer capability.
    (iii) To the extent possible, the applicant must provide system 
maps showing the location of transmission facilities where binding 
constraints have been known or are expected to occur.
    (9) Firm transmission rights (Physical and Financial). For each 
potential supplier to a destination market that holds firm transmission 
rights necessary to directly or indirectly deliver energy to that 
market, or that holds transmission congestion contracts, the applicant 
must provide the following information:
    (i) Supplier name;
    (ii) Name of transmission path interface, or facility;
    (iii) The FERC rate schedule number, if applicable, under which 
transmission service is provided; and
    (iv) A description of the firm transmission rights held (including, 
at a minimum, quantity and remaining time the rights will be held, and 
any relevant time restrictions on transmission use, such as peak or 
off-peak rights).
    (10) Summary table of potential suppliers' presence.
    (i) The applicant must provide a summary table with the following

[[Page 71018]]

information for each potential supplier for each destination market:
    (A) Potential supplier name;
    (B) The potential supplier's total amount of economic capacity (not 
subject to transmission constraints); and
    (C) The potential supplier's amount of economic capacity from which 
energy can be delivered to the destination market (after adjusting for 
transmission availability).
    (ii) A similar table must be provided for available economic 
capacity, and for any other generating capacity measure used by the 
applicant.
    (11) Historical trade data.
    (i) The applicant must provide data identifying all of the merging 
entities' wholesale sales and purchases of electric energy for the most 
recent two years.
    (ii) The applicant must include the following information for each 
transition:
    (A) Type of transaction (such as non-firm, short-term firm, long-
term firm, peak, off-peak, etc.);
    (B) Name of purchaser;
    (C) Name of seller;
    (D) Date, duration and time period of the transaction;
    (E) Quantity of energy purchased or sold;
    (F) Energy charge per unit;
    (G) Megawatt hours purchased or sold;
    (H) Price; and
    (I) The delivery points used to effect the sale or purchase.
    (12) Historical transmission data. The applicant must provide 
information concerning any transmission service denials, interruptions 
and curtailments on the merging entities' systems, for the most recent 
two years, to the extent the information is available from OASIS data, 
including the following information:
    (i) Name of the customer denied, interrupted or curtailed;
    (ii) Type, quantity and duration of service at issue;
    (iii) The date and period of time involved;
    (iv) Reason given for the denial, interruption or curtailment;
    (v) The transmission path; and
    (vi) The reservations or other use anticipated on the affected 
transmission path at the time of the service denial, curtailment or 
interruption.
    (e) Mitigation. Any mitigation measures proposed by the applicant 
(including, for example, divestiture or participation in a regional 
transmission organization) which are intended to mitigate the adverse 
effect of the proposed transaction must, to the extent possible, be 
factored into the horizontal Competitive Analysis Screen as an 
additional post-transaction analysis. Any mitigation commitments that 
involve facilities (e.g., in connection with divestiture of generation) 
must identify the facilities affected by the commitment, along with a 
timetable for implementing the commitments.
    (f) Additional factors. If the applicant does not propose 
mitigation, the applicant must address:
    (1) The potential adverse competitive effects of the transaction.
    (2) The potential for entry in the market and the role that entry 
could play in mitigating adverse competitive effects of the 
transaction;
    (3) The efficiency gains that reasonably could not be achieved by 
other means; and
    (4) Whether, but for the transaction, one or more of the merging 
entities would be likely to fail, causing its assets to exit the 
market.


Sec. 33.4  Additional information requirements for applications 
involving vertical competitive impacts.

    (a)(1) The applicant must file the vertical Competitive Analysis 
described in paragraphs (b) through (e) of this section if, as a result 
of the proposed transaction, a single corporate entity has ownership or 
control over one or more merging entities that provides inputs to 
electricity products and one or more merging entities that provides 
electric generation products (for purposes of this section, merging 
entities means any party to the proposed transaction or its parent 
companies, energy subsidiaries or energy affiliates).
    (2) A vertical Competitive Analysis need not be filed if the 
applicant can affirmatively demonstrate that:
    (i) The merging entities currently do not provide inputs to 
electricity products (i.e., upstream relevant products) and electricity 
products (i.e., downstream relevant products) in the same geographic 
markets or that the extent of the business transactions in the same 
geographic market is de minimis; and no intervenor has alleged that one 
of the merging entities is a perceived potential competitor in the same 
geographic market as the other.
    (ii) The extent of the upstream relevant products currently 
provided by the merging entities is used to produce a de minimis amount 
of the relevant downstream products in the relevant destination 
markets, as defined in paragraph (c)(2) of Sec. 33.3.
    (b) All data, assumptions, techniques and conclusions in the 
vertical Competitive Analysis must be accompanied by appropriate 
documentation and support.
    (c) The vertical Competitive Analysis must be completed using the 
following steps:
    (1) Define relevant products.--(i) Downstream relevant products. 
The applicant must identify and define as downstream relevant products 
all products sold by merging entities in relevant downstream geographic 
markets, as outlined in paragraph (c)(1) of Sec. 33.3.
    (ii) Upstream relevant products. The applicant must identify and 
define as upstream relevant products all inputs to electricity products 
provided by upstream merging entities in the most recent two years.
    (2) Define geographic markets.--(i) Downstream geographic markets. 
The applicant must identify all geographic markets in which it or any 
merging entities sell the downstream relevant products, as outlined in 
paragraphs (c)(2) and (c)(3) of Sec. 33.3.
    (ii) Upstream geographic markets. The applicant must identify all 
geographic markets in which it or any merging entities provide the 
upstream relevant products.
    (3) Analyze competitive conditions.--(i) Downstream geographic 
market.
    (A) The applicant must compute market share for each supplier in 
each relevant downstream geographic market and the HHI statistic for 
the downstream market. The applicant must provide a summary table with 
the following information for each relevant downstream geographic 
market:
    (1) The economic capacity of each downstream supplier (specify the 
amount of such capacity served by each upstream supplier);
    (2) The total amount of economic capacity in the downstream market 
served by each upstream supplier;
    (3) The market share of economic capacity served by each upstream 
supplier; and
    (4) The HHI statistic for the downstream market.
    (B) A similar table must be provided for available economic 
capacity and for any other measure used by the applicant.
    (ii) Upstream geographic market. The applicant must provide a 
summary table with the following information for each upstream relevant 
product in each relevant upstream geographic market:
    (A) The amount of relevant product provided by each upstream 
supplier;
    (B) The total amount of relevant product in the market;
    (C) The market share of each upstream supplier; and
    (D) The HHI statistic for the upstream market.
    (d) Mitigation. Any mitigation measures proposed by the applicant

[[Page 71019]]

(including, for example, divestiture or participation in an Regional 
Transmission Organization) which are intended to mitigate the adverse 
effect of the proposed transaction must, to the extent possible, be 
factored into the vertical competitive analysis as an additional post-
transaction analysis. Any mitigation measures that involve facilities 
must identify the facilities affected by the commitment.
    (e) Additional factors.
    (1) If the applicant does not propose mitigation measures, the 
applicant must address:
    (i) The potential adverse competitive effects of the transaction.
    (ii) The potential for entry in the market and the role that entry 
could play in mitigating adverse competitive effects of the 
transaction;
    (iii) The efficiency gains that reasonably could not be achieved by 
other means; and
    (iv) Whether, but for the proposed transaction, one or more of the 
parties to the transaction would be likely to fail, causing its assets 
to exit the market.
    (2) The applicant must address each of the additional factors in 
the context of whether the proposed transaction is likely to present 
concerns about raising rivals' costs or anticompetitive coordination.


Sec. 33.5  Proposed accounting entries.

    If the applicant is required to maintain its books of account in 
accordance with the Commission's Uniform System of Accounts in part 101 
of this chapter, the applicant must present proposed accounting entries 
showing the effect of the transaction with sufficient detail to 
indicate the effects on all account balances (including amounts 
transferred on an interim basis), the effect on the income statement, 
and the effects on other relevant financial statements. The applicant 
must also explain how the amount of each entry was determined.


Sec. 33.6  Form of notice.

    The applicant must file a form of notice of the application 
suitable for issuance in the Federal Register, as well as a copy of the 
same notice in electronic format in WordPerfect 6.1 (or other 
electronic format the Commission may designate) on a 3\1/2\" diskette 
marked with the name of the applicant and the words ``Notice of 
Application.'' The Notice of Filing must appear in the following form:

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

[Full Name of Applicant(s)]

Docket No. XXXX-XXX-XXX

NOTICE OF FILING

    Take notice that on [Date of filing], [Applicant(s)] filed with 
the Federal Energy Regulatory Commission an application pursuant to 
section 203 of the Federal Power Act for authorization of a 
disposition of jurisdictional facilities whereby [describe the 
transaction for which authorization is sought, clearly identifying 
the jurisdictional facilities being disposed of, the entity(s) 
disposing of the facilities, the entity(s) acquiring/leasing the 
facilities and (briefly) how the disposition will be accomplished 
(e.g., by stock transfer or a cash sale)]. [If the disposition of 
jurisdictional facilities is directly related to the disposition of 
generation assets, identify those generation assets and their total 
nameplate generation capacity in Megawatts. If authorization is 
needed for both the sale and the purchase of the jurisdictional 
facilities, this should be clearly stated in this paragraph of the 
notice. If the application involves a merger, the applicant should 
clearly indicate this in the draft notice. If the application 
contained a request for privileged treatment by the Commission, 
state this fact in this paragraph of the notice.]
    Any person desiring to be heard or to protest such filing should 
file a motion to intervene or protest with the Federal Energy 
Regulatory Commission, 888 First Street, NE., Washington, DC 20426, 
in accordance with Rules 211 and 214 of the Commission's Rules of 
Practice and Procedure (18 CFR 385.211 and 385.214). All such 
motions and protests should be filed on or before __________. 
Protests will be considered by the Commission to determine the 
appropriate action to be taken, but will not serve to make 
protestants parties to the proceedings. Any person wishing to become 
a party must file a motion to intervene. Copies of this filing are 
on file with the Commission and are available for public inspection. 
This filing may also be viewed on the Internet at http://www.ferc.fed.us/online/rims.htm (call 202-208-2222 for assistance).

Secretary

    The Commission may require the applicant to give such local notice 
by publication as the Commission in its discretion may deem proper.


Sec. 33.7  Verification.

    The original application must be signed by a person or persons 
having authority with respect thereto and having knowledge of the 
matters therein set forth, and must be verified under oath.


Sec. 33.8  Number of copies.

    An original and eight copies of the application under this part 
must be submitted. If the applicant submits a public and a non-public 
version (containing information filed under a request for privileged 
treatment), the original and at least three of the eight copies must be 
of the non-public version of the filing, pursuant to 
Sec. 388.112(b)(ii). If the applicant must submit information specified 
in paragraphs (b), (c), (d), (e) and (f) of Sec. 33.3 or paragraphs 
(b), (c), (d) and (e) of Sec. 33.4, the applicant must submit all such 
information in electronic format (e.g., on computer diskette or on CD) 
along with a printed description and summary. The electronic version 
must be submitted in accordance with Sec. 385.2011 of the Commission's 
regulations. The printed portion of the applicant's submission must 
include documentation for the electronic submission, including all file 
names and a summary of the data contained in each file. Each column (or 
data item) in each separate data table or chart must be clearly labeled 
in accordance with the requirements of Sec. 33.3 and Sec. 33.4. Any 
units of measurement associated with numeric entries must also be 
included.


Sec. 33.9  Protective order.

    If the applicant seeks to protect any portion of the application, 
or any attachment thereto, from public disclosure pursuant to 
Sec. 388.112 of this chapter, the applicant must include with its 
request for privileged treatment a proposed protective order under 
which the parties to the proceeding will be able to review any of the 
data, information, analysis or other documentation relied upon by the 
applicant for which privileged treatment is sought.


Sec. 33.10  Additional information.

    The Director of the Office of Markets, Tariffs and Rates, or his 
designee, may, by letter, require the applicant to submit additional 
information as is needed for analysis of an application filed under 
this part.

    Note: The following Appendix will not be published in the Code 
of Federal Regulations.


[[Page 71020]]



Appendix--List of Commenters

Abbreviation--Commenter

1. AFPA--The American Forest & Paper Association
2. Antitrust Institute--The American Antitrust Institute
3. APPA/TAPSG--The American Public Power Association/Transmission 
Access Policy Study Group--Wisconsin Public Power Inc., Electric 
Cities of North Carolina, Inc., Florida Municipal Power Agency, 
Illinois Municipal Power Agency, Massachusetts Municipal Wholesale 
Electric Co., Madison Gas & Electric Co., Michigan Public Power 
Agency, Municipal Energy Agency of Nebraska, Northern California 
Power Agency.
4. EEI--Edison Electric Institute
5. FTC Staff--Staff of the Bureau of Economics-Federal Trade 
Commission
6. Gridco Commenters--Ad hoc group of investment interests 
represented by Milbank, Tweed, Hadley & McCloy
7. Indiana Counselor--The Indiana Office of Consumer Counselor
8. Industrial Consumers--Electricity Consumers Resource Council, 
American Iron and Steel Institute, Chemical Manufacturers 
Association
9. IOU's--LG&E Energy Corp., Northern States Power Cos. (Minnesota 
and Wisconsin), OGE Energy Corporation, U.S. Generating Co.
10. Morris--J.R. Morris of Economists Inc.
11. Midwest ISO Participants--Cinergy Corp., Commonwealth Edison 
Co., Wisconsin Electric Power Co., Hoosier Energy Rural Electric 
Cooperative, Inc., Wabash Valley Power Association, Inc., Ameren, 
Kentucky Utilities Co., Louisville Gas & Electric Co., Illinois 
Power Co., Central Illinois Light Co.
12. Missouri Commission--The Missouri Public Service Commission
13. NARUC--The National Association of Regulatory Utility 
Commissioners
14. NASUCA--The National Association of State Utility Consumer 
Advocates
15. New York Commission--The Public Service Commission of the State 
of New York
16. NRECA--National Rural Electric Cooperative Association
17. Ohio Commission--The Public Utilities Commission of Ohio
18. Sempra--Sempra Energy
19. Southern--Southern Company
20. Sustainable Policy--Project for Sustainable FERC Energy Policy
21. WEPCO--Wisconsin Electric Power Company/Putnam, Hayes & 
Bartlett, Inc.

[FR Doc. 00-29676 Filed 11-27-00; 8:45 am]
BILLING CODE 6717-01-P


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