70984 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

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 ¶ 31,044

(1996), reconsideration denied, Order No. 592–A,

62 Fed. Reg. 33,34 (1997), 79 FERC ¶ 61,321 (1997)

(Policy Statement).

2Policy Statement at p. 30,111 n.3.

3 16 U.S.C. 824b.

4Revised Filing Requirements Under Part 33 of

the Commission’s Regulations, Notice of Proposed

Rulemaking, 63 Fed. Reg. 20340 (1998), FERC

Statutes and Regulations ¶ 32,258 (1998) (NOPR).

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.

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outdated or no longer useful to the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

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 nonmerger 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

Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations 70985

5The commenters, and abbreviations for them as

used herein, are listed in the Appendix attached to

this Final Rule.

6Policy Statement at p. 30,128.

7Although we apply these factors to other section

203 transactions as well, the filing requirements

and the level of detail required may differ.

8U.S. Department of Justice and Federal Trade

Commission, Horizontal Merger Guidelines, 57 FR

41,552 (1992), revised, 4 Trade Reg. Rep. (CCH)

¶ 13,104 (Apr. 8, 1997).

9See Atlantic City Electric Company and

Delmarva Power & Light Company, 80 FERC

¶ 61,126 at 61,412, order denying reh’g, 81 FERC

¶ 61,173 (1997) (Atlantic City/Delmarva).

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.

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.

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.

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

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

70986 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

10See, e.g., Enova Corporation and Pacific

Enterprises, 79 FERC ¶ 61,372 (1997) (Enova) and

Dominion Resources, Inc. and Consolidated Natural

Gas Company, 89 FERC ¶ 61,162 (1999) (Dominion/

CNG). 11 Id., n. 12.

12Although 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.

competitive effects of proposed vertical

mergers.10

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

§ 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

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

(§ 33.2(a) through (l)) and nine exhibits

(§ 33.3 Exhibits A through I) that an

applicant must file. Some of these

requirements overlap. For example,

§§ 33.2(i) and 33.3 Exhibit G both

concern applications filed with state

commissions. Therefore, the NOPR

proposed to consolidate these sections

into § 33.2(i). Other information

requirements are no longer relevant to

our review of applications filed under

this part. An example is § 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 §§ 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 § 33.10, which stated that the

Commission will ‘‘ordinarily’’ act

within 45 days on section 203

applications.12 In addition, the NOPR

proposed revising § 33.6, which would

incorporate the requirement of the

current § 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

No revision will be implemented to

proposed § 33.1—Applicability.

No change was proposed to

§ 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 § 33.2(c)—Description of the

applicant—incorporates the

requirements of current §§ 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

Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations 70987

14Policy 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.

15Supplementing the application with orders

from other regulatory bodies will not normally

delay the processing of an application.

16This information is needed so that we can

determine the existence of interlocking directorates.

requires that organizational charts be

filed.

Proposed § 33.2(d)—Description of

the jurisdictional facilities—requires a

general description of each applicant’s

jurisdictional facilities.

Proposed § 33.2(e)—Description of the

proposed transaction—incorporates the

old §§ 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.

Proposed § 33.2(f)—Contracts related

to the proposed transaction—

incorporates the requirements of the old

Exhibit H.

Proposed § 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 § 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 § 33.2(i)—Other regulatory

approvals—incorporates the

requirements of the old § 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, § 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.

Proposed § 33.8—Number of copies—

includes the information required in the

old § 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 §§ 33.3 and 33.4.

Proposed § 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 §§ 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

§ 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 nonmerger 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

§ 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 intracorporate 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 § 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

§ 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

§ 33.2(c)(3), we will now require that

organizational charts be filed showing

70988 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

17For 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.

18Policy Statement at p. 30,119.

19Policy Statement, p. 30,113. See also, Duke

Power Company and PanEnergy Corporation, 79

FERC ¶ 61,236 (1997) (Duke); NorAm Energy

Services, Inc., 80 FERC ¶ 61,120 at 61,379 and n.13

(1997) (NorAm); Morgan Stanley Capital Group Inc.,

et al., 79 FERC ¶ 61,109 at 61,503–04 (1997)

(Morgan Stanley); and Boston Edison Company and

BEC Energy, 80 FERC ¶ 61,274 (1997).

20We 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 ¶ 61,107

at 61,491–96 (1997).

21The electronic filing requirements are set forth

in § 33.8 of the revised regulations.

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.

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 § 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.

Revised § 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.

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 § 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

§ 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

§ 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 § 33.3) or a vertical

competitive analysis (as provided in

§ 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.

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

§§ 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 § 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 § 33.4.20

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.

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

Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations 70989

23American Electric Power Co. and Central and

South West Corp., 85 FERC ¶ 61,201; reh’g denied,

87 FERC ¶ 61,274 (1999) (AEP/CSW).

24Among the information the FTC Staff suggests:

internal documents of the merging parties; thirdparty 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.

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.

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 §§ 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 §§ 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.

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.

WEPCO notes that under the HartScott-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

70990 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

25APPA/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.

26See e.g., UtiliCorp United Inc. and St. Joseph

Light & Power Co. and UtiliCorp United Inc. and

Empire District Electric Co., 92 FERC ¶ 61,067

(2000) (Utilicorp/St. Joseph), AEP/CSW; Allegheny

Energy, Inc. and DQE, Inc., 84 FERC ¶ 61,223 (1998)

(APS/Duquesne).

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.

28Sierra Pacific Power Co., Nevada Power Co. and

Portland General Electric Co., 92 FERC ¶ 61,069

(2000).

29Policy Statement at p. 30,118.

30These specific filing requirements are set forth

in § 33.3 of the revised regulations.

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 notso-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

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 ‘‘megamergers’’ 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.

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.

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, § 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 § 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

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

Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations 70991

31Commonwealth Edison Company and PECO

Energy Company, 91 FERC ¶ 61,036 (2000) (PECO/

ComEd).

32The specific filing requirements for applicants

addressing mitigation measures and additional

factors are set forth in § 33.3(e) and § 33.3(f),

respectively. 33See below note 77.

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

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.

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, shortterm 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.

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

70992 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

34Regional Transmission Organizations, Order

No. 2000, 65 Fed. Reg. 809 (Jan. 6, 2000), FERC

Statutes and Regulations at 31,135 (1999).

35Policy Statement at p. 30,130.

36Consolidated Edison, Inc. and Northeast

Utilities, 92 FERC ¶ 61,225 (2000), reh’g denied, 92

FERC ¶ 61,014 (2000) (ConEd/NU) and Energy East

Corp. and CMP Group, 91 FERC ¶ 61,001 (2000)

(Energy East/CMP).

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.

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.’’

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.

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 offpeak 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

Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations 70993

37The price would include payments for

transmission and ancillary services needed to

deliver the power.

38Policy Statement at pp. 30,130–31.

39The 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 longterm 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.’’

40Southern 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.

41Baltimore Gas & Electric Company and

Potomac Electric Power Company, Opinion No.

412, 76 FERC ¶ 61,111 (1996), 79 FERC ¶ 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.

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.

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).

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.

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.

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

70994 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

42We have noted such discrepancies in data

received from applicants in our analysis in a prior

case. See BG&E/PEPCO, pp. 61,119–120.

43Native 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.

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

45Hourly data are available in electronic format

from the FERC Form 714, Annual Electric Control

and Planning Area Report.

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.

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.

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 marketbased, 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.

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 § 33.3(d)(4)

of the revised regulations.

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

Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations 70995

46Policy statement at pp. 30,131.

47Rates 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.

48For 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.

49Policy Statement at p. 30,131.

50Atlantic City/Delmarva, p. 61,408.

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 nonpublic 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.

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

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 § 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 premerger 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

As discussed in the Policy Statement,

the Commission does not believe that all

electricity markets have matured

sufficiently to exhibit single marketclearing 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

70996 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

51Ohio Edison Company, et al., 80 FERC ¶ 61,039

at 61,105–6 (1997) (FirstEnergy).

52Examples include Energy East/CMP, ConEd/

NU, and NiSource Inc. and Columbia Energy Group,

92 FERC ¶ 61,068 (2000) (NiSource/Columbia

Energy).

53When transmission constraints are binding,

identical prices in adjacent markets may still occur,

although this is unlikely.

54See, CP&L/Florida Progress, in which prices

based on system lambda and observed ‘‘Market

Power Week’’ data were different.

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.

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.

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.

The specific filing requirements for

market price data are set out in

§ 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

Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations 70997

55First Energy, p. 61,104.

56See, 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.

57See, e.g., Northern States Power and New

Centuries, Inc., 91 FERC ¶ 61,157 (2000) reh’g

pending (NSP/New Century), where the applicants

modeled the effect of the integration on

transmission availability.

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.

59Wisconsin Electric Power Company, et al.

(Primergy), 79 ¶ 61,158 at 61,694 (1997), and

FirstEnergy at 61,107.

60FirstEnergy, pp. 61,103–04.

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.

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 flowbased models.56 As the industry

continues to develop flow-based

models, we encourage applicants to

adopt these methods for estimating

transmission availability.57

The specific filing requirements for

transmission capability data are set out

in § 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 longterm 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.

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 § 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.

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

70998 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

61See e.g., APS/Duquesne, Louisville Gas and

Electric Co., Kentucky Utilities Co., and PowerGen

plc, 91 FERC ¶ 61,321 (2000).

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.

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

§ 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

Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations 70999

62The 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.

63Since 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 ¶ 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

Continued

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 §§ 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 postmerger 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.

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

71000 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

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 ¶ 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.

64For 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.

65These factors are those discussed in steps two

through five of the DOJ Guidelines.

66 Guidelines, 57 FR at 41,561.

67 Id. at 41,561–562.

68For 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 ¶ 61,158 at 61,695–

696.

69The 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.

70NRECA 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.

71Ohio 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.

The specific filing requirements for

concentration statistics are set out in

§ 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.

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.

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

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.

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

Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations 71001

72After 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 ¶ 31,089 (1999), order on reh’g, Order

No. 2000–A, 90 FERC ¶ 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.

73See, e.g., CP&L/Florida Progress, and UtiliCorp/

St. Joeseph.

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.

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.

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 nearterm projections. It also wants standalone 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 statejurisdictional 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

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

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 § 33.3(e). The specific filing

requirements for additional factors are

set out in § 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

71002 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

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

76A 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).

77See, e.g., AEP/CSW, NSP/New Century, and

CPL/Florida Progress.

78We 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.

79We 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.

consolidating them is likely to have a

negligible effect on market

concentration.75

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

Furthermore, we will not require

section 203 applicants to provide a

competitive analysis under §§ 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 procompetitive. Moreover, the standards set

forth in Order No. 2000 require

Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations 71003

80Policy Statement at p. 30,113.

81See e.g., Enova, AEP/CSW, Dominion/CNG,

Long Island Lighting Co. 82 FERC ¶ 61,214, reh’g

denied, 83 FERC ¶ 61,076 (1988) (LILCO), NorAm,

Duke/PanEnery, PG&E Corporation and Valero

Energy Corporation, 80 FERC ¶ 61,041 (1997)

(PG&E/Valero); Destec Energy, Inc. and NGC

Corporation, 79 FERC., ¶ 61,373 (1997) (Destec/

NGC); Enron Corporation, 78 FERC & 61,179 (1997)

Enron.

82See, Illinova Corporation and Dynergy Inc., 89

FERC ¶ 61,163 (1999).

83These specific filing requirements are set forth

in § 33.4 of the revised regulations.

84There may be several relevant upstream input

products (such as fuel, transportation and turbine

manufacturers).

85Horizontal 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.

86See Enova, 79 FERC ¶ 61,372 at 62,560.

87Foreclosure can also result from a vertical

merger if the downstream merging firm refuses to

purchase from input suppliers other than its

upstream affiliate.

88See, Enova, 79 FERC ¶ 61,372 at 62,560.

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.

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.

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.

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.

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.

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

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

71004 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

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.

90One 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.

91See, 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)).

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.

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 lowcost 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

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.

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

Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations 71005

92Regulatory evasion could effect requirements

service customers in wholesale electricity markets.

However, this is less likely to be a concern if

wholesale markets are competitive.

93NRECA 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.

94Policy Statement at 30,128.

95See, Duke/PanEnergy, 79 FERC ¶ 61,236 at

62,039. 96See supra note 29.

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.

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.

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.

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

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.

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

71006 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

97See supra note 29.

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.

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 welldocumented. 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 §§ 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

Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations 71007

98See, Enova, 79 FERC ¶ 61,372 at 62,562. If

multiple upstream suppliers serve a single

generating plant or unit, applicants’ analysis must

take this into account.

99The DOJ 1984 Merger Guidelines address

vertical mergers and discuss both market share and

HHI statistics. See DOJ 1984 Merger Guidelines at

46.

100The 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.

101See, American Electric Power Company, 90

FERC ¶ 61,242.

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

§ 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

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.

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.

The specific filing requirements for

assessing the competitive conditions in

the downstream market are set forth in

§ 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

71008 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

102See DOJ 1984 Merger Guidelines §§ 4.211 and

4.212.

103See, Vastar Resources, Inc., et al., 81 FERC

¶ 61,135 at 61,633.

104See Pipeline Service Obligations and

Revisions to Regulations Governing SelfImplementing 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. ¶ 30,939 (April 8,

1992), order on reh’g, Order No. 636–A, FERC Stats,

& Regs. ¶ 30,950 (August 2, 1992), order on reh’g,

Order No. 636–B, 61 FERC ¶ 61,272 (November 27,

1992), reh’g denied, Order No. 636–C, 62 FERC

¶ 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 ¶ 61,816 (1997).

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.

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.

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 marketsensitive 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.

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

Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations 71009

105Enova, 79 FERC ¶ 61,372 at 62,565 (1997).

106Policy 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.

107Policy 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.

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 § 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, selfreported 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

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

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 § 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.

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.

71010 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

108Policy Statement at p. 30,125. 109NOPR, p. 33,383.

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

§ 33.2(g)(1) of the revised regulations.

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 computerbased 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.

Comments

Several commenters agree that a

computer model may be useful in the

Commission’s analysis of mergers and

that the Commission should develop inhouse 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

Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations 71011

110NOPR, pp. 33,383–84.

111Missouri 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).

112NOPR, p. 33,368.

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.

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.

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.

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

71012 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

113Policy Statement at p. 30,127–28.

114 5 U.S.C. 601(3) (citing § 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.

116 18 CFR Part 380.

117 18 CFR 380.4(a)(16).

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.

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

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

Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations 71013

118 44 U.S.C. 3507(d). 119 61 FR 21, 540, May 10, 1996. 120 65 FR 809, January 6, 2000.

assessment nor an environmental

impact statement is required.

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.

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.

Data collection No. of

respondents

No. of

responses

Hours per

response

Total annual

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.

Data collection

Annualized

capital/start-up

costs

Annualized ongoing costs

(operations

and

maintenance)

Total

annualized

costs

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 × 107 filings × 8 = $3,980,400.

(b) Simple merger $630,828 × 7 filings = $ 4,415,796.

(c) Complex merger $5,285,400 × 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 § 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

71014 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

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

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.

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 mike.miller@ferc.fed.us) 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).

• CIPS provides access to the texts of

formal documents issued by the

Commission since November 14, 1994.

• 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.

• 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

WebMaster@ferc.fed.us) or the Public

Reference Room at (202) 208–1371 (EMail to

public.referenceroom@ferc.fed.us).

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.

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.

§ 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.

§ 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

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

§ 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

71016 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

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 longterm 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 HerfindahlHirschman 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’

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

71018 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

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 nonfirm, 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.

§ 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 § 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 § 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 § 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

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

§ 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.

§ 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 31⁄2′′ 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 lllll.

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.

§ 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.

§ 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

§ 388.112(b)(ii). If the applicant must

submit information specified in

paragraphs (b), (c), (d), (e) and (f) of

§ 33.3 or paragraphs (b), (c), (d) and (e)

of § 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

§ 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 § 33.3 and § 33.4. Any

units of measurement associated with

numeric entries must also be included.

§ 33.9 Protective order.

If the applicant seeks to protect any

portion of the application, or any

attachment thereto, from public

disclosure pursuant to § 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.

§ 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.

71020 Federal Register / Vol. 65, No. 229 / Tuesday, November 28, 2000 / Rules and Regulations

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