Federal Energy Regulatory Commission DOE.
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facilities that raise no competitive concerns and eliminates certain filing requirements in part 33 that are outdated or no longer useful to the Commission in analyzing mergers and other dispositions of jurisdictional facilities.
This Final Rule will become effective January 29, 2001.Start Further Info
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) 208-1247End Further Info End Preamble Start Supplemental Information
Table of Contents
I. Introduction and Summary
A. Revisions to Part 33—Basic Information Requirements
B. Revised Filing Requirements Applicable to Merger Filings
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. 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.
Following the issuance of the Policy Statement, applications filed pursuant to section 203 of the Federal Power Act (FPA)  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  to revise 18 CFR part 33 by specifying clear and succinct filing requirements for all applications submitted pursuant to section 203 of the FPA (including non-merger transactions). In this NOPR, the Commission analyzed information that is needed to evaluate section 203 applications to determine how the filing requirements under part 33 could be made more helpful to the electric industry, intervenors and businesses operating in the emerging competitive landscape. The proposed revised filing requirements were intended to provide greater certainty about what needed to be filed in section 203 applications. This would allow applicants to prepare their proposals more quickly and efficiently and to better predict the outcome of the Commission's evaluation. The proposed requirements Start Printed Page 70985would 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, 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;  (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.
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. 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)  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.
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 Start Printed Page 70986competitive effects of proposed vertical mergers.
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.
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.
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. 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.
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 Start Printed Page 70987requires 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, 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. 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.
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.
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 non-merger applications within 90 days of filing, on average. We intend to continue this practice.
Also, the Exhibit H filing requirements are now reflected in new § 33.2(f). Although we are not revising these filing requirements, we take this opportunity to clarify that all section 203 filings must include a copy of all contracts pertaining to the proposed disposition and/or such other agreements (in final or, if not available, in draft form) and must identify: (1) All relevant parties to the transaction and their roles in the transaction (e.g., as seller, purchaser, lessor, lessee, operator); (2) the jurisdictional facilities that are being disposed of and/or acquired, directly or indirectly; and (3) all terms and conditions of the proposed disposition that pertain to the ownership, leasing, control of, or operation of jurisdictional facilities. If contracts pertaining to the section 203 disposition have not been finalized at the time of filing, or, in the case of intra-corporate transactions, if applicants claim there will be no contracts associated with the disposition, applicants may submit a draft contract, a term sheet, a letter of intent or a memorandum of understanding to satisfy the § 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, and jurisdictional transactions. Also, pursuant to § 33.2(c)(3), we will now require that organizational charts be filed showing Start Printed Page 70988the 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  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. 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
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. 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.
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. 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. 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 Start Printed Page 70989consistent 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.
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.
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.
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, 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.  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 Hart-Scott-Rodino approach to consideration of mergers by the antitrust agencies, there is substantial interaction between agency staff and interested parties that has better promoted understanding of merger-related problems. WEPCO suggests that one way to improve the communication among Commission staff, applicants and intervenors, given the quasi-judicial functions of the Commission and its ex parte restrictions, would be for staff to prepare a report summarizing its preliminary findings; merger applicants and other interested parties could comment upon that report. Staff would then revise its conclusions as appropriate to take into account any Start Printed Page 70990new information developed in the comment process.
Several commenters express concern that applicants provide full disclosure of the required data. APPA/TAPS cautions that despite the fact that filing requirements focus on the past, current, and near future, they cannot accurately capture the dynamic changes in the not-so-near future. Full disclosure of all information that may bear on future competitive activities and changes, such as retail competition, is vital to the screening process.
NRECA recommends a two-track merger review policy to foster flexibility. It suggest fast-track review of mergers of small and medium-sized utilities that would not adversely affect competition in a relevant regional market and that could enhance regional competition by creating a stronger, more viable competitor. NRECA believes that such a two-track review process would allow the Commission to more effectively scrutinize proposed “mega-mergers” where the Commission's horizontal screen indicates the potential to create or exacerbate market dominance.
Finally, APPA/TAPS cautions against applying the institutional framework and processes for reviewing ordinary rate filings to evaluating mergers. They state that the analysis produced by the filing requirements will not yield a reliable answer to the fundamental question of the effect of a merger on future competitive markets. They therefore urge the Commission not to follow a mechanistic approach to evaluating mergers.
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. 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. For example, in Sierra Pacific we proposed a technical conference as an appropriate avenue of communication among Commission staff, applicants and intervenors. 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.
The competitive analysis screen  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 Start Printed Page 70991down 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.
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. 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
Applicants must identify the wholesale electricity products sold by the merging firms. At a minimum, such products include non-firm energy, short-term capacity (or firm energy), and long-term capacity. Products should be grouped together when they are reasonable substitutes for each other from the buyer's perspective. Supply and demand conditions for particular electricity products may vary substantially over time and, if so, the analysis should take this into account. Periods with similar supply and demand conditions should be aggregated. Thus, applicants must define and describe all products sold by the firms, explain and support the market conditions and groupings, and provide all data relied upon for product definition.
In the NOPR, we stated that as restructuring in the wholesale and retail electricity markets progresses, short-term markets appear to be growing in importance. We sought comments on the assessment of long-term capacity markets in merger analysis.
The delivered price test, which we require applicants to use to identify potential suppliers in a market, focuses on the ability of suppliers to deliver energy to relevant markets as measured by their short-term variable costs. However, there is no good measure for long-term capacity prices per se. Therefore, we sought comments on the appropriate analytic framework for evaluating long-term capacity products.
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.
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, 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 Start Printed Page 70992of 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. 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.
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. 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). We proposed that applicants be required to provide all data used in determining the affected customers.
FTC Staff remarks that the list of affected customers produced by the delivered price test provides only a limited picture of the customers who may be harmed by a merger. It notes that in their own experience, suppliers' pricing decisions focus on attracting new customers that often are not on lists of current customers. FTC Staff also contends that if a potential anticompetitive effect of a merger involves increased coordination among suppliers, the harmful effects of the acquisition may go beyond customers of the merging parties to include many customers supplied by non-merging companies. Lastly, it explains that if a potential anticompetitive effect of a merger is slower entry into new geographic markets, the affected consumers will (by definition) be those located where the parties have not previously done business. Without information about these potential customers, the FTC Staff states, merger analysis may underestimate present and future demand elasticity or incentives to innovate. Therefore, FTC Staff recommends the Commission broaden its concept of affected customers to include potential customers and customers of third-party suppliers in the market(s) served by the merging parties.
Because transmission constraints may bind during peak demand periods, the FTC Staff suggests that more care be taken when defining geographic markets. In an ISO that is divided into zones, such as California, during off-peak hours the relevant geographic market could be the entire ISO, while during the peak hours each zone could be a relevant geographic market. Since, in general, the broader the geographic area the less concentrated the market, applicants should justify the use of a broad geographic market with evidence that the market definition remains viable during peak times. If not, the FTC Staff suggests, the market definitions should be narrowed for peak periods.
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 Start Printed Page 70993load 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)
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  no more than five percent above the pre-merger market price. 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)  and available economic capacity (AEC).
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. 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.
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. 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
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 Start Printed Page 70994potential 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. 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
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
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. 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.
A number of commenters raised issues regarding native load obligations. For example, WEPCO asserts that retail choice reduces native load obligations and correspondingly increases AEC and available transmission capability (ATC) in wholesale bulk power markets. It states that under full retail competition with complete release of native load, AEC converges to EC. In states where retail competition is not on the horizon, AEC still provides useful information. WEPCO, therefore, suggests the Commission consider the value of AEC on a case-by-case basis.
NASUCA and Missouri Commission argue that since retail choice is quickly expanding throughout the country, the Commission should not rely on AEC. With retail choice comes the release of some or all of a utility's native load obligation. In addition, under retail choice, rates for native load customers that had been regulated become market-based, increasing the ability of anticompetitive behavior to raise rates. NASUCA and Missouri Commission also point out that the Commission noted in the NOPR that the assumption that a utility uses its least-cost generation to serve its native load may no longer hold under retail competition, to whatever extent it currently holds.
The FTC Staff argues the impending release of native load requirements has different competitive implications for a merger before and after retail choice programs are enacted. It suggests the Commission look at two scenarios: one considering those suppliers that are constrained by native load obligations (representing the near-term) and one considering those that are not (representing the long-term). EEI recommends the Commission require applicants to perform tests of the sensitivity of their delivered price test results to changes in assumptions regarding retail choice.
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. 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. 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
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 Start Printed Page 70995analyses 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.
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.
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
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. For purposes of competitive analysis screen, applicants must use the maximum tariff rates in public utilities' open access tariffs on file with the Commission. The NOPR pointed out that where a non-public utility's transmission system is involved, the maximum tariff rates under any non-jurisdictional (NJ) open access reciprocity tariff should be used. If an NJ tariff for an entity has not been submitted to the Commission, the NOPR proposed that applicants use their best efforts to obtain or estimate transmission and ancillary services rates. 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.
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.
As discussed in the Policy Statement, a supplier's capacity may be included in a relevant market, for purposes of the competitive analysis screen, if it can be delivered into the market at a price that is no more than 5 percent above the pre-merger market price. 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.
As discussed in the Policy Statement, the Commission does not believe that all electricity markets have matured sufficiently to exhibit single market-clearing prices for various products. Therefore, in the NOPR we sought comments on appropriate criteria for determining when surrogate measures are needed. We did not require a specific method for estimating market prices. However, we stated that the results must be supported and consistent with what one would expect in a competitive market. For example, we would expect prices to vary little from customer to customer in the same region during similar demand conditions (if there are no transmission constraints), but we would expect prices to vary between peak and off-peak Start Printed Page 70996periods. 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.
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.
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. 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. 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. 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.
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 Start Printed Page 70997example, 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. 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 flow-based models. As the industry continues to develop flow-based models, we encourage applicants to adopt these methods for estimating transmission availability.
The specific filing requirements for transmission capability data are set out in § 33.3(d)(7) of the revised regulations.
Firm Transmission Rights
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.
The New York Commission contends that along with long-term transmission rights, transmission congestion contracts (TCCs) need to be considered in analyzing market power. The New York Commission further states that a market participant who owns generation in a higher-priced market along with a substantial amount of transmission rights or TCCs could increase the value of its TCCs by withholding generation, thereby causing the market price to rise.
In addition, WEPCO expresses concern that confusion may arise as to whether a long-term transmission reservation is associated with a long-term transaction in light of ongoing industry restructuring.
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. 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
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. 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. 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 Start Printed Page 70998analysis 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.
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.
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. 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
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
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 Start Printed Page 70999markets 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
Under the Policy Statement, the final step of the competitive analysis screen is to assess market concentration. Applicants must file pre- and post-merger market concentration statistics calculated in accordance with the preceding sections. Both HHIs and single-firm market share statistics must be presented.
The HHI statistics are compared with the thresholds given in the Guidelines. 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.
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.
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.Start Printed Page 71000
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
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. 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. 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. 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. 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.
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. NRECA advocates structural remedies only in extraordinary circumstances. 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, behavioral rules, functional unbundling, structural Start Printed Page 71001separation, 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 near-term projections. It also wants stand-alone cost estimates based on the assumption that all prudent and reasonable steps to operate efficiently would be undertaken by each of the merging parties continuing to act as individual firms. Finally, Antitrust Institute wants any claimed benefits that are derived from capacity deferrals to be shown in terms of the present value of delaying capital costs less increases in fuel costs implied by the postponements.
The Ohio Commission argues that merger savings should benefit jurisdictional ratepayers as well as shareholders and that applicants' proposed allocation of merger savings among wholesale and state-jurisdictional customers should be disclosed in the merger application.
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. 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.
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.
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
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 Start Printed Page 71002consolidating them is likely to have a negligible effect on market concentration.
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.
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.
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. 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. 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.
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. Our decision not to require RTO applications to provide a competitive analysis is consistent with our strong belief that participation in RTOs is pro-competitive. Moreover, the standards set forth in Order No. 2000 require Start Printed Page 71003extensive 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
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). 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. 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.
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.
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. 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. 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;  (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. This effect can be brought about by: (1) Foreclosure/raising of rivals' costs; (2) facilitating coordination; and (3) regulatory evasion.
Foreclosure/Raising Rivals' Costs
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. Raising rivals' costs can also deter entry of rival generators in the downstream market. 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 Start Printed Page 71004markets. 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.
Several parties want to eliminate the need for a detailed vertical analysis once it becomes clear that merging firms lack the ability to raise rivals' costs. For example, EEI states that when a downstream firm has easy access to alternative suppliers of natural gas or a dual-fired generation facility has low-cost fuel oil alternatives, the upstream firm has no market power. Similarly, Southern points out that a large number of natural gas storage facilities can protect against a withholding of natural gas services by suppliers. In either case, the analysis should stop, since it is clearly demonstrated the merged party has no ability to raise rivals' costs, even if it has the incentive.
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
A vertical merger can facilitate anticompetitive coordination  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.
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.
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.
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. 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.
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.
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 Start Printed Page 71005an issue. 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.”  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.
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. 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
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.
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. (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
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 Start Printed Page 71006must 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:  (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
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.
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.
We proposed that applicants must identify the products produced by the upstream merging firm and used by the downstream merging firm and/or its competitors in the production of relevant downstream electricity products. Upstream products can be grouped together whenever they are good substitutes for each other from the buyer's perspective. Products may also be differentiated with respect to time, since supply and demand conditions vary considerably over the year.
We also proposed the relevant products identified by the applicant must be explained and well-documented. The Commission sought comments on the proposed approach, any alternative approaches to defining relevant input products, and how such approaches will vary for different types of inputs.
Geographic Markets—Downstream Market
Defining the downstream geographic market consists of identifying the customers potentially affected by the merger and the suppliers that can compete with the merging firm to supply a relevant electricity product. In the regulations for the horizontal screen analysis, relevant geographic electricity markets are defined using the delivered price test and if applicants so choose, additional methods that are adequately supported. Under the delivered price test, a supplier is considered to be in the market if it has generating capacity from which energy can be made available and delivered to the market at a price, including transmission and ancillary services, no more than five percent above the market price.
In the NOPR, the Commission proposed that the relevant downstream geographic market in a vertical merger would be defined similarly to those in the proposed regulations for the horizontal analytic framework. However, we sought comments on the appropriateness of the delivered price test analysis for analyzing downstream markets in vertical mergers. We also solicited comments on any alternative approaches to defining downstream geographic markets in a vertical merger.
Geographic Markets—Upstream Market
In the NOPR, the Commission did not propose precise filing requirements for defining upstream geographic markets. One reason was that the Commission had not yet acted upon an application for a merger with vertical aspects that required a rigorous definition of the upstream geographic market. Another reason was that the types of analysis and data needed to define geographic upstream markets may vary from input to input. The Commission expected to better understand the data and analysis needed to define geographic input markets—if such analysis proved necessary—as we evaluated proposed vertical mergers. Until such time, the Commission proposed that applicants approximate the upstream geographic market for each relevant upstream product and submit data and documentation necessary to support their analyses. Such approximate definitions of the upstream geographic market could be based on historical trade data. We proposed that applicants define the smallest reasonable geographic markets.
We proposed that applicants fully explain, justify and document their analysis, including all supporting data and documentation. We sought comment on appropriate approaches to defining upstream geographic markets in vertical mergers.
Comments and Commission Conclusion
No specific comments were submitted with respect to relevant products and geographic markets in a vertical analysis. However, comments on horizontal “Relevant Geographic Markets” apply to downstream markets when considering a vertical analysis. We also note that the Commission has provided guidance on defining upstream relevant geographic markets involving mergers of companies with interests in generation and delivered gas in Dominion. Accordingly, as discussed in this section, we adopt the NOPR requirements. The filing requirements for this aspect of the analytic framework are set forth in §§ 33.4(c)(1) and 33.4(c)(2) of the revised regulations.
Evaluating Competitive Conditions in Geographic Markets
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 Start Printed Page 71007concentration in the upstream market, along with any alternative approaches.
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.
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.
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.
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. 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. We sought comments on this approach to assessing market shares and market concentration in the downstream market, along with any alternative approaches.
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.
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  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 Start Printed Page 71008would 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. 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
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.
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.
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.
The Commission is mindful of the delicate balance between the public's (including intervenors') right to know and the protection not only of certain commercially-sensitive information, but of the competitive marketplace itself. Thus, the Commission will not forego the use of protective orders, but will instead make careful use of them if needed to gather and analyze market-sensitive information. The Commission will not place restrictions on itself as to the types of data it will collect, but will take into account the desire of applicants to protect their competitive positions.
We will require that applicants evaluate whether customers of the upstream input supplier can switch to alternative inputs to avoid a price increase by the upstream merging firm. If switching to alternative inputs is possible, the merger may not create or enhance the ability of the merging firm to affect output and prices in the upstream market.
We will require that applicants provide data showing how regulatory requirements governing the conduct of upstream input suppliers (such as open access provisions applicable to gas pipelines under Order No. 636)  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 Start Printed Page 71009or 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
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.
The FTC Staff remarks that in order to assess coordinated interaction, more than market share statistics need to be gathered. The Horizontal Merger Guidelines focus on the conditions likely for collusion to take place. Successful coordinated interaction includes reaching agreement on profitable coordination among companies, detecting deviations from that agreement, and punishing any such deviation. A better analysis of the increased likelihood of coordinated interaction, according to the FTC Staff, results when market share statistics are supplemented with other sources of information. For example, market share statistics would not reveal the fact that a merger might adversely affect competition by eliminating a maverick firm.
To better address coordinated interaction concerns, the FTC Staff recommends that the Commission go beyond market share analysis to potentially useful third party information. The FTC Staff suggests that since firms have little incentive to accurately estimate their own abilities to engage in anticompetitive conduct, self-reported estimates should be validated independently. Otherwise, the Commission may be relying on inaccurate data.
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
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.
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
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.
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
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. 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.
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. Start Printed Page 71010
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. 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
In the NOPR, the Commission solicited comments on a number of emerging issues in the electric industry that could have significant effects on its proposed filing requirements. These issues include the use of computer-based simulation models; if and how to account for restructuring, retail competition, and other types of competitive issues in merger analysis; and suggestions of a moratorium on mergers in the electric industry. We received numerous comments in response to these questions, as discussed below.
A. Computer-Based Simulation Models
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. 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.
Several commenters agree that a computer model may be useful in the Commission's analysis of mergers and that the Commission should develop in-house expertise in developing models. However, commenters also recommend the Commission not rush to adopt a computer model, acknowledging that there is no model currently available that should be adopted as a standard. Some commenters argue that flexibility is important, and that a combination of models may be needed but that the use of too many models may become burdensome on smaller utilities and public interest groups. However, commenters also note the various benefits of using computer models in merger analysis. For example, the FTC Staff explains that power-flow models can be useful in analyzing issues arising in both horizontal and vertical mergers; however, it also notes that current models address only the technical aspects of power flows and not the economic aspects of trading in a deregulated wholesale market. The FTC Staff also advises that it expects more flexible, reliable, and accurate models to be developed and soon become commercially available. It suggests the Commission remain flexible in its approach to merger analysis, particularly as it pertains to computer modeling, so as to allow competition among vendors and development of the best models. On the other hand, Sempra cautions against adopting computer models for merger analysis because divestiture of generation assets to unregulated entities and the construction of unregulated plants reduces the availability of public data needed to run models and because use of a model also may cause more disputes and thus more hearings.
WEPCO notes that the main advantage of models of the type proposed by the Commission is that they simulate the interaction among all loads and resources in arbitraging prices in various destination markets. Since such a model calculates prices for each load area, WEPCO claims there is no need to define geographic markets, since any area in which the merger has a significant price effect is a relevant market. WEPCO points out that such modeling can be used to determine whether mergers eliminate competitors, to explore geographic definitions, and to corroborate the results of a structural analysis.
EEI believes that future uses of computer simulation models could provide more complex behavioral analysis beyond the structural approach underlying the hypothetical monopolist test. Such an approach, EEI comments, will enhance the Commission's ability to remedy potential problems posed by proposed mergers, especially considering the need to avoid wasting resources with mitigation measures that impose unnecessary costs.
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 Start Printed Page 71011discuss 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
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. 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.
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. 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. 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 Start Printed Page 71012most 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.
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, 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
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.
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. A description and analysis of the rule's effect on small businesses is therefore not required by the Regulatory Flexibility Act.
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. 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. Consequently, neither an environmental Start Printed Page 71013assessment 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, 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|
|(b) Simple merger||7||1||1,509||10,563|
|(c) Complex merger||7||1||12,557||87,899|
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 on-going costs (operations and maintenance)||Total annualized costs|
|(a) W/o analysis||$0||$37,200||$37,200|
|(b) Simple merger||15,300||615,528||630,828|
|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  and Order No. 2000  to promote competitive, well-functioning markets Start Printed Page 71014while 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 email@example.com) 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 (E-Mail to firstname.lastname@example.org).
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. The Rule will be submitted to both Houses of Congress and the Comptroller General.Start List of Subjects
List of Subjects in 18 CFR Part 33
- Electric utilities
- Reporting and recordkeeping requirements
By the Commission.
Linwood A. Watson, Jr.,
In consideration of the foregoing, the Commission revises Part 33, Chapter I, Title 18 of the Code of Federal Regulations, as follows:End Amendment Part Start Part
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
- Contents of application—general information requirements.
- Additional information requirements for applications involving horizontal competitive impacts.
- Additional information requirements for applications involving vertical competitive impacts.
- Proposed accounting entries.
- Form of notice.
- Number of copies.
- Protective order.
- Additional information.
(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.
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 Start Printed Page 71015communications regarding the application, including phone and fax numbers, and E-mail addresses.
(c) A description of the applicant, including:
(1) All business activities of the applicant, including authorizations by charter or regulatory approval (to be identified as Exhibit A to the application);
(2) A list of all energy subsidiaries and energy affiliates, percentage ownership interest in such subsidiaries and affiliates, and a description of the primary business in which each energy subsidiary and affiliate is engaged (to be identified as Exhibit B to the application);
(3) Organizational charts depicting the applicant's current and proposed post-transaction corporate structures (including any pending authorized but not implemented changes) indicating all parent companies, energy subsidiaries and energy affiliates unless the applicant demonstrates that the proposed transaction does not affect the corporate structure of any party to the transaction (to be identified as Exhibit C to the application);
(4) A description of all joint ventures, strategic alliances, tolling arrangements or other business arrangements, including transfers of operational control of transmission facilities to Commission approved Regional Transmission Organizations, both current, and planned to occur within a year from the date of filing, to which the applicant or its parent companies, energy subsidiaries, and energy affiliates is a party, unless the applicant demonstrates that the proposed transaction does not affect any of its business interests (to be identified as Exhibit D to the application);
(5) The identity of common officers or directors of parties to the proposed transaction (to be identified as Exhibit E to the application); and
(6) A description and location of wholesale power sales customers and unbundled transmission services customers served by the applicant or its parent companies, subsidiaries, affiliates and associate companies (to be identified as Exhibit F to the application).
(d) A description of jurisdictional facilities owned, operated, or controlled by the applicant or its parent companies, subsidiaries, affiliates, and associate companies (to be identified as Exhibit G to the application).
(e) A narrative description of the proposed transaction for which Commission authorization is requested, including:
(1) The identity of all parties involved in the transaction;
(2) All jurisdictional facilities and securities associated with or affected by the transaction (to be identified as Exhibit H to the application);
(3) The consideration for the transaction; and
(4) The effect of the transaction on such jurisdictional facilities and securities.
(f) All contracts related to the proposed transaction together with copies of all other written instruments entered into or proposed to be entered into by the parties to the transaction (to be identified as Exhibit I to the application).
(g) A statement explaining the facts relied upon to demonstrate that the proposed transaction is consistent with the public interest. The applicant must include a general explanation of the effect of the transaction on competition, rates and regulation of the applicant by the Commission and state commissions with jurisdiction over any party to the transaction. The applicant should also file any other information it believes relevant to the Commission's consideration of the transaction. The applicant must supplement its application promptly to reflect in its analysis material changes that occur after the date a filing is made with the Commission, but before final Commission action. Such changes must be described and their effect on the analysis explained (to be identified as Exhibit J to the application).
(h) If the proposed transaction involves physical property of any party, the applicant must provide a general or key map showing in different colors the properties of each party to the transaction (to be identified as Exhibit K to the application).
(i) If the applicant is required to obtain licenses, orders, or other approvals from other regulatory bodies in connection with the proposed transaction, the applicant must identify the regulatory bodies and indicate the status of other regulatory actions, and provide a copy of each order of those regulatory bodies that relates to the proposed transaction (to be identified as Exhibit L to the application). If the regulatory bodies issue orders pertaining to the proposed transaction after the date of filing with the Commission, and before the date of final Commission action, the applicant must supplement its Commission application promptly with a copy of these orders.
(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 Start Printed Page 71016during the two years prior to the date of the application, including, but not limited to, non-firm energy, short-term capacity (or firm energy), long-term capacity (a contractual commitment of more than one year), and ancillary services (specifically spinning reserves, non-spinning reserves, and imbalance energy, identified and defined separately). Because demand and supply conditions for a product can vary substantially over the year, periods corresponding to those distinct conditions must be identified by load level, and analyzed as separate products.
(2) Identify destination markets. Identify each wholesale power sales customer or set of customers (destination market) affected by the proposed transaction. Affected customers are, at a minimum, those entities directly interconnected to any of the merging entities and entities that have purchased electricity at wholesale from any of the merging entities during the two years prior to the date of the application. If the applicant does not identify an entity to whom the merging entities have sold electricity during the last two years as an affected customer, the applicant must provide a full explanation for each exclusion.
(3) Identify potential suppliers. The applicant must identify potential suppliers to each destination market using the delivered price test described in paragraph (c)(4) of this section. A seller may be included in a geographic market to the extent that it can economically and physically deliver generation services to the destination market.
(4) Perform delivered price test. For each destination market, the applicant must calculate the amount of relevant product a potential supplier could deliver to the destination market from owned or controlled capacity at a price, including applicable transmission prices, loss factors and ancillary services costs, that is no more than five (5) percent above the pre-transaction market clearing price in the destination market.
(i) Supplier's presence. The applicant must measure each potential supplier's presence in the destination market in terms of generating capacity, using economic capacity and available economic capacity measures. Additional adjustments to supplier presence may be presented; applicants must support any such adjustment.
(A) Economic capacity means the amount of generating capacity owned or controlled by a potential supplier with variable costs low enough that energy from such capacity could be economically delivered to the destination market. Prior to applying the delivered price test, the generating capacity meeting this definition must be adjusted by subtracting capacity committed under long-term firm sales contracts and adding capacity acquired under long-term firm purchase contracts (i.e., contracts with a remaining commitment of more than one year). The capacity associated with any such adjustments must be attributed to the party that has authority to decide when generating resources are available for operation. Other generating capacity may also be attributed to another supplier based on operational control criteria as deemed necessary, but the applicant must explain the reasons for doing so.
(B) Available economic capacity means the amount of generating capacity meeting the definition of economic capacity less the amount of generating capacity needed to serve the potential supplier's native load commitments, as described in paragraph (d)(4)(i) of this section.
(C) Available transmission capacity. Each potential supplier's economic capacity and available economic capacity (and any other measure used to determine the amount of relevant product that could be delivered to a destination market) must be adjusted to reflect available transmission capability to deliver each relevant product. The allocation to a potential supplier of limited capability of constrained transmission paths internal to the merging entities' systems or interconnecting the systems with other control areas must recognize both the transmission capability not subject to firm reservations by others and any firm transmission rights held by the potential supplier that are not committed to long-term transactions. For each such instance where limited transmission capability must be allocated among potential suppliers, the applicant must explain the method used and show the results of such allocation.
(D) Internal interface. If the proposed transaction would cause an interface that interconnects the transmission systems of the merging entities to become transmission facilities for which the merging entities would have a “native load” priority under their open access transmission tariff (i.e., where the merging entities may reserve existing transmission capacity needed for native load growth and network transmission customer load growth reasonable forecasted within the utility's current planning horizon), all of the unreserved capability of the interface must be allocated to the merging entities for purposes of the horizontal Competitive Analysis Screen, unless the applicant demonstrates one of the following:
(1) The merging entities would not have adequate economic capacity to fully use such unreserved transmission capability;
(2) The merging entities have committed a portion of the interface capability to third parties; or
(3) Suppliers other than the merging entities have purchased a portion of the interface capability.
(5) Calculate market concentration. The applicant must calculate the market share, both pre- and post-merger, for each potential supplier, the Herfindahl-Hirschman Index (HHI) statistic for the market, and the change in the HHI statistic. (The HHI statistic is a measure of market concentration and is a function of the number of firms in a market and their respective market shares. The HHI statistic is calculated by summing the squares of the individual market shares, expressed as percentages, of all potential suppliers to the destination market.) To make these calculations, the applicant must use the amounts of generating capacity (i.e., economic capacity and available economic capacity, and any other relevant measure) determined in paragraph (c)(4)(i) of this section, for each product in each destination market.
(6) Provide historical transaction data. The applicant must provide historical trade data and historical transmission data to corroborate the results of the horizontal Competitive Analysis Screen. The data must cover the two-year period preceding the filing of the application. The applicant may adjust the results of the horizontal Competitive Analysis Screen, if supported by historical trade data or historical transmission service data. Any adjusted results must be shown separately, along with an explanation of all adjustments to the results of the horizontal Competitive Analysis Screen. The applicant must also provide an explanation of any significant differences between results obtained by the horizontal Competitive Analysis Screen and trade patterns in the last two years.
(d) In support of the delivered price test required by paragraph (c)(4) of this section, the applicant must provide the following data and information used in calculating the economic capacity and available economic capacity that a potential supplier could deliver to a destination market. The transmission data required by paragraphs (d)(7) through (d)(9) of this section must be supplied for the merging entities' Start Printed Page 71017systems. 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 Start Printed Page 71018information for each potential supplier for each destination market:
(A) Potential supplier name;
(B) The potential supplier's total amount of economic capacity (not subject to transmission constraints); and
(C) The potential supplier's amount of economic capacity from which energy can be delivered to the destination market (after adjusting for transmission availability).
(ii) A similar table must be provided for available economic capacity, and for any other generating capacity measure used by the applicant.
(11) Historical trade data.
(i) The applicant must provide data identifying all of the merging entities' wholesale sales and purchases of electric energy for the most recent two years.
(ii) The applicant must include the following information for each transition:
(A) Type of transaction (such as non-firm, short-term firm, long-term firm, peak, off-peak, etc.);
(B) Name of purchaser;
(C) Name of seller;
(D) Date, duration and time period of the transaction;
(E) Quantity of energy purchased or sold;
(F) Energy charge per unit;
(G) Megawatt hours purchased or sold;
(H) Price; and
(I) The delivery points used to effect the sale or purchase.
(12) Historical transmission data. The applicant must provide information concerning any transmission service denials, interruptions and curtailments on the merging entities' systems, for the most recent two years, to the extent the information is available from OASIS data, including the following information:
(i) Name of the customer denied, interrupted or curtailed;
(ii) Type, quantity and duration of service at issue;
(iii) The date and period of time involved;
(iv) Reason given for the denial, interruption or curtailment;
(v) The transmission path; and
(vi) The reservations or other use anticipated on the affected transmission path at the time of the service denial, curtailment or interruption.
(e) Mitigation. Any mitigation measures proposed by the applicant (including, for example, divestiture or participation in a regional transmission organization) which are intended to mitigate the adverse effect of the proposed transaction must, to the extent possible, be factored into the horizontal Competitive Analysis Screen as an additional post-transaction analysis. Any mitigation commitments that involve facilities (e.g., in connection with divestiture of generation) must identify the facilities affected by the commitment, along with a timetable for implementing the commitments.
(f) Additional factors. If the applicant does not propose mitigation, the applicant must address:
(1) The potential adverse competitive effects of the transaction.
(2) The potential for entry in the market and the role that entry could play in mitigating adverse competitive effects of the transaction;
(3) The efficiency gains that reasonably could not be achieved by other means; and
(4) Whether, but for the transaction, one or more of the merging entities would be likely to fail, causing its assets to exit the market.
(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 Start Printed Page 71019(including, for example, divestiture or participation in an Regional Transmission Organization) which are intended to mitigate the adverse effect of the proposed transaction must, to the extent possible, be factored into the vertical competitive analysis as an additional post-transaction analysis. Any mitigation measures that involve facilities must identify the facilities affected by the commitment.
(e) Additional factors.
(1) If the applicant does not propose mitigation measures, the applicant must address:
(i) The potential adverse competitive effects of the transaction.
(ii) The potential for entry in the market and the role that entry could play in mitigating adverse competitive effects of the transaction;
(iii) The efficiency gains that reasonably could not be achieved by other means; and
(iv) Whether, but for the proposed transaction, one or more of the parties to the transaction would be likely to fail, causing its assets to exit the market.
(2) The applicant must address each of the additional factors in the context of whether the proposed transaction is likely to present concerns about raising rivals' costs or anticompetitive coordination.
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.
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 _____. 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).
The Commission may require the applicant to give such local notice by publication as the Commission in its discretion may deem proper.
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.
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.
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.
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.
The following Appendix will not be published in the Code of Federal Regulations.Start Printed Page 71020
Appendix—List of Commenters
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.
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).Back to Citation
2. Policy Statement at p. 30,111 n.3.Back to Citation
4. Revised Filing Requirements Under Part 33 of the Commission's Regulations, Notice of Proposed Rulemaking, 63 Fed. Reg. 20340 (1998), FERC Statutes and Regulations ¶ 32,258 (1998) (NOPR).Back to Citation
5. The commenters, and abbreviations for them as used herein, are listed in the Appendix attached to this Final Rule.Back to Citation
6. Policy Statement at p. 30,128.Back to Citation
7. Although we apply these factors to other section 203 transactions as well, the filing requirements and the level of detail required may differ.Back to Citation
8. U.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).Back to Citation
9. See 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).Back to Citation
10. See, 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).Back to Citation
11. Id., n. 12.Back to Citation
12. Although we are eliminating this section of our Part 33 regulations, the Commission intends to continue to process section 203 applications as expeditiously as practicable. As stated in the Policy Statement, the Commission continues to believe that, for example, we can issue an initial order for most mergrs within 150 days of receiving a completed application.Back to Citation
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.Back to Citation
14. Policy Statement at pp. 30,125-26 (we no longer consider the reasonableness of purchase price as a factor; rather, it is subsumed within the effect on rates factor). This information is used for purchase accounting purposes.Back to Citation
15. Supplementing the application with orders from other regulatory bodies will not normally delay the processing of an application.Back to Citation
16. This information is needed so that we can determine the existence of interlocking directorates.Back to Citation
17. For example, under a tolling arrangement, a gas supplier would receive the output of a gas-fired generator as payment for the gas it supplies to the generator. If the gas supplier is the only supplier to that generator, then the gas supplier could effectively control the generator.Back to Citation
18. Policy Statement at p. 30,119.Back to Citation
19. Policy 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).Back to Citation
20. We noted in Enova that a merger of jurisdictional facilities can be effected by a change in control over a public utility's facilities. Public utilities (or their parent companies) can effect a merger by combining their businesses through the formation of a new holding company that will own or control, either directly or indirectly, previously unaffiliated entities. See Enova, 79 FERC ¶ 61,107 at 61,491-96 (1997).Back to Citation
21. The electronic filing requirements are set forth in § 33.8 of the revised regulations.Back to Citation
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.Back to Citation
23. American Electric Power Co. and Central and South West Corp., 85 FERC ¶ 61,201; reh'g denied, 87 FERC ¶ 61,274 (1999) (AEP/CSW).Back to Citation
24. Among the information the FTC Staff suggests: internal documents of the merging parties; third-party documents, including documents from industry trade associations; depositions of applicants and third-party executives and consultants; history of previous antitrust cases; financial analysts' reports; consultants' reports on competitive conditions in the industry; documents and interviews with executives of failed entrants, prospective entrants and fringe firms; filings about competitive conditions made with other government agencies; and documents and interviews with suppliers and customers.Back to Citation
25. APPA/TAPS notes that strategic alliances should be disclosed and treated as mergers where their terms could have horizontal or vertical competitive effects. Also, to evaluate whether a proposed merger is likely to harm competition by placing additional costs on competitors, merging companies should be required to disclose existing “reserve sharing,” pooling arrangements and contractual or other commitments in order to continue those arrangements post-merger.Back to Citation
26. See 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).Back to Citation
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.Back to Citation
28. Sierra Pacific Power Co., Nevada Power Co. and Portland General Electric Co., 92 FERC ¶ 61,069 (2000).Back to Citation
29. Policy Statement at p. 30,118.Back to Citation
30. These specific filing requirements are set forth in § 33.3 of the revised regulations.Back to Citation
31. Commonwealth Edison Company and PECO Energy Company, 91 FERC ¶ 61,036 (2000) (PECO/ComEd).Back to Citation
32. The specific filing requirements for applicants addressing mitigation measures and additional factors are set forth in § 33.3(e) and § 33.3(f), respectively.Back to Citation
33. See below note 77.Back to Citation
34. Regional Transmission Organizations, Order No. 2000, 65 Fed. Reg. 809 (Jan. 6, 2000), FERC Statutes and Regulations at 31,135 (1999).Back to Citation
35. Policy Statement at p. 30,130.Back to Citation
36. Consolidated 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).Back to Citation
37. The price would include payments for transmission and ancillary services needed to deliver the power.Back to Citation
38. Policy Statement at pp. 30,130-31.Back to Citation
39. The starting point for calculating economic capacity is the supplier's own generation capacity with low enough variable costs that energy can be delivered to a market (after paying all necessary transmission and ancillary service costs, including losses) at a price that is five percent or less above the pre-merger market price. Capacity must be decreased to reflect any portion committed to long-term firm sales; and it must be increased to reflect any portion acquired by long-term firm purchases. In addition, any capacity under the operational control of a party other than the owner must be attributed to the party for whose economic benefit the related unit is operated. The result of these calculations is the supplier's “economic capacity.”Back to Citation
40. Southern comments that actual market conditions reflecting any legal constraints on market participation should be considered, but only if such constraints are actually being adhered to.Back to Citation
41. Baltimore 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.Back to Citation
42. We have noted such discrepancies in data received from applicants in our analysis in a prior case. See BG&E/PEPCO, pp. 61,119-120.Back to Citation
43. Native load customers are the wholesale and retail power customers on whose behalf a utility, by statute, franchise, regulatory requirement, or contract, has an obligation to construct and operate an electric system.Back to Citation
44. See, e.g., Utilicorp/St. Joseph.Back to Citation
45. Hourly data are available in electronic format from the FERC Form 714, Annual Electric Control and Planning Area Report.Back to Citation
46. Policy statement at pp. 30,131.Back to Citation
47. Rates for non-public utilities that are members of a regional body such as an RTO may be found in the RTO tariff. Such information may also be available on a non-public utility's OASIS.Back to Citation
48. For public utilities (and non-public utilities with OASIS), evidence should be available from OASIS archives. OASIS database transaction data must be retained and made available upon request for three years after they were first posted. See 18 CFR 37.7.Back to Citation
49. Policy Statement at p. 30,131.Back to Citation
50. Atlantic City/Delmarva, p. 61,408.Back to Citation
51. Ohio Edison Company, et al., 80 FERC ¶ 61,039 at 61,105-6 (1997) (FirstEnergy).Back to Citation
52. Examples include Energy East/CMP, ConEd/NU, and NiSource Inc. and Columbia Energy Group, 92 FERC ¶ 61,068 (2000) (NiSource/Columbia Energy).Back to Citation
53. When transmission constraints are binding, identical prices in adjacent markets may still occur, although this is unlikely.Back to Citation
54. See, CP&L/Florida Progress, in which prices based on system lambda and observed “Market Power Week” data were different.Back to Citation
55. First Energy, p. 61,104.Back to Citation
56. See, e.g., North American Electric Reliability Council's web page (http://www.nerc.com.filez/ptdf/html) on use of Power Transfer Distribution Factors and the Interchange Distribution Calculator which can be used to identify interchange transactions contributing to a constraint.Back to Citation
57. See, 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.Back to Citation
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.Back to Citation
59. Wisconsin Electric Power Company, et al. (Primergy), 79 ¶ 61,158 at 61,694 (1997), and FirstEnergy at 61,107.Back to Citation
60. FirstEnergy, pp. 61,103-04.Back to Citation
61. See e.g., APS/Duquesne, Louisville Gas and Electric Co., Kentucky Utilities Co., and PowerGen plc, 91 FERC ¶ 61,321 (2000).Back to Citation
62. The Policy Statement addresses three ranges of market concentration as described in the Guidelines: (1) An unconcentrated post-merger market—if the post-merger HHI is below 1000, regardless of the change in HHI the merger is unlikely to have adverse competitive effects; (2) a moderately concentrated post-merger market—if the post-merger HHI ranges from 1000 to 1800 and the change in HHI is greater than 100, the merger potentially raises significant competitive concerns; and (3) a highly concentrated post-merger market—if the post-merger HHI exceeds 1800 and the change in the HHI exceeds 50, the merger potentially raises significant competitive concerns; if the change in HHi exceeds 100, it is presumed that the merger is likely to create or enhance market power.Back to Citation
63. Since the NOPR, we have had a significant number of cases where applicants have provided such evidence, and we encourage them to continue that practice. For example, in PECO/ComEd we noted that Applicants' screen failures occurred “over a scattering of markets and time periods.” 91 FERC ¶ 61,036 at 61,134. In NSP/New Century, Applicants attempted to isolate three potential sources of merger-related changes in concentration “due to: (1) Combining NSP's and SPS's market shares; (2) changes in NSP's or SPS's market share due to joining the [Midwest ISO] or integrating directly; and (3) changes in the composition of relevant markets resulting from either integration plan, but not related to changes in NSP's or SPS's market shares.” 90 FERC ¶ 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.Back to Citation
64. For example, certain behavioral measures—in contrast to structural remedies such as divestiture—do not transfer control over resources from the merged company to an existing or new market participant. In such cases, the market shares of the merging companies would not change and, therefore, the merger would not change market concentration.Back to Citation
65. These factors are those discussed in steps two through five of the DOJ Guidelines.Back to Citation
66. Guidelines, 57 FR at 41,561.Back to Citation
67. Id. at 41,561-562.Back to Citation
68. For example, we found in Primergy that timely entry would not occur and thus was not a mitigating factor to the anticompetitive effects of the proposed merger. 79 FERC ¶ 61,158 at 61,695-696.Back to Citation
69. The FTC Staff comments that during periods of moderate inflation, a rate cap without an inflation adjustment may provide a rough substitute for a technology adjustment. The FTC Staff further says that in periods of deflation or substantial inflation, there would be greater reasons to differentiate the inflationary and technological effects on costs.Back to Citation
70. NRECA defines extraordinary circumstances as including mergers above its moratorium threshold of 1,000,000 metered accounts, mergers of registered holding companies, and mergers of companies exhibiting excessive market power.Back to Citation
71. Ohio Commission also suggests that the regulations require that any mitigation measure involving an ISO that does not meet the minimum ISO criteria should be co-terminus with existing reliability council boundaries.Back to Citation
72. After the issuance of the NOPR, the Commission amended its regulations under the FPA to facilitate the formation of Regional Transmission Organizations (RTOs). We required each public utility that owns, operates, or controls facilities for the transmission of electric energy in interstate commerce to make certain filings with respect to forming and participating in an RTO. The Commission codified minimum characteristics and functions that a transmission entity must satisfy in order to be considered an RTO. See Regional Transmission Organizations, Order No. 2000, 65 Fed. Reg. 809 (Jan. 6, 2000), FERC Statutes and Regulations ¶ 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.Back to Citation
73. See, e.g., CP&L/Florida Progress, and UtiliCorp/St. Joeseph.Back to Citation
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.Back to Citation
75. Duke, 79 FERC at 62,037 (1997).Back to Citation
76. A firm may exert a salutary influence on behavior in a market without actually competing in it. See e.g., FTC v. Proctor & Gamble Co. 386 U.S. 568 (1967); U.S. v. Falstaff Brewing Corp., 410 U.S. 426 (1973).Back to Citation
77. See, e.g., AEP/CSW, NSP/New Century, and CPL/Florida Progress.Back to Citation
78. We understand that, in responding to interventions raising concerns about perceived potential competition, applicants may find it necessary to submit data on their market strategies. We appreciate the commercial sensitivity of information pertaining to applicants' market strategies, and the concern applicants may have about possible disclosures of this information to competitors. Applicants are free to claim confidentiality for this information, we will presume that this information falls within the exemption from public disclosure under the Freedom of Information Act for “trade secrets and commercial or financial information obtained from a person and privileged or confidential.” 18 CFR 388.107(d)(2000). If parties seek access to this information, and we determine that limited disclosure is necessary to satisfy the due process rights of intervenors to challenge relevant evidence relief upon by the applicants, we will allow such access to parties' attorneys and experts only under the terms of an appropriate protective order. See, e.g., model protective order at www.ferc.fed.us/alj/index.html. Such a protective order would prevent broader dissemination or use of the sensitive information for business purposes or commercial advantage.Back to Citation
79. We clarify that by exemption, we mean that an applicant need not tender a competitive analysis with its filing. If the Commission determines that a filing raises competitive issues nonetheless, the Commission will evaluate those issues and direct the applicant to submit any data that the Commission determines is necessary to satisfy its concerns.Back to Citation
80. Policy Statement at p. 30,113.Back to Citation
81. See 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.Back to Citation
82. See, Illinova Corporation and Dynergy Inc., 89 FERC ¶ 61,163 (1999).Back to Citation
83. These specific filing requirements are set forth in § 33.4 of the revised regulations.Back to Citation
84. There may be several relevant upstream input products (such as fuel, transportation and turbine manufacturers).Back to Citation
85. Horizontal mergers may give rise to a higher market share for the merged entity and increase concentration in the market. Market share and concentration are not directly affected by a solely vertical merger.Back to Citation
86. See Enova, 79 FERC ¶ 61,372 at 62,560.Back to Citation
87. Foreclosure can also result from a vertical merger if the downstream merging firm refuses to purchase from input suppliers other than its upstream affiliate.Back to Citation
88. See, Enova, 79 FERC ¶ 61,372 at 62,560.Back to Citation
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.Back to Citation
90. One example of potential anticompetitive coordination is the anticompetitive exchange of information. If the downstream merging firm obtains price quotes and other sensitive competitive information from other (non-merging) upstream suppliers it could transfer that information to its upstream merging partner. The exchange of such information among upstream input suppliers can be potentially useful in agreeing to raise prices or restrict output to all downstream customers.Back to Citation
91. See, e.g., Gulf States Utilities v. FPC, 411 U.S. 747 (1973) reh'g denied, 412 U.S. 944 (1973); and Alabama Power Co., et al., v. FPC, 511 F.2d 383 (DC Cir. (1974)).Back to Citation
92. Regulatory evasion could effect requirements service customers in wholesale electricity markets. However, this is less likely to be a concern if wholesale markets are competitive.Back to Citation
93. NRECA at 25. In the merger as originally proposed, eleven states were directly affected, yet, says NRECA, the merging parties asserted that only four states (all within CWS's territory) had clear authority to approve or reject the merger.Back to Citation
94. Policy Statement at 30,128.Back to Citation
95. See, Duke/PanEnergy, 79 FERC ¶ 61,236 at 62,039.Back to Citation
96. See supra note 29.Back to Citation
97. See supra note 29.Back to Citation
98. See, 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.Back to Citation
99. The DOJ 1984 Merger Guidelines address vertical mergers and discuss both market share and HHI statistics. See DOJ 1984 Merger Guidelines at 46.Back to Citation
100. The DOJ 1984 Merger Guidelines use a “highly concentrated” market as a threshold for further investigating the competitive effect of a vertical merger. See DOJ 1984 Merger Guidelines at 46. Because concentration thresholds are indicators that additional investigation is warranted, the Commission proposed to look further at mergers with an HHI near 1800 or above.Back to Citation
101. See, American Electric Power Company, 90 FERC ¶ 61,242.Back to Citation
102. See DOJ 1984 Merger Guidelines §§ 4.211 and 4.212.Back to Citation
103. See, Vastar Resources, Inc., et al., 81 FERC ¶ 61,135 at 61,633.Back to Citation
104. See Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission's Regulations, and Regulation of Natural Gas After Partial Wellhead Decontrol, Order No. 636, FERC Stats. and Regs. ¶ 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).Back to Citation
105. Enova, 79 FERC ¶ 61,372 at 62,565 (1997).Back to Citation
106. Policy Statement at 30,111, 30,121-24, and n.5. See also, Morgan Stanley, 79 FERC at 61,504-05; Duke/PanEnergy, 79 FERC at 62,039-41; Enova, 79 FERC at 62,566; Destec, 79 FERC at 62,574-75; LILCO, 80 FERC at 61,079-80; FirstEnergy, 80 FERC at 61,098; NorAm, 80 FERC at 61,382-3.Back to Citation
107. Policy Statement at 30,112 and 30,124-25. See also, Duke/PanEnergy, 79 FERC at 61,041-42; Morgan Stanley, 79 FERC at 61,505; Enova, 79 FERC at 62,566-67; Destec, 79 FERC at 62,575; LILCO, 80 FERC at 61,080; FirstEnergy, 80 FERC at 61,098-99; Noram, 80 FERC at 61,383; and Atlantic City/Delmarva, 80 FERC at 61,412-13 and n.60.Back to Citation
108. Policy Statement at p. 30,125.Back to Citation
109. NOPR, p. 33,383.Back to Citation
110. NOPR, pp. 33,383-84.Back to Citation
111. Missouri Commission cites “Making the Transition from Regulation to Competition: Thinking About Merger Policy during the Process of Electric Power Restructuring,” Address by Joel I. Klein, United States Department of Justice, Assistant Attorney General, Antitrust Division, FERC Distinguished Speaker Series (January 21, 1998).Back to Citation
112. NOPR, p. 33,368.Back to Citation
113. Policy Statement at p. 30,127-28.Back to Citation
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”).Back to Citation
[FR Doc. 00-29676 Filed 11-27-00; 8:45 am]
BILLING CODE 6717-01-P