Predictions of a U.S. electric merger wave heated up last summer, when the Energy Policy Act of 2005 (EPACT) repealed the 1935 Public Utility Holding Company Act (PUHCA), thereby allowing acquisition of electric utility companies by foreign firms, domestic non-utilities, or other non-contiguous utilities.1 Factors including demand growth for electricity, re-regulation, potential profitability of baseload power plants caused by high natural-gas prices, and competitive pressures have made the electric utility industry, particularly power generation, more attractive for investment and take-over activities.
Starting Feb. 8, 2006, any electric utility asset transfer with a value exceeding $10 million is subject to Federal Energy Regulatory Commission (FERC) approval.2 Until recently, a utility asset transfer with a value of $50,000 has been subject to FERC approval. Section 203 of Federal Power Act (FPA) raises the threshold value of the transaction from $50,000 to $10 million. Will this increase in the minimum-threshold value be perceived as a lowering of regulatory hurdles, thereby spurring more electric utility plant acquisitions?
Regulatory scrutiny at FERC and other antitrust agencies in the post-PUHCA era likely will be at least as involved as before. A review of previous plant acquisitions over the past two years shows that the average value of the assets sold well exceeded $10 million, triggering a FERC section 203 filing.3 Nearly 50 electric-plant acquisition deals were completed in the past two years, resulting in a total of 46,384 MW and $13.7 billion worth of plant assets changing hands in 2004 and 2005.
As shown in Table 1, the deals ranged from as little as $2 million to as high as $3.6 billion, with an average transaction value of about $280 million. At a weighted average value of $300/kW, the value of a 300-MW power plant is $90 million, far above the $10 million threshold. Additionally, structural changes and corporate realignments in the electric utility industry, combined with high fuel prices, would pressure regulators to undertake a thorough review, particularly if the transaction involves electric-gas consolidations. In Order 669, FERC already has implemented a new filing rule requiring Section 203 applicants to prove that their proposed transactions would not result in cross-subsidization.4
Furthermore, Section 203 applicants that already have market-based rate (MBR) authority would need to file a change in status (CIS) within 30 days of their closing.5 The CIS filing implements FERC’s April 2004 Generation Market Power Analysis, specifically designed to determine if MBR authority should be granted.6 The analysis has well-specified requirements and guidelines that contain some subtle differences from the Section 203 market-power analysis, and these differences may result in undesirable outcomes.
This article explains differences between the market-power tests of the section 203 and MBR filings, and further suggests key elements to consider when assessing competitive impacts of a proposed transaction. These regulatory elements also provide investors a checklist on how to weigh their acquisition choices.
Market power analyses for both Section 203 and MBR filings are designed to examine two different questions. The goal of FERC’s Section 203 market-power analysis is to examine only the market power arising from the transaction. FERC takes as given the overall degree of competitiveness or market power held by buyers, sellers, or individual segments. Thus, the FERC threshold for approving an asset transfer emphasizes the impact of the transaction on competition, i.e., the change in market concentration. It accepts the status quo of the applicant even if the applicant operates in a highly concentrated market and has a market share exceeding 20 percent, a threshold FERC uses in determining whether MBR authority should be granted.
The market-power analyses for MBR applicants examines whether a seller is likely to have market power. Two screen tests are required; the Pivotal Supplier Screen (PSS) and the Market Share Screen (MSS) analyses. Between these two screens, the MSS is arguably the more challenging for an investor-owned utility (IOU) because of FERC’s rigid formula. Under the MSS, an MBR seller with a market share exceeding 20 percent fails this test. It is therefore possible that a Section 203 applicant would be granted a transfer of the asset; however, because it has MBR authority, its acquisition would be denied by FERC. This is an undesirable outcome.
Although FERC has not yet ruled on this particular situation, similar cases have been observed. Arizona Public Service (APS) and its affiliates filed for a Section 203 approval when it acquired a 450-MW natural-gas combustion turbine power plant from PPL Sundance Energy LLC. On May 6, 2005, FERC approved the transaction but requested APS to file CIS,9 even though its May 2004 triennial MBR for its control area had not been granted by FERC.10
In preparing market-power analyses for the APS CIS filing,11 APS had claimed that its relevant market expanded beyond the APS control area to cover Salt River Project’s (SRP’s) control area. Nevertheless, it provided the analyses for both the APS control area market and the expanded APS/SRP market. APS failed the FERC market-share screen test for its control-area market, but passed when the market was defined as the combined APS/SRP market. APS voluntarily submitted the DPT analysis to demonstrate that there are no market power concerns relating to APS and to its affiliates receiving MBR authority in its control area.12 After almost two years, FERC has revoked APS and its affiliates’ MBR authority for power sales in the APS control area.13
In the Exelon-Public Service Electric and Gas (PSEG) merger, the merged firm would fail the FERC MBR tests.14 Even with the amount of mitigation proposed by the merging parties, the merged entity’s market share may exceed the 20 percent threshold in several periods.15 It will be interesting to see what transpires when Exelon submits its CIS filing at FERC.
Despite FERC’s requirements and guidelines on these two filings, its market-power analyses are screening tests.16 They allow FERC to streamline the requisite work. However, they are not perfectly accurate, i.e., one test may identify a market-power concern that does not exist, while the other test may identify no market-power concern when, in fact one does exist. The failure of either screen does not mean that an applicant has undue market power, but rather that additional analysis is needed to reveal a correct conclusion. To rebut the presumption of market power, the applicant would need to file additional analyses, or propose mitigation measures.17
A list of what one might consider in assessing the degree of difficulty in gaining FERC regulatory approval can assist in weighing FERC’s competitive screens in plant acquisition decision-making (see “Before You Do the Plant Deal,” p. 72). For example, does the potential acquisition convey control of management or operation of the assets?
The concept of control is essential in a market-power evaluation. In some circumstances, banks or investment ventures may be deemed to have control over a public utility due to their lending activities, which in turn allows them to hold the public utility’s securities. They therefore may be required to obtain FERC’s approval under section 203.
Nevertheless, in FERC’s recent Order 669, the commission granted blanket authorization, exempting certain types of transactions from the section 203 filing requirements. These include acquisition of non-voting securities, and voting securities that comprise less than 10 percent of all outstanding voting securities.18
A second question to consider: Is the potential acquisition located in the same geographic market or contiguous area as any of the acquirer’s existing power plants?
Many buyers are exempt from a full-fledged DPT analysis. According to FERC’s Order 642, if buyers and sellers do not operate in overlapping markets, they do not need to submit a DPT analysis. Examples of these cases include AIG Global Investment Group and El Paso Corp.19
Also, if the potential acquisition is located in the same geographic market, what is the size of the transaction? If the potential acquisition is located in the same geographic market as the acquirer’s existing power plant but the size of the acquisition is de minimis, the transaction also is exempt from the full DPT analysis.20 For example, when Onondaga Cogeneration Limited Partnership requested FERC approval for the transfer of its ownership of Onondaga Cogeneration Facility—a 91-MW dual fuel combined-cycle merchant energy facility located in New York—to Teton Funding LLC, it did not submit the DPT analysis. It argued that competition would not be negatively affected by the transaction, as the combined capacity of Onondaga, Teton, and its affiliates would be de minimis, totaling approximately 875 MW in the New York Independent System Operator markets, which contains 36,527 MW of total generating capacity.21
However, in the case where an applicant is considered a larger supplier in the market, some analysis should be considered to demonstrate that the transaction is de minimis and thereby has no adverse effect on the relevant markets. A simplified analysis could be performed to show that the transaction would cause market concentration to increase by an amount less than the FERC threshold level.
Moreover, when the acquisition has no effect on market concentration because the buyer already exercises control over transaction capacity via a long-term contract, a full DPT analysis is not needed. When Dominion Virginia Power acquired a 181-MW qualifying facility (QF) of Panda Rosemary LP, it did not submit a competitive analysis.22 Dominion explained that the facility already had been subject to a long-term purchase agreement with Dominion since 1989. The contract will expire in 2015. FERC approved the transaction.23
But if the size of the acquisition is not deemed to be de minimis, then a full DPT analysis is required. Once this is determined, there are a few more questions to answer.
FERC uses market shares and market concentration, aka Herfindahl Hirschman Indices (HHIs), in screening for horizontal market power concerns. An HHI or a composite of market shares24 in a market is an essential factor in determining the level of market concentration.
HHI tends to be higher in a market that is dominated by fewer suppliers. Regulators and antitrust agencies have challenged mergers with significant market shares and concentration. Nevertheless, market shares and HHI by themselves are neither a necessary nor sufficient basis for challenging a transaction. Other factors, such as a distribution of merging parties’ generating units on a market-supply curve and a control of fuel supplies, are critical for regulators to gauge a potential harm of mergers on competition.
FERC requires a definition of “relevant products” and “geographic markets” that would be affected by the transaction prior to the market-share calculation. In the past, the DPT examined short-term products, which could vary within days because of the inability to store electricity. Thus, long-term contract data are taken into account, as they determine each supplier’s ability to control resources.25
Additionally, FERC examines two measures of capacity: economic capacity (EC) and available economic capacity (AEC). In the EC measure, each supplier’s resources include capacity owned and controlled through long-term contracts, while the AEC measure subtracts native-load obligations from the EC measure. But is a buyer a net buyer or a net seller?
Many investor-owned utilities (IOUs) own resources that are greater than their peak load because of reserves requirements. Therefore, it is very likely that an IOU will be a net seller in low-load periods and a net buyer in high-load periods. One also would observe more screen failures under the EC scenario than under the AEC scenario. Would more screen failures in the EC, and in low-load periods for the AEC case, be problematic?
FERC has ruled that AEC is more relevant for determining the competitive impact in cases where an applicant has significant native-load obligation. For example, Brattle’s DPT analysis for Nevada Power Co.’s acquisition of GenWest LLC’s Silverhawk power plant found screen failures under the EC scenario in 11 of the 14 time periods studied, and only one screen failure in the spring peak season under the AEC scenario.26 The post-transaction market in the spring peak season, however, is moderately concentrated, and Nevada Power’s market share is approximately 21 percent.
FERC approved the Nevada Power transaction, stating that it gave more weight to the AEC results, and the AEC failure in the spring peak market was neither highly concentrated, nor did Nevada Power have significant market share.27 On a side note, Nevada Power does not have MBR authority to sell power in its own control area.
FERC also reviews the potential adverse impact of a proposed acquisition on vertical market power with respect to transmission. The most common vertical market power concern is whether the transaction would create or enhance ability and incentive for a buyer to use its transmission system to raise electricity prices, or to frustrate entry in relevant wholesale electricity markets. A buyer that solely controls transmission facilities, i.e., an IOU, will fall under FERC’s vertical market-power concern radar screen. The commission is concerned about the efficacy of its open-access transmission tariff (OATT), created in 1996 to ensure non-discriminatory transmission access to all generators.28
In the 2003 section 203 proceeding, Oklahoma Gas and Electric Co. (OG&E) and NRG McClain LLC sought FERC approval for OG&E’s acquisition of the McClain generating plant, which is located within OG&E’s service area.29 The DPT results showed screen failures for six of the 10 time periods under the EC scenario, but the transaction passed the screen in all time periods under the AEC scenario. The applicants argued that AEC is the relevant measure because Oklahoma does not have retail choice, and OG&E retains a native-load obligation. However, an intervener in the proceeding claimed that the OG&E acquisition would “exacerbate” existing transmission constraints into, out of, and within, the OG&E control area. FERC found that this acquisition would unduly increase market concentration within OG&E’s control-area market, and required OG&E to add transmission capacity, among other measures, as a condition of approving the acquisition.
Unlike the OG&E/McClain case, the commission did not find a vertical market-power concern in the Nevada-Silverhawk proceeding. Nevada Power explained to the commission that many of the wholesale customers own their own transmission assets and, therefore, could not be foreclosed by Nevada Power. Under Nevada’s restructuring legislation, any eligible retail customer that seeks to purchase from an alternative supplier is entitled to a pro rata share of Nevada Power’s available import capability. Additionally, the proposed transaction would increase the available import capacity into Nevada Power by freeing up transmission now used for imports.
FERC is concerned if an applicant or its affiliates own or control upstream fuel supplies that could be used to harm competition in downstream wholesale electricity markets by raising rival costs. For example, a buyer of a baseload power plant who also owns or controls natural-gas pipeline firm capacity or storage facilities would have an incentive and the ability to raise natural-gas prices delivered for natural-gas-fired generation. In the wholesale power market with a single market clearing price, an increase in the price of natural gas would directly translate to a higher profit margin for baseload generating units, particularly during high load periods when natural-gas power plants often set market-clearing prices. This fact also may trigger additional scrutiny by antitrust agencies, particularly in an organized market.
FERC has an analytical framework to assess whether a potential merger or acquisition should be approved. Although this framework may be viewed as complex, there are steps one can take to ensure success in gaining FERC approval. Use the checklist of questions provided in the box to assess FERC’s market-power analysis before making an acquisition decision.
1. Energy Policy Act of 2005 at §§ 1261 et seq., Aug. 8, 2005.
2. FERC Order No. 669, Transactions Subject to FPA Section 203, Dec. 23, 2005.
3. FERC determines that the market value from transactions between non-affiliates is the most effective and reasonable approach to determine which asset transfers require section 203 approval. See FERC Order 669, P. 113.
4. Order 669, PP. 164-170.
5. FERC requires an entity with MBR authority to file CIS when its net assets increase by 100 MW or more. 110 FERC ¶ 61,097, Reporting Requirement for Change in Status, Feb. 10, 2005.
6. Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy, 107 FERC ¶ 61,018, April 14, 2004.
7. Fox-Penner, P. and Broehm R., “Deregulated Electricity Pricing in the U.S.: Dramatic New Rules From the FERC,” The Brattle Group, April 25, 2004.
8. Market share is measured by uncommitted capacity, which is calculated based on minimum daily peak load day for each of the four seasons. See 107 FERC ¶ 61,018 (2004), P 100.
9. 111 FERC ¶ 62,146 (2005).
10. Pinnacle West Capital Corporation, et al., (PWCC) in Docket No. ER00-2268, et al., May 13, 2004.
11. Request for Additional Information on Change in Status Filing for the Pinnacle West Companies, Docket Nos. ER00-2268-012, et al., Aug. 8, 2005.
12. Docket Nos. ER00-2268-015, et al., Jan. 20, 2006.
13. 115 FERC ¶ 61,055, April 17, 2006. The basis for the revocation is on the key input determining imports of competitive suppliers. The commission found that APS’s simultaneous import limit study for the APS control area did not comply with the FERC requirement set in Appendix E of its Triennial MBR Order (April 2004).
14. Supplemental Testimony and Exhibits of Williams Hieronymus on behalf of Exelon Corp., Exhibit J-17, Docket No. EC05-43, May 12, 2005.
15. Id., PP 15-22.
16. Fox-Penner P., Taylor, G., Broehm, R., and Bohn, J., “Competition in Wholesale Electric Power Markets,” Energy Law Journal, 2002, Volume 23, No. 2.
17. In the MBR circumstance, the applicant who fails either MSS or PSS must perform a DPT if a mitigation measure is not proposed.
18. Order No. 669, Dec. 23, 2005, PP. 140-145. A purchaser of such voting securities, however, must provide the commission copies of the Security Exchange Commission schedules required to be filed by any entity acquiring beneficial ownership of more than 5 percent of a class of a company’s securities. See Id., n.107.
19. Docket EC04-78, March 19, 2004.
20. 93 FERC ¶ 61,164. Sections 33.3 (2) and 33.4(2).
21. Docket No. EC04-34, Dec. 5, 2003. FERC approved the transaction in 106 FERC ¶ 62,041, Jan. 21, 2004.
22. Virginia Electric and Power Co., Docket No. EC05-24, Dec. 2, 2004.
23. 110 FERC ¶ 62,077.
24. HHI is calculated as the sum of the squares of the market shares of suppliers in a market. HHI = where MSi is market share of firm i.
25. A long-term contract is defined as a contract with more than one year of duration.
26. Fox-Penner Affidavit, Docket No. EC05-132, Aug. 31, 2005.
27. 113 FERC ¶ 61,265, P. 15. Also see similar findings at 113 FERC ¶ 61,073 and 113 FERC ¶ 61,074.
28. Notice of Inquiry, Preventing Undue Discrimination and Preference in Transmission Services, Docket No. RM05-25-000, Sept. 16, 2005.
29. Oklahoma Gas and Electric Company and NRG McClain LLC, FERC Order Doc. No. EC03-131-000, Dec. 18, 2003.