Do regulatory and economic trends favor industry mergers?
Douglas G. Green is a partner with Steptoe & Johnson.
Three major electric power merger and acquisition (M&A) transactions have been announced in the last several months,1 and a number of leading power company executives recently have expressed the need for increased consolidation in the industry. These developments raise some interesting questions.
Not many years ago, the power industry experienced an apparently never-ending wave of merger activities sweeping across the country. The repeal of the Public Utility Holding Company Act of 1935 (PUHCA), and its burdensome regulatory rules, including the requirement that registered holding companies be operationally integrated, opened up the possibility of mergers between geographically distant U.S. companies and made U.S. acquisitions more attractive to regulation-averse foreign companies. Then suddenly, M&A activity dropped off a cliff. The failure of the Exelon-PSE&G merger in September 2006 heightened concerns about state regulatory approvals. Soon after, financial markets dried up, and load growth reversed itself. Prolonged M&A doldrums followed.
Now that some new major transactions have emerged, and financial recovery appears slowly moving forward, some obvious questions arise. Does the recent re-emergence of merger activity betoken a new wave of M&A transactions? To what extent have the changes that have occurred in the last few years altered the regulatory landscape and affected the prospects for obtaining federal and state regulatory approval of mergers with acceptable merger conditions? What new considerations should prospective acquirers or target firms know about and address in their regulatory filings?
The electric power industry remains one of the least concentrated of the major industries in the United States. The industry’s structure includes about 81 separate investor-owned utility corporate families and a larger number of independent power producers. In many mature industries, especially those that are capital intensive, economies of scale and scope result in markets characterized by a small number of leading firms and a smattering of niche players.
Do the forces that drive consolidation in the rest of the economy apply in the electric industry today? Arguably they do. “Consolidation in the electric power industry is inevitable,” says John Rowe, chairman of Exelon, whose actions reflect those views.2 The cost of constructing large generation and transmission facilities is rising, and the need for them is increasing. These dynamics are reflected in FirstEnergy’s public statements regarding the motivation for its proposed consolidation with Allegheny Power. FirstEnergy identifies the benefits of the pending FirstEnergy-Allegheny merger as including “increased scale and scope in energy delivery, generation, and transmission3” and CEO Anthony Alexander emphasizes that the merger will create “a larger, financially stronger company that is better positioned to compete for and attract capital on reasonable terms,” and will enhance technology and managerial expertise.4 Obviously, these reasons could apply broadly to many potential combinations of electric industry players throughout the nation.
But the power industry is unique in many ways. It involves a product that can’t be readily stored and must be delivered instantaneously to meet demand over a transmission grid with finite delivery capability. It’s therefore characterized by individual, regional geographic markets, and these are subject to dual layers of federal and state regulation, in which some companies possess an obligation to serve. As a result, each company tends to face its own particular competitive and regulatory situation, and mergers tend to be opportunistic. Moreover, at least two other important factors tend to serve as a counter balance to the forces that otherwise would impel large-scale consolidation. First, in the market for corporate control in the power industry, the acquiring company often needs to pay a significant premium. Changes that have occurred in the industry’s economic regulatory landscape can make it harder for potential acquirors to be certain that the necessary premium is warranted. Second, the regulatory approval process creates uncertainty. Thus, it’s important that the process be managed to reduce that uncertainty to the extent possible, and to do so, the recent changes in dynamics of the industry must be considered carefully and taken into account.
Regulatory Landscape Changes
Among the significant changes currently in play in the power industry, several key developments—involving competitive issues, transmission planning, renewable goals, and economic and financial issues—potentially affect merger negotiations and the regulatory approval process.
• Competition: The competitive effects of a power-industry transaction typically are reviewed at both the federal and state level. A merger must pass through two layers of federal review: Competitive issues have stymied some major mergers, while others that potentially raised such issues (e.g., the AEP-CSW merger) have moved smoothly through the approval process with acceptable conditions. It’s very important to be able to identify, at an early stage in the merger evaluation process, any competitive issues and the worst-case mitigation that might be necessary.
Two recent developments potentially affect the competition analysis applicable to power industry mergers. First, on April 20, 2010, the Department of Justice Antitrust Division and Federal Trade Commission proposed to revise their horizontal merger guidelines to liberalize the safe harbors for identifying mergers that don’t raise competitive issues. The merger guidelines identify certain mergers that don’t raise significant competitive issues because they either occur in unconcentrated markets or don’t cause an increase in market concentration large enough to raise any concerns. The proposed merger guidelines would raise the market concentration levels that define these merger safe harbors. This proposed change is significant because it would permit more transactions to be approved promptly by FERC and the federal antitrust authorities, without the uncertainty and delay of time-consuming hearings and investigations. These new criteria also should aid in state proceedings.
Currently, FERC’s merger policy statement adopts the market-concentration screens in the existing federal merger guidelines. Proposed mergers that satisfy those screening criteria can be approved by FERC without any evidentiary hearing. Getting FERC approval without a hearing is important because the hearing process at FERC can take 12 months.5 Having the certainty of federal merger approvals and the knowledge of how much divestiture, if any, will be required, can help substantially at the state level when competition issues are considered. Largely for this reason, merger applicants at FERC whose proposed combination otherwise would exceed the guidelines’ safe-harbor market concentration screens, typically have proposed to divest sufficient generating capacity to bring the transaction within these safe harbors to avoid a hearing. The stringency of the existing market-concentration screens, and the consequent divestiture requirement, has limited the scope of realistically viable merger combinations.
The proposed new federal merger guidelines make significant changes in the market concentration screens. Under the guidelines, mergers resulting in unconcentrated markets would pass the screens; mergers resulting in moderately or highly concentrated markets would exceed the screens if they cause significant increases in market concentrations as measured by the Herfindahl-Hirschman Index (HHI) (see Figure 1). The new merger guidelines would revise the threshold for defining unconcentrated and concentrated markets and raise the level of HHI increases that can occur without exceeding the safe-harbor screening criteria.
If FERC adopts these new DOJ and FTC merger guideline standards, it will make a significant difference.6 For example, the new guidelines would change the definition of an unconcentrated market from an HHI of 1,000 to an HHI of 1,500. According to FirstEnergy’s recent FERC filing, the post-merger HHI in PJM-wide energy markets currently would be below 1,000, except for two off-peak periods when it would be no higher than 1,029. This means that the FirstEnergy-Allegheny merger largely would pass the current safe-harbor market-concentration screens, but that any significant subsequent mergers in PJM may not, absent divestiture. However, under the revised market-concentration screens in the proposed new guidelines, some potential future transactions that would exceed the current screens might be able to obtain timely FERC approval without divestiture. Similar effects would be seen in other geographic markets.
Notably, because the FirstEnergy-Allegheny transaction would raise the market concentration level in PJM, this would reduce the headroom for subsequent mergers within PJM to fit under the market-concentration screens. Thus, as can be seen, there’s a first mover advantage to firms considering large mergers. It will be easier for them to consummate consolidations of generating assets than for subsequent merger applicants.
The new proposed guidelines are expected to be adopted sometime this year. If FERC amends its merger policy statement to mirror the new guidelines, this will facilitate merger regulatory review. Even if FERC doesn’t immediately revise its criteria, the more lenient standards in the new guidelines will permit merger applicants before the agency to argue for greater flexibility in approving merger proposals.
A second development affecting competition analysis can be seen in the Department of Justice’s recently announced final judgment regarding the KeySpan-Morgan Stanley swap.7
The Justice Department charged that KeySpan violated the Sherman Act by entering into a financial hedge that gave KeySpan an incentive to exercise market power in the capacity market in New York City. Under this arrangement, KeySpan bought a financial derivative from Morgan Stanley, whereby Morgan Stanley paid Key Span a guaranteed revenue stream if prices rose above a specified value. It was alleged that this arrangement gave KeySpan, a pivotal supplier in the in-City market, the ability to profitably raise prices.
This recent DOJ action confirms that DOJ continues to follow the conceptual approach that DOJ utilized in the proposed (but failed) Exelon-PSE&G merger. In modeling the competitive effects of that proposed merger, DOJ input into its model the parties’ (and their affiliates’) financial hedging arrangements and other derivative transactions. DOJ’s analysis thus addressed whether these financial arrangements gave the merged entity an incentive or ability to raise prices that wouldn’t have been present taking into account only their physical generating assets. The lesson is that in assessing how a proposed transaction is likely to be reviewed by the antitrust enforcement authorities, the parties considering a merger should take into account their financial/trading arrangements.
• Transmission Planning: On June 17, 2010, FERC issued its proposed transmission NOPR.8 If adopted, the NOPR significantly would alter the manner in which transmission assets are planned and potentially constructed. A final rule that resembles the NOPR potentially would have very important ramifications for transmission-owning utilities, and several aspects of it could be significant to merger planning and merger approvals.
The NOPR proposes, inter alia, to: 1) require that transmission planning be done on a regional basis; 2) require procedures for coordinated planning between regions; 3) provide that transmission planning account for public policy requirements (i.e., namely renewables requirements), established by state or federal law; and 4) remove from FERC-approved tariffs or agreements “a right of first refusal [created by those documents] . . . that provides an incumbent transmission provider with an undue advantage over non-incumbent transmission developers.” If this rule is adopted, it could have several impacts relevant to regulatory evaluation of new mergers. It could result in larger relevant geographic markets, either as a result of consolidation of ISOs or substantial increases in the capacity of transmission interconnections among regions. Also, mergers of large transmission companies in adjacent regions arguably could facilitate inter-regional planning. The new NOPR, by proposing to eliminate the right-of-first-refusal of incumbent transmission providers, arguably might affect the competitive dynamics of the transmission business. However, transmission will remain a highly regulated business, with transmission access governed by FERC, and with a very large number of firms able to attract capital sufficient to enter.
Combinations might make the combined companies more efficient in their planning and stronger financially, and thus better able to develop and construct new projects. Moreover, consolidations of transmitting companies across regions might provide a means for the state agencies responsible for regulating the merged entity to have a greater degree of input into the inter-regional planning process than otherwise would be the case in a post-NOPR world, where individual utilities and state regulatory commissions may have little influence in the regional and inter-regional planning processes. In any event, with billions of dollars projected to be spent on increased transmission capacity in virtually every area of the country, and with major new transmission infrastructure an important FERC policy objective, FERC’s adoption of the policies in the transmission NOPR and their perceived effect on the merging companies and their state regulators may be a significant factor, pro or con, in the evaluation and approval of merger proposals.
• Economic Factors: A number of industry economic factors have changed in recent years in ways that affect both the appeal of potential transactions and the issues involved in their regulatory review. In the past, a number of mergers have been motivated by the view that generation assets were undervalued. In such a scenario, combining complementary merchant-generation portfolios clearly offered potential scale and scope economies that could enhance operating efficiencies and increase net profits. While efficiency gains from such consolidations may remain achievable, at present the prevalence of low gas prices has held down energy prices at the margin, diminishing the potential returns from merchant baseload and mid-merit generating assets. To the extent this situation continues in the medium- to long-term future, as some project, it can affect the strategic reasons for consolidation. There might be a lower premium placed on the potential future gains from a generating portfolio and a greater premium on efficiencies of scale and scope and technical acumen. Some of the focus also might be shifted from generating-asset efficiencies to the benefits of consolidating transmission and distribution assets.
• Financial Strength: Mayo Shattuck, CEO of Constellation Energy Group, Anthony Earley, CEO of DTE Energy, and others who perceive the need for increased consolidation have emphasized the need for enhanced financial strength.9 To the extent the public interest warrants new nuclear power plants, large extra high-voltage transmission lines, and other highly capital-intensive infrastructure investment, the formation of larger, financially stronger companies could serve that end.
• Renewable Goals: Generalizations about the ramifications of renewables policy on power industry consolidation are risky. Nonetheless, because of the importance of the issue at the state level, the interplay between a prospective merger and the renewables policies of affected states should be assessed carefully. In most areas of the country, meeting renewables targets will require building significant new transmission, hence considerations regarding transmission should apply. Obviously, state commissions considering merger applications will require assurances that consolidation will have no adverse effect on attainment of their renewables requirements.
Tolstoy wrote in Anna Karenina that all happy families resemble one another, while all unhappy families are unhappy in their own separate ways. So it is with electric power industry mergers; the mergers that are approved and consummated seem to march along without major mishap, with the combined companies better able to serve their customers and shareholders. The transactions that founder all seem to hit the shoals for a different reason, with each firm left to re-play its own what-if scenario. Potential acquirors and targets are much more likely to end up in the happy family category if the changes in the industry landscape are carefully examined in any analysis of a potential transaction and creatively addressed in any application to consummate it.
On the competition front, a different mode of competitive analysis may be required at the Department of Justice, at FERC, and before state commissions. It’s important to be aware of this in advance in assessing the need for, and the components of, any divestiture proposal. Otherwise, a proposal that satisfies one mode of analysis may not suffice under another, and an applicant may be trapped into expanding the amount of divestiture required to satisfy successive regulatory reviews. Knowing in advance how each of these bodies will assess the situation allows an applicant to anticipate a worst-case and advocate a best-case outcome and be certain both that no unnecessary divestiture will be required, and that the amount of mitigation ultimately imposed will be acceptable. It’s especially important, in this regard, that the pre-merger analysis take into account the modeling approach used by the Department of Justice and FTC, as well as the approaches used by FERC and the states.
Anyone familiar with the history of utility mergers knows that state commissions typically demand a sharing of benefits. However, the new factors concerning transmission planning and expansion, and their inter-relationship to renewables goals, might offer merger applicants an additional avenue for identifying benefits to consumers. Though the benefits from an expanded transmission network and more assured accomplishment of renewables goals are hard to quantify, they might carry weight with responsible, policy-wise regulators. Indeed, it might be possible to devise merger commitments responsive to these policy goals that will lessen the need for other benefits-sharing mechanisms. In any event, these issues need to be addressed at the state level at least to a much more extensive degree than in the past.
The pressure on gas prices might make long-term merger benefits due to an expanded generation portfolio difficult to quantify reliably. While the negotiation of rate concessions is a very complex and politically sensitive process in every case, the importance of attaining emerging policy goals of renewable resources and related transmission expansion might create opportunities for new performance-related metrics that address a reasonable sharing of merger benefits. For example, the merged company could be given credits, and allowed to retain a greater share of benefits, upon achievement of renewables and transmission goals.
Trend vs. Opportunism
Focusing on the most recent major transactions, each seems to represent an opportunistic effort to respond to some of the changes underway in the industry. The sale of E.On U.S. to PPL Corp. appears to reflect E.On’s desire to retrench on more familiar territory, coupled with PPL’s desire to rebalance its business mix by expanding its regulated business and to dilute the risk of its merchant generation. This goal presumably responds in part to perceived greater uncertainty in the generation sector.10 FirstEnergy-Allegheny at first glance might appear like some past mergers that positioned companies to benefit from a prospective upsurge in power prices. However, company executives emphasize that Allegheny would add 6,000 MW of supercritical coal-fired generation to FirstEnergy’s fleet, thus enhancing the merged company’s competitiveness at the same time and diversifying Allegheny’s assets with FirstEnergy’s nuclear generation. Thus, the transaction appears to be an opportunistic effort to consolidate generating assets in PJM and to diversify the merged company’s portfolio to reduce risks and augment possible upside gains. Mirant’s acquisition of RRI reflects the purchase of an entity that has for some time recognized the need for a merger to be successful. And the Blackstone Group’s acquisition of Dynegy is expected to allow Blackstone, having far greater financial resources, profitably to sell off Dynegy’s gas-fired plants in California in ways that Dynegy, handcuffed by its debt instruments, could not.These recent transactions, each with an individualized motive, don’t necessarily suggest an accelerating wave of consolidation. They do suggest, however, that in this relatively fragmented industry, opportunities for beneficial consolidations will continue to occur, and that the potential benefits of such consolidations will tend to be strategic and reflect the broadening scope of power markets and electricity policy.
1. FirstEnergy/Allegheny, RRI/Mirant, and E.On/PPL.
2. Peter Maloney, “CEOs Share Views on Consolidation, Cost of Building Plants, EPA and Climate Change,” Platts Electric Utility Week, Mar. 22, 2010, at 1. Exelon has attempted to consummate three major acquisitions in the last several years.
3. FirstEnergy Corp., Sec. and Exch. Comm’n Form S-4A, June 25, 2010, at 63.
4. I/M/O the Merger of FirstEnergy Corp. and Allegheny Energy Inc., Direct Testimony of Anthony J. Alexander, at 10, 11, Md. Pub. Serv. Comm’n, Case No. 9233 (May 27, 2010).
5. Prior to the EPAct of 2005 instituting a 360-day time limit, this process often was even longer.
6. These new screening criteria are intended to update the guidelines to reflect the current practice of the antitrust enforcement agencies. Thus, in most industries the changes simply reflect current practice and may not have a significant impact. But in the electric power industry, FERC currently applies the screening criteria in the existing (and soon to be superseded) guidelines.
7. United States v. KeySpan Corp., Final Judgment, Civ. Act. No. 10-cv-1415 (S.D.N.Y. Jun. 17, 2010). The arrangement challenged by the Justice Department Antitrust Division was more complex than lends itself to full discussion here. According to the Justice Department’s complaint, KeySpan was aware that a financial services company (now known from a related FERC proceeding to be Morgan Stanley) had entered into a related agreement with one of KeySpan’s competitors, the owner of the Astoria generating unit, so that the combined effect of these derivative transactions was to give KeySpan the revenues associated with higher prices on Astoria’s unit as well as its own, thus insulating KeySpan from competition and ensuring it could profit by raising prices. United States v. KeySpan Corp., Competitive Impact Statement at 1-2, Civ. Act. No. 10-cv-1415 (S.D.N.Y. Feb. 23, 2010) (Final Judgment and CIS are both available here).
8. Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Notice of Proposed Rulemaking, 131 FERC ¶ 61,251 (2010).
9. See e.g., Paul Carlsen, “Constellation Aiming to Buy Gas Plants with $1Billion of Cash from EDF Deal,” Platts Electric Utility Week, Mar. 1, 2010, at 32; Mark Chediak, “Utility Mergers May Increase, DTE CEO Anthony Earley Says,” Bloomberg Businessweek, Feb. 23, 2010.
10. Rosy Lum, “PPL Paid a ‘Premium’ to Lessen Commodity Exposure, Grow Regulated Business,” SNL Energy Finance Daily, May 3, 2010 (stating that PPL “see[s] a kind of continued erosion in the earnings power of [its] generation fleet”).