Merchant Power Players and Utilities Undergo Mega-Mergers

By Theo Mullen, Managing Editor, Megawatt Daily

Changing market prompts companies to focus on near-term strategies

FOR YEARS, EXPERTS AT THIS GLOBAL POWER Markets forum predicted the U.S. independent power industry would shrink to but a few companies. Some forecast a handful of merchant companies would hold most of the generation.

The future didn't unfold quite that way. Yes, there are fewer merchant power companies. And many are quite large. But many independent power producers (IPPs) just seemed to fade away over the last several years. Some sold their assets to other IPPs or investor-owned utilities (IOUs), some defaulted on their project loans and their lenders took over, and others were acquired by investment funds.

Ranking of companies cited in article among top 250 global energy companies Source: www.top250.platts.com

For example, major merchant player NRG Energy bought Texas Genco for $8.3 billion in cash and assumed debt. Previously, Princeton, N.J.-based NRG held more than 15,000 MW of merchant plants, mostly in the Northeast, South Central, and West. Texas Genco's assets give NRG approximately 11,000 MW in the Electric Reliability Council of Texas and a total portfolio of about 26,000 MW.

Similar deals are expected this year and others are already looking for opportunities. Soaring market valuations for solid-fuel-fired plants particularly in the Texas market prompted partners Sempra Energy and the Carlyle/Riverstone Global Energy and Power Fund to hire Goldman Sachs to help sell their 4,112 MW of coal-, lignite-, and gas-fired units.

Houston-based Dynegy Inc. is looking to buy more generation assets. The company owns about 12,600 MW, mostly in the Midwest, Northeast and South. Specifically, Dynegy's near-term strategy calls for de-emphasizing long-term power deals, taking advantage of generally rising prices in short-term markets, and looking for opportunities to acquire additional plants, said Dynegy Chairman and CEO Bruce Williamson.

Dynegy is working to reduce its long-term commitments and to purchase plants that complement its generation and power-sales position in key markets. The strategy "means that we minimize our forward sales position," Williamson said. "In a fundamentally rising market, which we are experiencing, emphasizing a forward sales strategy can create a new synthetic debt maturity for a company.… A company that hedges its position by locking in positions on forward sales will receive a collateral call for the provider when prices move up, which could put a significant drain on liquidity," he said. "Our near-term strategy does not expose Dynegy to this risk, and our consistently low collateral level demonstrates that."

Key Market Changes

Recovering wholesale power markets are also prompting some other IPPs to change traditional strategies to embrace wholesale electricity price fluctuations.

In February, Reliant Energy said it would place less reliance on hedging. "We have concluded that the hedging of our coal plants, which was designed to reduce volatility, actually added complexity and cost to our business," Reliant Chairman, President, and CEO Joel Staff said. Reliant entered into most of its coal hedges in 2004, but when natural gas prices rose sharply in the third quarter of 2005, Reliant's hedge-related collateral requirements soared as well.

Staff said the move would enable Reliant to realize the value inherent in its generation plants. The change adds $190 million to retail margins by 2007, he said, and would return to the company some $1 billion in cash collateral requirements.

Dynegy, of course, is also making changes to further eliminate its reliance on hedging. "We are going to be much more of a commodity-play business," said Williamson. He said Dynegy would concentrate on selling the electricity produced by the company's power plants much closer to when it is produced, rather than trying to "out guess the market by selling forward two or three years out."

With the sale of its midstream natural gas business in fall 2005, Dynegy is now a "pure-play independent power producer," Williamson said. Dynegy has emerged from the financial strain it and many other IPPs experienced in the first half of the decade. "We are looking for acquisitions more than greenfield development," he said. He also acknowledged Dynegy may be a takeover target because of its improved financial and operational performance.

IPPs have sold power forward in a market in which gas prices have been rising, and as a result, said Williamson, they have missed market upside and left money on the table; they also have had to post huge amounts of cash collateral and sacrifice liquidity to provide credit support for their hedge positions.

Over the past several years, a perfect storm of rising gas prices, falling wholesale power prices, and outsized debt burdens has prompted most merchant generators to hedge their bets by entering contracts that locked in power prices or fuel prices, or sometimes both. Throughout, the generators harbored hopes of a recovery, but as spark spreads began to recover, the same hedges that protected them on the downside hurt, or at least hampered them, on the upside.

Craig Shere, an analyst with Calyon Securities, said that if companies hedge while spark spreads are expanding and gas prices are high, they are not only locking in prices, they are "locking in lower profits." Then, "When the market goes through your hedge, you have to post more collateral."

Other companies, including some integrated utilities with large wholesale generation operations, are also looking at unhedging their generation, said Jean-Louis Poirier, senior strategist at consulting firm GF Energy. One of the factors making the unhedging strategy more attractive, and more feasible, he said, is an increased use of auctions by utilities to fill supply needs.

By 2010, all 17 states that have passed deregulation legislation will have reached the end of the transition periods that were designed to serve as buffers between regulated and competitive market pricing. At that point, power prices in those states will rise and fall freely with changes in the marketplace.

Rather than get caught in the trap of buying long-term fixed-rate power for sale in a variable-rate market, utilities will choose to hold auctions, argued Poirier. The cost of power bought at an auction can be passed on to customers, he noted, and "You can't be [caught] long by doing a pass through." These auctions, which are generally for two- or three-year contracts, will also provide a useful alternative to hedges for wholesale providers seeking the security of locked-in prices.

Generation investment, by industry sector, 2005 Source: Federal Energy Regulatory Commission, Platts

So for now, said Poirier, not hedging is a better strategy for merchant generators, if they can manage their fuel prices, because prices are going in their direction. Or, as Shere noted, "Making a bet works—when you're right."

Significant IOU Consolidation

Because of significant IOU consolidation, this year is widely expected to alter the tone and tenor of the domestic power industry

Five major utility mergers are pending and progressing: Exelon/Public Service Enterprise Group (PSEG), Duke/Cinergy, MidAmerican Energy/PacifiCorp, FPL Group/Constellation Energy—and National Grid/KeySpan. More mega-mergers are expected.

Rising cost pressures and "size envy" are two of several reasons Merrill Lynch analysts believe IOU mergers and acquisitions will accelerate in 2006. "We are hearing many utilities openly discuss interest in corporate M&A [mergers and acquisitions] activity for the first time since the late 1990s," said Steve Fleishman, Jonathan Arnold, and Elizabeth Parrella in a recent Merrill Lynch analysis.

The trend is driven by envy of other mega-deals, regional market and fuel scale and diversity, rising cost pressures and interest in mitigating rate increases, increased options under the repeal of the Public Utility Holding Company Act, and a "more pragmatic" Federal Energy Regulatory Commission.

For example, a combined Exelon/PSEG would form the country's largest utility, with seven million electric customers and two million gas customers. The new Exelon Electric & Gas also would also be the country's largest power generator, with 52,000 MW of generation, including 20,000 MW of nuclear capacity.

The $11 billion combined FPL and Constellation would create one of the nation's largest utilities with 45,000 MW—24,500 MW of it merchant and 20,500 MW owned by regulated Florida Power & Light.

The repeal of PUHCA by the Energy Policy Act 2005 (EPAct05) underpins an IOU merger blitz. EPAct05 handed significant new powers to FERC, and it is acting quickly, finding little to dislike—so far—in most big deals. But the five deals may just be a precursor of the rest of the year, which could be the biggest yet for mergers and acquisitions since the late 1990s.

PricewaterhouseCoopers' Transaction Services group says how companies decide to use their "huge cash reserves from record commodity prices" will determine how M&As unfold in 2006. The "back to basics" strategies many IOUs pursued over the last several years resulted in strong balance sheets, good credit ratings, and predictable cash flows, PwC said. Look for consolidation among IOUs to eventually yield "a small number of 'super regional' companies," it suggested.

James Halloran, an analyst at Cleveland-based National City Private Client Group, agrees. Other energy companies "may not want to be bigger, but they want to be in the ballpark. All of the major guys, and you'd have to include AEP [American Electric Power] and FirstEnergy, will be saying, 'How does this affect us?' Over the next couple of years you'll end up with six to 10 utilities that will be in that ballpark."

Duke Energy Chairman and CEO Paul Anderson seems to agree. Duke's proposed $9 billion merger with Cinergy could well be the first step in a much larger expansion, he suggested. A successful merger would enable each company to "keep the face of" the regulated utilities in the Carolinas and the Midwest—one regulators and customers find familiar—but combine back-office operations and gain significant efficiencies, he said at a recent conference.

"If you get that done right, you can add more [utilities] to it and get more economies of scale, and each time you do that you are adding to the revenue base," Anderson said. He declined to elaborate or identify potential acquisition targets.

Duke pursued a merger with Cinergy because of its planned withdrawal from the merchant-power and energy-trading markets. The company realized its growth prospects were then largely limited to the footprint of its regulated Duke Power subsidiary, Anderson said. Duke also is working toward financial close of a $1.5 billion sale of 6,100 MW of merchant plants in the Northeast and West to LS Power Equity Partners.

Modest Generating Fleet Expansion

Contributions to new generation in the United States from IPPs in 2005—about 4,000 MW—were less than half the level of IPP contributions in 2004. IPPs added about 7,000 MW in 2004. Overall additions to U.S. power generation in 2005 totaled about 17,000 MW, a 25% decline from 2004 and down 75% from 2002, according to separate estimates by the FERC and Platts.

Of the industry sectors investing in generation in 2005, FERC said IOUs built 7,000 MW; public power and cooperative utilities about 4,000 MW; IPPs about 4,000 MW; and utility affiliates about 2,000 MW.

New generation by fuel source, 2005 Source: Federal Energy Regulatory Commission

Although U.S. capacity additions peaked in 2002 at 77,100 MW, the 17,000 MW in 2005 was still more generation added than in 14 of the previous 20 years. Capacity additions drifted downward in subsequent years: 50,678 MW in 2003, and 27,033 MW in 2004. The 77,100 MW of additions in 2002 resulted in significant over capacity in many areas.

Of the 17,000 MW added in 2005, FERC said some 84%—about 14,300 MW—used natural gas as fuel, down from 96% in 2004. Another 14%—2,380 MW—was wind generation. FERC attributed the increase in wind—up from 1% in 2004—to the federal tax credit for wind plants and state fuel diversity programs. About 2%—just 340 MW—of new capacity in 2005 used coal as fuel, FERC said.

The biggest chunk of the additions in 2005 was in the Southeast, FERC said, mainly in Florida. Compared with 2004, California and the Midwest had relatively high investment. New England had almost none, and the PJM Interconnection had a small increase, mainly renewables. About a third of the generation additions were in transmission-constrained locations, FERC said.

Meanwhile, for 2006, IPPs and IOUs are forecast to add between 17,000 MW and 18,000 MW to the U.S. fleet, similar to capacity additions in 2005 but relatively low by historical standards. The 2006 additions come as reserve margins in eight of 10 North American Electric Reliability Council are set to decline sharply. The confluence of the two trends is likely to exaggerate pockets of over supply and under supply in certain regions, particularly the Northeast and Central.

The fuel component of 2006 additions indicates a dramatic shift. Once a laggard, wind power is red hot. Some 8,400 MW of new wind generation is scheduled to join the grid during the year, the most ever for a single year. Wind accounted for 2,758 MW of new 2005 capacity. In fact, the total for planned 2006 wind projects is just short of the capacity additions planned for gas-fired projects, about 8,400 MW, well below half of what gas-fired generation was added in 2005.

The remainder of new 2006 capacity is a scattering of coal projects and small renewable projects, mostly wood and geothermal.

For now, gas-fired project developers are reeling from a sharp price run-up, with just modest relief in sight. Fitch Ratings analyst Adam Miller views "high natural gas prices as a temporary market condition" and expects a return "to more modest levels over the next few years." Henry Hub spot prices will average $7/Mcf for all of 2006, down from $9.15/Mcf in 2005. Longer term, Miller thinks prices between $5/Mcf and $8/Mcf will be the norm until enough liquefied natural gas is imported to offset declining domestic production. Miller suggests average prices could fall to $3.50/Mcf once LNG becomes a more substantial ingredient in the U.S. gas supply mix.