Power generation industry pulled in many directions

Kathy Carolin Larsen

While American utilities grapple with the impacts of doubled natural gas prices and the Energy Policy Act of 2005, their European counterparts are focusing on consolidation and carbon control.

IN MID-AUGUST, THE STORY OF THE YEAR in the U.S. electric power industry appeared to be the passage—after about 15 years of trying—of a comprehensive energy bill that repealed the long-derided Public Utility Holding Company Act of 1935 (Puhca). For years, the industry consensus was that the demise of Puhca, which restricted ownership of utilities, would release a pent-up firestorm of mergers that would narrow the ranks of American power companies to a precious few giants.

But then hurricanes Katrina and Rita trashed the heart of the U.S. natural gas production and refining complex on and off the Gulf Coast, and a new story crashed to the forefront. Further escalation of already-high gas prices sent many power stations' costs into the stratosphere.

Cheap gas is history

As gas futures soared into the $14/mmBtu range, industry veterans suggested that the price was unlikely to sink to "normal" levels any time soon. About a year ago, $5 to $6 gas prices were causing some excitement. But over the past half-decade, gas prices often have not slumped back to historic levels after an increase. Instead, higher plateaus developed.

"Do we get back to normal after winter?" asked Steve Piper, managing director of forecasting for Platts Analytics, following up with an even more difficult question: "And what does 'normal' look like?"

Winter power prices went to as much as $200/MWh in New England after the second hurricane—a 52% leap in about a month and 160% higher than last winter's average price. Even a few weeks later, the New England winter package closed at $194/MWh. Prospects for coal, oil, and nuclear generation looked good, but gas-fired plants' outlook was tough, said Credit Analyst Peter Rigby of Standard & Poor's (like Platts, the publisher of Insight, a part of The McGraw-Hill Companies, Inc.) in October.

It was unclear how much of the rise would hold as winter gave way to spring and summer 2006. But prognosticators agreed that the baseline had indeed changed.

Dial M for merger

As the hurricanes snatched the headlines from Puhca's repeal at summer's end, the industry was still pondering the significant regulatory consequences and implementation details of the Energy Policy Act of 2005 (EPAct).

Even before Puhca was repealed, three major utility mergers were announced between December 2004 and July 2005. Exelon said in December that it would buy Public Service Enterprise Group in a deal valued at $25.7 billion. In mid-May, Duke said it would buy Cinergy for $9.1 billion. Only a few weeks later, MidAmerican Energy announced it would buy PacifiCorp for $9.4 billion.

Pre-EPAct, MidAmerican and Duke said their purchases could pass muster under Puhca's tough limitations, although some disagreed. Now, of course, such claims and questions are moot. But at the time, repeal advocates could never be certain they would succeed, so the passage this summer of EPAct was a huge moment for them.

Because the Federal Energy Regulatory Commission (FERC) has to go through rulemakings to implement the new law, uncertainty about future market structure still prevails, making players hesitant to invest. Among the questions they are asking: How tough will FERC be in rewriting its open-access rule to eliminate remaining discrimination in transmission service? Will generation capacity be planned with organized incentives or on a free-market basis? Will utility holdouts be forced to turn over more control of their transmission systems? Will a national mix of regionally organized markets and strictly bilateral markets be able to survive for long? Uncertainty in these and other areas has made it hard to predict when pent-up merger-and-acquisition energy might begin to be released.

Only one thing seemed clear: Billionaire Warren Buffett, the controlling owner of MidAmerican, has $40 billion itching for investment, and he has said he wants to do more in the energy sector. Theoretically, with Puhca off the books, he is free to buy almost anything he wants.

Among other companies more than just mildly interested in the power industry are Wall Street giants and investment funds. They have made their presence increasingly felt in the generation and marketing/trading arenas, where, for example, Bear Stearns struck a deal this fall with financially strapped Calpine Corp. to form a trading venture. Bear Stearns joins JPMorgan Chase, Lehman Brothers, Credit Suisse First Boston, Merrill Lynch, and others that have already made marks in the energy sector. In a novel twist, GE Energy Financial Services formed a "development club" with Starwood Energy Group Global to focus on buying mid- to late-stage development projects with long-term equity investment potential.

In a nutshell, a GE Energy Financial Services executive said in September, "Everybody and his mother is an investor in the energy space."

IPPs vs. IOUs

Given the gas-price situation, being in the energy space this year poses big challenges to merchant generators. At least one merchant saw virtue in broadening its fuel mix. NRG Energy agreed to buy Texas Genco to create the second-largest merchant firm in the country, giving NRG a U.S. generation portfolio of 23,920 MW that is "fuel, dispatch, and geographically diverse." The largest U.S. merchant power firm, Calpine, has at least 27,000 MW of operating capacity, almost 98% of it gas-fired.

Another hurdle for merchants is the trend of utilities' self-building generation and moving unregulated plants into the rate base. At this year's Platts Global Power Conference, Jean-Louis Poirier of GF Energy estimated that 50 GW of capacity would be built between 2005 and 2012. Independent power producers (IPPs) could build up to 55% of it, he said, but for the trend toward utility self-building and ratebasing. Adopt a "guerilla" mindset, Poirier advised merchants, to deal with capacity procurement processes that vary widely from one state to another.

That very subject—capacity procurement, or resource adequacy—has been a focus in 2005, with a developing battle between the capacity-market models used in regional grid operations in the East and those who suggest that these markets benefit no one but independent producers. "No generator left behind" is how the American Public Power Association described the regimes.

The Midwest Independent Transmission System Operator (MISO) is promoting a different plan that would lift real-time power price caps and urge (or require) utilities to sign long-term contracts. This argument will be closely watched in the next year as a test of how much faith regulators, customers, and industry have in pure market mechanisms. Indications are that advocates of MISO's approach face an uphill road.

The question will have special significance as the big enchilada, California, studies how to design its own plan. California's job is far more complicated than anyone else's because the state is considering a factor that most others are not yet—carbon emissions.

EU pushes carbon controls

Although Europe is now in the throes of dealing with carbon, the U.S. government continues to resist any moves to limit global warming. But investment funds and pensions with $21 trillion in assets are pressuring utilities and other companies to deal with the issue, and a handful of states are figuring out how to craft their own greenhouse-gas reduction plans.

As an example, California's utility regulators have adopted a plan that would put a per-ton value of between $8 and $25 on a greenhouse-gas adder. However, the regime, which would likely have a big impact on out-of-state coal burners looking to sell their production into California, was only starting to reach serious levels of detail and practicality late in the year.

Across the country in the Northeast, political leaders and utility regulators were moving toward agreement on the Regional Greenhouse Gas Initiative—a carbon cap-and-trade program for power plants. But critics were hammering the plan, not least because it conflicted with the federal government's foreign policy.

That policy does not endear itself to Europe, which is caught between a rock and a hard place as it carries out its Kyoto Protocol commitments to reduce greenhouse gases. Carbon prices in the EU more than tripled from January to September and were hovering around 23 euros/ton this fall. Carbon is definitely "at the forefront of any analysis by potential investors," according to Michael Wagner of IPA Energy Consulting.

Regulatory and structural uncertainty plays as big a role in Europe as in the U.S., and one issue stood out as common to both continents: continuing perceptions that some "national champions" or old-line utilities are getting transmission preference. In Europe, the questions of carbon allowance allocation and windfall profits for some companies are slowing the progress of the Continent's emissions trading system.

Some European power industry leaders, facing the task of achieving their carbon goals in a limited sphere, are pushing the view that Europe will have to abandon its commitment to Kyoto unless the U.S. plays the game, too. "The greatest weakness of the European system is that it is just that, European," Vattenfall CEO Lars Josefsson warned an audience of bankers and financiers in Stockholm this September.

According to Josefsson, the EU has invested so much prestige in ratifying the climate change protocol and setting up its emissions trading system that it will not drop it before 2012, when the second phase of the trading scheme is scheduled to end. But after that, he continued, "there has to be a global price [for emission rights]. We have to get the U.S. on board." He said other utilities agreed with him, simply because European industry "can't take the brunt of this."

EU mergers begin

Complicating the situation, carbon prices and higher oil/gas prices have driven European power prices up. Those prices have become perhaps the single strongest driver of what looks to be a new wave of consolidation in the Old World.

In the early fall, Gas Natural made a hostile bid for Endesa, Eon admitted it was looking at ScottishPower, Centrica was linked to a possible bid from Gaz de France or a partnership with Norsk Hydro or Shell, Suez had moved to take control of Electrabel, and Electricité de France was said to be about to buy UBS's stake in Atel.

One analyst told the newsletter Power in Europe that this year's commodity-price scene was completely different from last year's: "The time to buy [a company] is now, when most valuations are more consistent with $35–$40/bbl of oil, not when valuations finally catch up with reality." The low cost of capital also appeared to be supporting the activity.

The gas-price factor played at least some role in another way, as some analysts saw pure-gas player Gas Natural's bid for Endesa as partly a bid for fuel diversity.

Whether a European company will take advantage of the newly liberalized investment opportunities in the U.S. is an open question. ScottishPower left the U.S. utility market by agreeing to sell PacifiCorp, and thereby made itself a more attractive target for Eon. In the U.S., Eon owns LG&E Energy in Kentucky, and despite occasional rumors that it would sell the business, it has not done so. Meanwhile, National Grid of the UK owns northeastern U.S. utilities and has expressed interest in getting seriously into the transmission business in other regions of the country.

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