Can U.S. Generators Break the Proverbial Boom-and-Bust Cycle of the Power Market?

by Jeff Ryser, Senior Writer, Platts Electric Power Group

U.S. summer temperatures soar, as does the demand for electricity—exceeding forecast peaks in some locations. Several energy companies, worried about market crashes in the years ahead, are looking to up capacity in their most strained markets, igniting debate over how to keep prices and capacity level.

IN THE U.S., ELECTRICITY DEMAND HAS BEEN growing faster than some had expected thanks to solid economic growth and a housing boom that has spawned bigger homes, more central air conditioning, and more computers and appliances. In some places, the growth has bitten into fat generation surpluses created by the building boom of the late 1990s and early 2000s.

In exceptional heat this past summer, no market crashed from lack of supply, but some locations went far past forecast peaks. The PJM Interconnection had projected its summer peak would reach 131,439 MW, but it set a new record in early August with 144,796 MW. New records were set, as well, in New England, New York, the Midwest Independent Transmission System Operator (MISO), Texas, California, the Southwest Power Pool, and Tennessee Valley Authority (TVA).

While anything resembling real shortages remains a few years away in most markets, a number of firms, notably TXU and NRG, are eyeing two of the markets that will need new capacity the soonest: the Electric Reliability Council of Texas (ERCOT) and PJM, the Mid-Atlantic-into-Midwest system.

ERCOT, where ambitious TXU is proposing to build eight new 800-MW coal plants, says that without new generation its reserve margin will fall from 16.9% in summer 2006 to 15.2% next summer to 11.8% in 2008 and 8.9% in 2009—ERCOT has said it wants a minimum of 12.5%.

The other market TXU is eyeing is PJM, where it wants to build 5,000 MW to 8,000 MW of coal-fired merchant generation—PJM has about 165,303 MW of capacity. If its summer peak had been near the projected 131,500 MW, it would have had a very comfortable 25% reserve margin, but the new peak record reached almost 145,000 MW, reducing the margin to about 14%, below the 15% that PJM requires. The much higher than expected new peak record made TXU's plans for PJM suddenly much more compelling.

Other regions still have big excesses. The Southwest Power Pool (South Central U.S.) for example, has 55,023 MW, so even with demand hitting a new all-time peak of 42,227 MW this summer, its capacity margin fell to a fat 30%. The big Midwest ISO is another market that still has a healthy surplus—about 18%—left from the last building boom.

Price Signals

Federal and state regulators, like some market players, are struggling with how to smooth out another boom-and-bust cycle. From a regulator's point of view, the problem is to get capacity additions before politically unacceptable price increases make it clear that they are needed.

The last cycle featured price spikes in some places and shortages in 1998 and 1999, followed by huge additions of merchant generation early this decade, resulting in the current surplus. ISOs and state and federal regulators are embroiled in long-running debates over creating capacity markets where plant owners get revenue just for being there when they are finally needed and all market participants pay the owner for building the capacity.

Consumer groups and industry players that are traditionally short power, like municipal utilities, say capacity markets are a bad idea because it is impossible to tell if high prices in those markets signal scarcity and the need for more generation, or if they simply reflect capacity owners' exercise of market power in a non-competitive capacity market.

Some regulators and market organizers have eschewed the capacity market idea in favor of what they call a purer market approach: lifting or removing price caps. This year, Texas decided to go that way and the Midwest ISO is trying to win support for it, although officials aren't sanguine about their chances of winning approval.

Whatever mechanisms are being relied on to send price signals so that new generation starts get under way soon, forward power prices show that the market doesn't really expect any tightening in supplies for years. The forward curve shows current market expectations that power prices are headed down through 2009 in Eastern and Central regions and through 2010 in the West.

Forward power prices are heavily dependent on forward gas prices and generally reflect the current market expectations as reflected in the NYMEX futures contracts. Forwards in recent times have reflected the market's expectation that power prices will trend downward over the next several years, even though they reflect NYMEX futures prices that have been considerably higher than what some forecasters expected.

August 24, for example, the NYMEX Henry Hub contracts for 2008 showed an average price of $9.198/mmBtu. In stark contrast, in August, Standard & Poor's projected Henry Hub prices of $4.50/mmBtu for 2008 and $4/mmBtu for 2009 and beyond. (Standard & Poor's, like Platts, is owned by The McGraw-Hill Companies.) Such drastically lower gas prices would have huge implications for the market in general, and in particular for developers who are focusing their efforts on new coal-fired capacity.

The Regulatory Factor

Although non-utilities, like TXU and NRG, have big plans to build, it appears to have become a truism that traditional utilities are, again, the best business model in the power industry—despite more than a decade of "restructuring" and working to make wholesale and retail markets competitive.

One reason: They are in the best position to make money off the huge investments needed in infrastructure—transmission and distribution, as well as new generation—assuming state regulators let them recover the investments and make a sufficient rate of return. One after another, utilities are winning state regulatory backing for plant-building plans, in the interest of security and control.

The regulatory factor is something that generation developers take into consideration. TXU, for one, pointed to it as one reason it is planning to build plants instead of buying them, which would mean "trying to get a deal past regulators, then share most of the savings with ratepayers."

TXU has said it "improved the risk/reward profile" of its expansion plans in four ways. First, it has secured a commitment for $11 billion of non-recourse financing at "favorable rates" to fund construction and to provide collateral support as part of a new subsidiary development company, TXU Generation Development Co. (TXU DevCo).

Second, TXU said it would be hedging a "significant portion" of the economic output of the facilities through 2012, with the ongoing execution of the company's natural gas hedging program.

The company said it would also be launching a process to sell forward the power from TXU DevCo. Furthermore, the Dallas-based firm said it would work with Morgan Stanley and Citigroup as financial advisers to lead a process for the potential sale or swap of equity interests in TXU DevCo. "High interest in physical power purchases and TXU DevCo's equity is indicative of the broad public policy and financial appeal of the program," the company said.

Assuming local opposition to the coal plans does not prevail, TXU has said that the coal-fired power plants could begin operating by 2010 and would meet growing demand for power through 2013.

And it's not just fossil fuels TXU is eyeing; just before Labor Day 2006 the company said it would apply to the Nuclear Regulatory Commission for combined construction and operating licenses to create between 2,000 and 6,000 MW of new nuclear capacity in Texas. The nuclear plants, if TXU ultimately decides to build them, would be at one, two or three sites and would begin commercial operation between 2015 and 2020.