GENERATION

Will Dailey is the primary author and director of Platts Research & Consulting's "RDI Power Outlook Research Service."

OF GLUT AND SCARCITY, OF BOOM AND BUST
How quickly things change. In less than a year the power sector has fallen on lean times. In the wake of Enron and subsequent accounting scandals, CEO resignations, and trading scandals, formerly high-flying power sector stocks took a huge hit in the first half of 2002. How did things go so wrong so fast? And could they get worse?

In the late 1990s, the concept seemed simple: Power markets were deregulating, electricity demand was growing at historically high rates, and the fleet of older, fossil-fired plants appeared headed out. Those conditions together with power shortages in the Midwest and Western regions made it seem like a good time to invest in new powerplants.

Developers like Calpine, Mirant, Reliant, and Duke Energy led the capacity charge, and numerous smaller players also joined in the rush to invest in generation. Each saw the same opportunities—power shortages in key regions and the ability to bring highly efficient, clean-burning gas-fired powerplants to market to replace older, less-efficient coal-fired capacity. Capital markets became comfortable with financing gas-fired generation. Despite signs of impending over-supply, obtaining financing for a new combined-cycle powerplant in 1999 or 2000 may have been as easy as obtaining financing in 1997 or 1998 for the latest dot-com craze.

In fact, in the last three years more than 200 different stakeholders have brought more than 140,000 megawatts (MW) to market, representing a supply increase of around 20 percent in North American power markets. The building boom appeared to slow down in late 2001 and early 2002 when price forecasts and capital availability collapsed, causing developers to curtail their expansion plans and cancel or postpone more than 175,000 MW of announced additions—but the rush to market still is not over, according to RDI's second quarter "2002 Power Outlook" forecast. More than 60,000 MW remain under construction and are slated to begin operation in 2003 and 2004. If they are built, North American markets could see a supply increase of nearly 30 percent in just five years.

This part of the construction cycle creates dilemmas for the future. After all, it's not as if that supply won't be needed by the end of the decade—in fact, we'll need more than 100,000 MW. How companies and capital markets address today's part of the cycle will affect everyone's needs less than 10 years from now.

No Shortages in Sight
Fundamentally, gas-fired generators make money in two ways—when disparities (measured in "spark spread") exist between natural gas and electricity prices, or when price spikes related to capacity shortages occur. It's this second source of volatility that new powerplant developers—particularly developers of peaking capacity—rely on to achieve their returns. While a price of $10 per million British thermal units of gas can result in $200 or $300 per megawatt-hour (MWH) power price spikes, capacity shortages can result in $1,000 or $2,000 per MWH spikes.

Ongoing gas price volatility is a given, especially as gas supplies and transportation are tested by the introduction of new gas-fired powerplants. But shortage-related price spikes are not: Such spikes can occur when a market is just 1 or 2 percent short on capacity. On the other hand, markets that have a 1- or 2-percent surplus are unlikely to see shortage-related price spikes. Since by the time the construction boom plays out the power market supply could increase by as much as 30 percent, it's clear there won't be a shortage problem. While this is good news for electricity consumers, it's bad news for power developers that recently brought new capacity to market.

The power construction boom seems to portend a price bust—and only the degree and duration of the bust are still up for debate. Some industry observers believe price recovery is just three or four years away. But according to RDI—even taking into account the recent cancellation announcements—most U.S. power markets are unlikely to see price recovery until later this decade.

Either way, the outlook is pretty grim for cash-starved power developers.

Those who believe in early price recovery are hanging their hats on two possibilities: that the recent trend toward cancellations will decrease or eliminate capacity surpluses, and that older, less efficient powerplants will be retired. At this point, neither possibility appears likely.

Impact of Cancellations
It's a lot of generation to cancel or postpone, 175,000 MW. But to put that number in perspective, you need a sense of just how large the construction boom could have been.

Platts NEWGen database currently contains data on projects totaling nearly 600,000 MW—enough to double the North American power supply. Minus the new projects that are finished, under construction, or have announced cancellations, there still are nearly 200,000 MW that have not been canceled.

Will all those projects be built? No. Only a small portion of them will ever provide an electron to the market. However, it does show that for every project that is canceled, there is another developer taking a wait-and-see approach who may be willing to step into the canceled project's spot in the development queue if market conditions improve. In many cases the developers of these projects have already lined up sites and purchased turbines. Should wholesale cancellations occur and shortages appear imminent, it is likely that some developer will step up and build a plant to meet any shortages.

According to RDI's forecast, while the cancellation trend is significant, it is not likely to cause power shortages in the near future. First, the sheer number of plants that have already begun operating, plus those plants that are now under construction, are enough to ensure significant oversupply in most markets. While developers have canceled some under-construction projects, the vast majority of projects that have broken ground are not likely candidates for cancellation—developers have too much invested in them by the time construction begins.

Regional Shortages Possible, But Unlikely
In some regions power projects are harder to build than others. That's been the case in California and New York where, due in part to more stringent siting requirements, power markets have not shared in the construction boom to the extent that other regions have.

For example, despite the clear market signals sent to suppliers during the California power crisis, investors are fleeing the state. Developers have announced more than 14,000 MW of canceled projects in recent months—and some of them were already under construction. Cancellation announcements jumped in California when lawmakers announced their intention to renegotiate long-term power contracts they entered into with generators during the crisis. The state has threatened to abrogate the contracts if power suppliers do not renegotiate. Developers of new projects realized they were building into a market with a political risk profile similar to that seen in banana republics. Their response has been to walk away.

But California is part of a broader regional market that has seen a great deal of development. Barring widespread cancellations of under-construction projects, enough new capacity will be added in the state and in the broader market to avoid power shortages for quite some time.

While New York as a whole has always had excess capacity, New York City and Long Island have historically had problems with shortages due to difficulties with siting new powerplant facilities and transmitting power from other parts of the Northeast. But help is on the way there with nearly 1,700 MW moving forward in the city and on Long Island. The likelihood of projects targeting such a tight market being canceled is very low.

Retirements Not Occurring...Yet
RDI's forecast indicates that more than 20,000 MW of older, inefficient capacity could be retired for economic reasons between 2003 and 2006. However, many of the candidates for retirement still operate under regulated rate bases and have different economics than plants built by nonregulated power developers. Should these circumstances continue, the owners of regulated capacity are not likely to have the incentive to retire noneconomic plants. But new powerplant developers have been counting on the retirement of older, less-efficient plants. These developers built efficient combined-cycle capacity specifically because they believed they would be able to chase older, less efficient fossil-fired plants from the market.

All things being equal, the decision to retire or withdraw capacity from the market will hinge on the owner's perception of the likelihood of market recovery. Of course, all things may not remain equal. New environmental regulations could accelerate retirements. If more stringent emission standards are imposed on powerplants, retirement schedules for older coal-fired plants could accelerate dramatically. Companies that built new gas-fired powerplants know that these accelerated retirements provide the best hope for market recovery and are even throwing their weight behind more stringent environmental laws—including voluntary caps on carbon dioxide emissions.

The Longer View
RDI's forecast indicates that most US markets will have sufficient power supply to last until the later years of the decade. (See Figure 1.) But after the construction boom is over and even assuming conservative demand growth, more than 100,000 MW will have to be built to meet the forecasted electricity demand in 2014. Therefore, to avoid shortages in the latter part of this decade, new investment in power resources will be required. If capital markets are burned badly by the North American power sector today, investors may be hesitant to invest in power markets then—at least not until shortages and price spikes occur.

Clearly the attempt to turn electricity into a commodity has worked, but commoditizing a product means that the market becomes susceptible to commodity-type boom and bust pricing cycles. This presents a new challenge for power market participants. Now those companies face financial difficulties that have caused them to abandon their strategies. This raises several questions. Can strong companies expand their portfolios by gobbling up the projects of cash-starved competitors? Will this lead to market consolidation? Will new players like the major oil companies dive into power markets? If no one can pull this off, is it possible that we will revert to regulated generation markets?

These questions raise issues that will likely play out in the next five years. In the shorter term, making money on new gas-fired generation is not going to be the easy opportunity that investors saw when they turned to power markets after the high tech bubble collapse. Still, opportunities exist, and the companies with the best information about their markets are the ones most likely to succeed.

© 2008 Edison Electric Institute