IOUs take action, but other overriding forces will affect prices in the near term.
It's going to be a wild summer for the Western Electricity Coordinating Council (WECC), courtesy of higher than forecasted load growth, high gas prices, delays and cancellations of renewable resources, and lower than normal hydro generation. These conditions will drive faster than expected market recovery in the West (especially for merchant generators) and will increase the price volatility exposure of the municipal and investor-owned utilities that rely upon the markets to meet load.
Any comeback requires a strong start, and the West got its start from above-average load growth. Aluminum smelter loads in the WECC likely are gone for good, but utility peak load grew 5 percent and energy sales grew 4 percent from 2002 to 2003. Many Western utilities have published new load forecasts representing higher than formerly predicted growth. The California ISO load through the end of May 2004 is up nearly 6 percent over the first 5 months of 2003. While some utilities are bullish on load growth, we see loads increasing by nearly 2.5 percent over the forecast of 6 months ago.
Natural gas prices also have continued to do their part in driving higher market prices in the West, remaining significantly above long-term sustainable levels during the last six months. The fundamentals don't fully support these high prices because natural gas storage in the West has caught up with storage levels from a year ago. However, as shown in Figure 1, fear of a return to historically low gas storage levels and efforts to avoid market exposure appear to be driving buyers to pay high prices.
In the long run, new production and liquefied natural gas facilities are expected to drive natural gas prices back down to the $3.50 to $4.00/MMBtu range. But over the next 3 years, we expect to see a $0.50/MMBtu premium on gas. While high natural gas prices are not normally seen as a positive thing for market participants' profits, many participants are operating high-efficiency, combined-cycle units with heat rates between 7,000 Btu/kWh and 8,000 Btu/kWh. The average implied daily heat rate in the West is nearly 8,800 Btu/kWh (see Figure 2), allowing a new combined-cycle turbine running at full load to take home 20 to 25 percent more profit from every fuel dollar spent.
Since January 2000, developers have committed to building nearly 6,000 MW of wind capacity in the West. To date only 1,200 MW of this capacity has been built, and an additional 1,400 MW has been abandoned. The rest is in various states of completion (see Figure 3). Some development faces significant permitting and economic hurdles, while other development is on hold because of the failure of Congress to renew the tax credits for these resources. It now looks unlikely that the renewable targets set by some states and utilities will be met.
Strangely enough, despite oversupply in Western markets, an additional 13,800 MW of new capacity was built between January 2003 and the end of May 2004. The West will go from its period of tight supply in 2000 to nearly 30 percent reserve margins by August. However, we don't expect this new capacity to further depress power prices because many of the new plant projects are being built by municipal utilities that want to ensure more reliable supply for their customers. As a result, much of this new generation is unlikely to be sold in the wholesale market.
IOUs Take Action
Investor-owned utilities are starting to get in on the action as well. Recently completed resource plans show several Western utilities building their own capacity. These projects are being justified by building in the right place in relation to transmission constraints, or by building more fuel diversity into their portfolio. These projects are likely to affect the market price on a long-term basis, but they will take several years to complete.
Variations in precipitation can have a significant impact on power markets in the WECC. In its long-term WECC planning forecast published in April 2004, Henwood assumed normal hydro conditions in all periods, starting in October 2004, based on average hydro generation from precipitation that occurred during the 1929 to 1978 historical period. For the period March 2004 through September 2004, the forecast also assumed that Pacific Northwest hydro would be at 92 percent of normal levels, and Northern California hydro would be at 109 percent of normal. Since April, recent runoff forecasts for the Pacific Northwest indicate that actual expected runoff will be lower. As of May 21, 2004, the runoff forecast has dropped to 74 percent of normal.
But hydro conditions are highly variable. While these lower hydro conditions can have upward pressure on prices, the impact is not expected to be as great this year as in 2000-2001, mostly as a result of the additional capacity that has been added since then. However because much of the capacity that has been added is gas-fired, power prices will be susceptible to higher gas prices. Overall, we could easily see higher prices in the Pacific Northwest-caused more by high gas prices than low hydro conditions.
Signs of Life
The WECC wholesale power markets appear to be emerging from their time in the wilderness. Signs of a lively market in the form of rising loads, high gas prices, delayed renewable energy projects, and a tight year for hydro collectively create better conditions for merchant generators. The new capacity brought on line in 2003 and 2004 likely will not drive down market prices but may well provide a measure of reliability to the market, possibly counteracting some of the usual price volatility seen in low hydro years. This is good news for the wholesale power business, and it signals that the industry is beginning to claw its way back from the near-death experience of the past few years.
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