California's Power Gamble: Long-Term Contracts, Locked-In Risk

Deck: 
High profit potential will attract new power plants, forcing prices down and stranding the state's long-term electricity purchases.
Fortnightly Magazine - May 15 2001


 

High profit potential will attract new power plants, forcing prices down and stranding the state's long-term electricity purchases.

Let's consider three questions crucial to California's energy crisis and its plans for solution.

First, what is the likely long-term wholesale power price in California, and how does that price compare with the current cost to the state of signing long-term contracts to buy electricity at prices, terms and conditions common to today's overheated market?

Second, despite the many risks (retail price caps, political interference, environmental restrictions, etc.), are the current rewards great enough to entice power producers to build more power plants - enough to bring prices way down in two or three years?

Third, could it be that, given the current market, long-term power contracts are not in the best interests of the state's electricity consumers?

Overall, many factors appear at work to increase the risks of investing in new generating capacity in California, including:

  • A constrained transmission system,
  • Threats of state takeovers of assets,
  • Voter opposition to necessary rate increases,
  • Calls for re-regulation of power producers, and
  • New legislation that could change the investment landscape.

Yet California, which stands as America's number one energy consumer, ranks only 47th on a per capita consumption basis - far below almost all other states, according to the Energy Information Administration. This fact would appear to leave little additional room for conservation. And, any new plants constructed by power producers are likely to be more efficient than existing plants. Even if the energy crisis ends in California and excess capacity exists, the new plants will be operated over the older, less-efficient ones.

And consider what might happen if new investment comes on line. If that new capacity pushes prices down, that could force the state's Department of Water Resources (DWR) into default on the bonds supporting its long-term power purchase contracts. After all, the state of Washington (Washington Power Supply System) defaulted on its bonds after it was concluded that sufficient power capacity existed in the state and its partially completed plants were no longer needed. But in California, the power from the new plants would still be more competitive than existing plants. By contrast to the stranded WPPS nuclear capacity, these new California producers could still attract customers by selling their output at market prices, and collect revenues above their costs. The key factor remains that this new capacity would replace older, less-efficient production.

Thus, one can identify many countervailing factors that might service to mitigate risks for new plant investment, including:

  • An expanding economy,
  • An expanding population,
  • A shortage of generating capacity,
  • Limited room for additional conservation, and
  • An existing inventory of generation that is older, less efficient, and ripe for replacement by newer, more efficient plants.

So, let's look at the facts. What elements are in place that might affect risks and incentives for power producers in California? How would these factors affect the answers to our three questions - about prospects for power producers and the wisdom of California's plan to invest in long-term supply contracts?

Where We Stand Today

In his annual "state of the state" address, California Governor Gray Davis outlined his view of the electricity crisis. "Make no mistake," he said. "We will regain control over power that is generated in California and commit it to the public good. Never again can we allow out-of-state profiteers to hold California hostage. Never again will we allow out-of-state generators to threaten to turn off our lights with a flip of their switch."

Was Davis threatening a state takeover? His words led one power industry insider to quip, "It sounds like condemnation. That's unrealistic."

Regardless, that is exactly what Davis says he is prepared to do.

"If I have to use the power of eminent domain to prevent generators from driving consumers into the dark and our utilities into bankruptcy, then that's exactly what I will do," says the Governor. Davis wants energy companies and California consumers to know that as governor of the Golden State, he holds the power - and is prepared to use it - to make certain that customers aren't left in the dark, even if that means repossessing the state's generating plants.

That strategy began to take shape on Feb. 1. That's when Gov. Davis signed new legislation into law (Assembly Bill 1-X), granting authority to the California Department of Water Resources (DWR) to issue bonds in amounts up to $10 billion, to enable the state to negotiate long-term contracts to buy power and then sell it to users at cost (plus expenses for transmission, delivery and administration).

Later, on March 5, the Governor announced that the DWR had obtained a portfolio of 40 long-term contracts with power generators, based on bids received from an Internet auction held on Jan. 23. The 40 contracts together would supply an average of 8,886 megawatts (MW) of power per year over the next 10 years, at an average price of $69 per megawatt-hour (MWh). The price came in a bit higher than the $65 figure the Governor had said he wanted, but well below the $200 to $500 prices paid this past winter in the spot market. However, the 40 contracts average out at $79/MWh for the first five years. (At the same time, the Governor announced that the DWR had signed 11 short-term contracts, slashing the DWR's average cost of short-term power purchases for the month of February from $330/MWh to $228 per MWh.)

Earlier, the Governor had unveiled several new initiatives to boost power generation throughout the state, including a crash program to alleviate energy shortages predicted for this summer by allowing "peaking" power plants to run longer hours. These smaller, less efficient facilities - which are used during power shortages to avoid rolling blackouts - will be allowed to pollute more in exchange for offsetting pollution elsewhere. Under the plan, if a peaking plant exceeds its imposed pollution limit, it will pay a mitigation fee to help clean up facilities or other mobile sources. For example, if a peaking plant expels more emissions than allowed, it would pay a fee that could be used to install a new, cleaner engine for a 30-year diesel school bus. In the end, California ends up with the same amount of pollution.

Nevertheless, the state's fast-track plan to add badly needed megawatts to California's power-starved grid by this summer's peak-demand season may be slowed by a shortage of generating turbines. Many of the California plants also need construction permits and have to build connecting lines to the power transmission grid and the natural gas pipelines needed to fuel the plants. So many plants are under construction around the country that there is often a long wait for delivery of the turbines, compressors and other crucial components of a power plant.

In fact, as this article went to press, the construction of certain small peaking power plants - capable of supplying 1 million homes - was stalled because of a dispute between state officials and the plant builders. It is true that Governor Davis ordered state Energy Commission regulators to roll out the red carpet for anybody willing to quickly build the small, sometimes temporary peakers needed to help the state get through next summer without blackouts. Yet plans for 29 such plants, which have been in the works since last fall, have been slowed by the state, according to the companies hired to build the plants. The problem, they say, is that the DWR, which was pushed into the electricity business on an emergency basis, is trying to amend the contracts. State officials say the original contracts gave too much to the plant builders, and DWR wants to save the taxpayers money by revising the terms. But it is likely that the governor will eventually prevail on this issue.

Transmission, the last piece to the puzzle, started to come into focus early last month. On April 9, the DWR signed a memorandum of understanding with Southern California Edison Co. and its parent company Edison International, forging a deal for the state to buy Edison's electric transmission grid for $2.76 billion. That agreement would also require Edison to sell cheap power from its retained power plant fleet on a cost-of-service basis through 2010. Of course, Edison does not have enough capacity to set the market price. Also, their plants are old, and not as efficient as new ones.

With the signing of the deal with Edison, and the Chapter 11 filing by Pacific Gas & Electric Co. (putting decisions in the hands of the federal bankruptcy judge), it remains to be seen whether the state will succeed in acquiring the transmission assets of PG&E and San Diego Gas & Electric Co. In fact, according to Paul Patterson, an analyst with Credit Suisse First Boston, the governor's most difficult task in a transmission takeover would be to persuade the legislature to sign off.

He stated that even if the Governor's plans are implemented, California will still be the screwiest, most-restrictive electricity market in the country. Independent power producers will have no easier time getting siting plans past local political activists than the current incumbents have now.

"He has talked about a lot of short-term measures to alleviate problems for this summer, but he hasn't communicated a long-term fix," said Lawrence J. Makovich, senior director of Cambridge Energy Research Associates. Makovich said Davis has to reform the market to encourage power providers to make necessary investments in California. California's greatest impediment to fixing its power problems is tough environmental standards and other regulatory hurdles that make it "very difficult and expensive to build power plants in California," he said. Maybe so, but market prices for the power will reflect these impediments.

Risk and Reward for Power Producers

Many claim that power makers are reaping extra high profits in today's California power market. Is that really true? What is the logical return on equity for a typical power plant investment in California?

Consider Table 1. It shows the average return on equity earned over the last five years by seven major power producers: Dynegy, Williams, CMS Energy Corp., Duke Energy Corp., AES Corp., Calpine Corp., and Reliant Energy.

The five-year average return on equity for these major energy companies ranges from 12.1 to 20.86 percent. It is likely that, given the negative risk factors listed above, projects in California might require returns at the higher end of the range, if not beyond.

Nevertheless, the various mitigating risk factors also discussed here might provide some offset. In fact, an argument could be made that generation investments in California are less risky than the financial markets as a whole. Following this line of reasoning, an investor in the California market should earn no more than the returns posted by various common financial market indices in recent years. These indices are shown in Table 2.

The range of the 10 indices shown in Table 2 is from 15.83 to 21.12 percent over a period of 15 years. High-tech stocks dominate the high end of the range. The Wilshire 5000, representing the total market, is at 16.64 percent. The range of the 10 indices shown in Table 2 is from 15.18 to 34.76 percent over a period of 5 years. Therefore, a generous return to a relatively less risky investment as evidenced by the California power market would result in a rate of return on equity of about 16 to 18 percent.

We could leave the question right here, and let the economists continue to debate with each other. In the alternative, however, we could try to crunch some numbers, and see what they say.

First, let's make some assumptions for typical new investment in generating capacity:

Plant Type - Combined-cycle turbine
Fuel - Natural gas
Avg. capacity cost - $600,000 per MW
Avg. heat rate - 7000 Btu per kWh
Annual capacity factor - 50%
Cost of pollution credits - $8 per MWh
Annual O&M cost - $10.00 per MWh

Table 3 shows the fuel-specific operating cost ($/MWh) for the new plant, depending on the plant heat rate, and based on different wholesale natural gas prices at the California border. (Fuel cost equals gas price times heat rate divided by 1,000.) With the fuel cost in hand, we can then determine return on equity for a typical plant, and how it varies with the gas price and the debt-equity ratio (percentage of equity included in capital structure), given a particular heat rate and a certain prevailing wholesale market price.

In the base case in Table 4, illustrating a plant with a heat rate of 7000 Btu/kWh, plus a market price for power of $250/MWh, we can see that return on equity for a 50-50 debt-equity ratio runs anywhere from 24 to 280 percent, for natural gas prices ranging from as high $30 per MMBtu down to $5 per MMBtu. For a more highly leveraged capital structure, with 25 percent equity and 75 percent debt, the returns run even higher. We could perform the same calculations for different wholesale power prices and plants with different heat rates. For instance, for the same plant (heat rate = 7000), but a higher power price ($450/MWh), returns on equity (50-50 capital ratio) would run 316 percent to 572 percent, over the same range of natural gas cost figures.

By contrast, a less-efficient plant placed in service years ago (heat rate = 11,000) would earn returns on equity (50-50 capital ratio) running from 141 percent to 542 percent, at a high power price of $450/MWh. However, at a lower power price of $250/MWh, that same older, inefficient plant would still earn returns on equity (50-50 capital ratio) as high as 250 percent, 170 percent, and 190 percent, respectively, at gas prices of $5.00, $10.00, and $15.00 per MMBtu. Returns for this older plant would fall in the negative range only as gas prices grew higher than $20 per MMBtu. (This older plant would record a negative 151 percent return on equity, at a 50-50 capital ratio, at a gas price of $30 per MMBtu.)

The Profitable Conclusion

These examples show that existing power-generating investments are more than sufficiently profitable, even at relatively high heat rates and relatively high natural gas prices. Only when the price of natural gas reaches astronomical levels, coupled to relatively high heat rates and moderating prices for electricity, does the profitability picture change.

These results lead one to conclude that investment will be attracted to California in spite of the state's inherent risks. In fact, they indicate that environmental constraints and/or local opposition to power plant siting are the only serious impediments to new power plant construction in California.

In short, prices for wholesale electric power will likely come down when sufficient additional capacity is built and natural gas prices return to historical levels. A long-term power price of $70/MWh, appearing in three years or so, would be a reasonably generous estimate.

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