Turning Up the Heat on Energy Policy

By Published On: July 31, 2004

<i>An earlier version of this article appeared in </i>California Journal<i> magazine in July, 2004.</i> Jim Detmers breaks into a sweat in the air-conditioned control room. The California Independent System Operator’s vice president is watching the morning weather report. For the fourth day in a row, it’s over 100 degrees in the Valley. At 8 a.m., every operable power plant is standing by on “spinning reserve” to feed power into the state’s grid of transmission lines, if necessary. By 4 p.m. Detmer’s staff makes a call, allowing hydroelectric power from out of state flowed into the state’s transmission system, and tapping all the reserves the grid operator can muster, the state narrowly avoids another blackout. This summer, that scenario could be all too common. Since January, demand for electricity this year alone is up 6.6 percent as of June, according to the grid operator. The California Independent System Operator (CAISO), which manages the flow of electricity on California’s 25,000-mile transmission system, has already marked peak demand on the grid this summer to be more than the highest consumption during energy crisis blackouts. “It’s a rosary bead summer.” That’s how Pat Wood, the Federal Energy Regulatory Commission’s chair, termed this summer’s prospects potential blackouts in California. Given the lack of new power supplies, increasing demand, decreasing conservation and a dearth of transmission line construction, California’s energy salvation could require some prayer. Back in May, CAISO was already warning that California’s sources of hydroelectricity may run low due to unusually dry conditions and a lower-than-usual snow pack. It urged all California consumers to practice conservation in order to “keep the power flowing” this summer. Detmers, a veteran of the energy crisis, knows that as the specter of rolling blackouts looms this summer, a couple major new power plants won’t be coming on line for two more years. Even then, two new plants aren’t reassuring when it comes to adequate supplies on hot summer days. “Sixty thousand megawatts of new electric supplies will be needed to power California’s economy in 2030,” according to a report commissioned by the California Energy Commission. That’s about 100 new power plants. “That report scared the bejeebers out of me,” said Rich Ferguson, Center for Energy Efficiency & Renewable Technologies research director. “If we leave it up to the transmission planners, we’re going to end up with a black future of coal-fired electricity.” Devising a comprehensive plan for the state’s energy future was put on hold eight years ago in favor of “let the market decide.” The market decided–it went on an all-expenses-paid-by-the-state spree during the energy crisis. The hold button is still flashing. With current inertia, California is likely to be mired in an energy future that uses increasing amounts of coal-produced electricity, liquefied natural gas imports from countries like Bolivia, and reliance on aging nuclear plants. That haphazard future?one that spells more pollution, greater dependency on foreign fossil supplies, and increased risk of accidents, including the “kaboom!” factor for LNG terminals and radiation leaks for 30-year-old nukes?could be avoided with pioneering policy and investments, acccording to Ferguson and others looking at state energy policy. In the end, both futures will probably cost about the same?although no one has attempted credible estimates of the costs. On the state’s current path, which relies primarily on fossil fuels, the long-term pollution and health costs mount stealthily, like the balloon on a credit card bill that’s never paid off. With the alternate?an emphasis on heavy investment in conservation and renewable energy?the biggest costs are upfront, while presumably avoiding the long-term price tag of environmental damage and health risks. Former Governor Gray Davis made headlines when he accelerated the state’s power plant approval process during the 2000-2001 energy crisis. An unprecedented 8,300 megawatts of new power plants were built during that time. These are the power plants that energy deregulation envisioned?private developers risking their own capital to build facilities, rather than having utilities risk ratepayers’ money to build plants. In 2004, it doesn’t matter much that California’s made it easier to approve plants because risk averse bankers aren’t financing new power plant construction. The money that flowed into power plants when the onset of deregulation promised profitability, vanished in the last two years as power plant owners were either forced into contracts with Department of Water Resources or the more volatile spot market. DWR contracts weren’t a bad trade for risk, but they are no longer available to assuage banker’s fears. In the last two years, that private capital risk caused 6,500 megawatts worth of power plants that have been approved are in limbo because there’s no financing. “In the next ten years, we won’t get lenders to loan until the market risk is taken away,” said Jeff Bodington of Bodington & Co., an energy developer consulting firm. Bankers aren’t the only ones who want to avoid risks. Decades before deregulation, regulators constantly questioned utilities over the prudence of spending ratepayer funds to build new plants. Regulators saw enormous cost escalation in utilities’ new power plant costs. That, in part, led to the belief that private developers could do the job at more competitive prices, and helped motivate deregulation. Although private power plant owners have been accused of being greedy, regulated utilities have their own history?making it politically dicey to choose one over the other, or crafting a more complicated mix. For instance, when expensive nuclear plants were introduced, utilities discovered that they could get them approved under cost-of-service ratemaking (a guaranteed rate of return?interest?paid for by ratepayers). Simply put, the bigger the investment, the bigger the payback to shareholders over time. Instead of spending tens of millions in those days?1950s and 60s?utilities discovered they could invests hundreds of millions, and eventually billions, and get the same rate of return. Ten percent interest on $1 billion beats 10 percent interest on $10 million. Pacific Gas & Electric’s Diablo Canyon was initially estimated at $320 million in the late 1960s, according to the Abalone Alliance. Its completed cost was $5.5 billion, but with subsidies and return on investment, its cost to ratepayers ran over $28 billion. Utilities are eager to build new power plants. Already this year, Southern California Edison received approval for the large Mountainview gas-fired power plant in San Bernardino County through an arrangement between an Edison affiliate that will own the plant, in turn contracting its output to the utility. San Diego Gas & Electric was able to buy the Palomar plant in Esocondido from its unregulated sister company and own it directly, with the repayment funds flowing from ratepayers. PG&E in mid-July, proposed that it wants to own and operate power plants that are built by others. Meanwhile, Governor Schwarzenegger made halfhearted steps into this energy policy predicament this spring. He expressed interest in establishing a 15 percent energy reserve?thus giving a cushion of extra power when demand is high and supplies low. He also indicated an interest in renewable energy sources, seeking an accelerated goal of 20 percent of electricity generated by renewables by 2010. And he wants to create a market for private investors to develop new energy-producing facilities. In a recent interview with <i>California Journal</i>, Schwarzenegger expressed concern over the threat of another energy crisis in California and said one of his next priorities is energy policy. But so far, there’s been little seen or heard of the details. Joe Desmond, Schwarzenegger’s appointee as deputy energy secretary at the state Resources Agency, promises more energy leadership. The former chief executive officer of Infotility says the first thing on the agenda is to provide power plant reserves. To accomplish that, he finds some common ground between the commission’s plans and the governor’s. Desmond has a range of possibilities, but no one answer. “We need to be careful to avoid one extreme or the other?the wholesale spot market or long-term contracts” for reserve power, Desmond said. Desmond is pitching a plan to open a new “market” for excess megawatts to serve the need for reserves, as well as the medium-term policy of engaging new megawatts from new construction. He includes in the potential new market a form of extreme conservation, called “demand-response.” For instance, an entire string of manufacturing facilities would promise to suddenly stop consuming electricity in return for payment through the new market. Direct access was a part of the original deregulation law, but was cut off after utilities sunk into steep financial declines. In the currently considered version of direct access, large, “noncore” utility customers could choose suppliers other than utilities. Large consumers want direct access because they believe they can contract for better power prices than what’s available from utilities. Even if the CPUC were able to get more power plants built by addressing bankers’ risk issues, new power plants are only half the story. Transmission lines to carry electrons from where they’re produced to where they’re needed are a more politically sensitive, expensive, and long-term problem than building new power plants. Thre years ago, a 500 kV transmisison line was proposed in the San Diego region to bring electricity from neighboring power plants in Mexico and Arizona, as well as wind power generated in the Tehachapis. But the project was denied state approval after enormous local homeowner opposition focused on the “ugly” towers needed to string wires across the landscape, along with disputes over placing the towers on nearby sovereign tribal land or getting a federal waiver to run it through a national wilderness. Meanwhile, the potential for summer blackouts remains. And with no clear direction yet from the Legislature and the governor, the state’s energy picture is as cloudy as ever. Desmond doesn’t think the state itself has to invest in renewable energy, only facilitate its delivery. He emphasizes fuel diversity?including renewable sources, but not ruling out coal and LNG. “We have to take an integrated view.” Taking an integrated view, however, won’t help prevent blackouts this summer and it won’t prevent a future of continued dependence on fossil fuel, including coal, as well as nuclear, to fuel electricity. The state mandate for 20 percent renewable energy in 2017 is a start, but it’s not enough to change the state’s energy and environmental future. Getting through the summer without blackouts is likely to test political acumen. Obtaining not only a reliable energy future?as well as a desirable one?will take more than acumen. It will take vision and risk.

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