WINDPOWER:
Beyond Boom and Bust
Windpower is caught
in a vicious cycle of
Washington politics.
Escaping the cycle
will require visionary
leadership in Congress
and the utility
industry.
May 2005
By Michael T. Burr
Windpower has come a long way in the past decade. Ten years ago, utility planners were hesitant about adding windpower to their systems. They weren't convinced wind machines were ready for prime-time utility applications, given their high cost, low efficiency, and poor reliability.
Today, utility perspectives on windpower have changed dramatically. "People used to say, 'The machines don't work.' They don't say that anymore," says Robert Kahn, a wind energy consultant based in Mercer Island, Wash. "Now they say, 'The power is intermittent.' And that's a stage-two question."
Technology development has made wind turbines more efficient and durable, and large-scale manufacturing has driven costs down. Consequently, in the right conditions a kilowatt-hour of windpower can compete favorably against a kilowatt-hour of fossil generation. Moreover, turbine performance is supported by such blue-chip manufacturers as General Electric, Mitsubishi, and Siemens-which is especially helpful for utility executives facing skeptical directors and commissioners.
Given these advances, policymakers today view windpower more favorably than they have in the past. More than 20 states have adopted renewable portfolio standards (RPS) that set targets for wind and other renewable resources, and the Federal Energy Regulatory Commission (FERC) recently proposed new transmission rules to help wind farms access transmission resources cost-effectively.
"There's a lot of political and regulatory goodwill behind wind right now," says Mike O'Sullivan, senior vice president of development for FPL Energy in Juno Beach, Fla. "It has a lot of supporters across both sides of the aisle in Congress, and at the same time many states are grabbing onto windpower as a public-policy initiative."
Where regulators go, utilities generally follow. And indeed some utilities are investing in windpower-through unregulated affiliates, and in some cases directly via their own franchises. Most notably, Puget Sound Energy (PSE) is investing $200 million to build a 150-MW wind farm in the state of Washington, and has issued a letter of intent to acquire another 230-MW project.
Such developments, combined with a slew of independent projects and transactions announced recently, indicate the windpower "buzz" is growing in the U.S. power industry. This buzz is amplified by rising concerns over fuel prices and energy security vulnerabilities, as well as recent trends toward restrictions on greenhouse gases.
Even Wall Street hears the buzz; investment bank Goldman Sachs agreed in March to acquire wind developer Zilkha Renewable Energy for undisclosed terms. "There is a widespread consensus among those at the firm who focus on the energy sector that wind is one renewable source whose time has come," says Neil Auerbach, managing director with Goldman Sachs in New York. "We think there is an opportunity here, and a profitable one at that."
However, the growing volume of the windpower buzz belies the paltry role windpower actually plays in the U.S. power market, and its sluggish growth compared to Europe and other parts of the world. Smaller countries dwarf the United States in terms of both installed capacity and rate of new additions.
So why is windpower accelerating steadily in many other countries, while it stumbles along here in fits and starts? The answer is multifaceted, but it boils down to two fundamental factors.
First, the wholesale power industry is a freer market in the United States than in most countries. Net cost is the dominant consideration when making fuel choices. Only when the social values and costs of various resources are included in the power-planning calculus can wind farms compete against traditional fossil-fired plants.
Second, the primary mechanism for recognizing those social values, the federal renewable production tax credit (PTC), is subject to the political whims of a fickle Congress. Legislators have extended the credit for only two years at a time, and repeatedly allowed it to expire without renewal.
This combination of factors has hobbled the U.S. windpower industry, and prevented wind from joining the mainstream of utility resource planning.
"For a long time we have advocated the need for a long-term national energy strategy," says David Sparby, vice president of government and regulatory affairs for Xcel Energy in Minneapolis. "The lack of a long-term strategy has resulted in a boom-bust cycle, not just for wind but also for other sources of power generation. This is the worst outcome we could imagine."
A long-term PTC by itself, however, will not eliminate the obstacles that prevent windpower from becoming a "standard" power-generation technology. Transmission constraints, in particular, pose tricky problems-both technical and regulatory (see "Wind, Wires & Coal," p. 34). And in the long term, tax credits and quotas are not a particularly efficient way to account for external values; a more robust, free-market approach would better serve the U.S. power market.
Resolving these issues will not be easy, even if the windpower buzz grows deafening.
Windy Over There
Despite being the largest power market in the world, the United States has only the third-largest amount of windpower capacity (6,740 MW at the end of 2004), behind Germany (16,629 MW) and Spain (8,263 MW). Furthermore, U.S. windpower growth last year was downright anemic. According to figures from the World Wind Energy Association, the U.S. wind industry grew at just under 6 percent in 2004, compared to the five-year global average of 28.4 percent.
Of course, the reason wind went nowhere in 2004 was the PTC had expired without renewal in 2003, and development plans were shelved until Congress renewed the PTC in September 2004. But that renewal only extended the credit 15 months; it expires at the end of 2005, and thus developers are frantically trying to plant wind farms before the credit expires again.
"As long as we have the PTC coming and going every year or two, there will be tremendous volatility and instability," says David Eves, vice president of resource planning and acquisition for Xcel Energy. "That creates tremendous problems for us, in terms of planning and lead times required to develop the transmission and interconnect those facilities."
While current indicators suggest the PTC will be renewed again, investors and manufacturers cannot predict when that might happen or under what terms. "Extension of the credit does not move on its own," says Randall Swisher, executive director of the American Wind Energy Association (AWEA) in Washington, D.C. "It moves as part of a more complicated vehicle, whether it's an energy bill or a tax bill. That's where things get difficult."
In the face of inconsistent and unpredictable policies, windpower has been unable to sustain its momentum in the United States. If utilities cannot plan for windpower, then projects remain in limbo, and manufacturers will not invest in manufacturing and marketing infrastructure to serve the U.S. market. "Windpower is a real business in the United States, and $2 billion worth of turbines will be put into the United States this year," says Paul Gipe, a longtime wind-industry consultant and gadfly, based in Tehachapi, Calif. "There will be a lot of chest thumping, but the people that were hired this year will be fired next year when the bottom falls out of the market."
Clearly this is no way to run a railroad-or a power industry. Whether a better way exists, however, is a difficult question.
In many countries-including, most notably, Germany, Spain, Denmark, France, and likely China in the near future-lawmakers have established a more direct way to support renewable power projects. Specifically, utilities are required to buy renewable generation at a predetermined rate that varies depending on the cost of the resource and the value lawmakers ascribe to it. This is known as the "German model," a "feed-in tariff," or a standard-offer contract.
This model works in those countries because political trends support giving a strong and direct subsidy to preferred technologies, based on environmental performance, use of domestic energy resources and other factors. The details of this approach vary by jurisdiction, but they all have one thing in common: They establish a higher rate for power sourced from renewable facilities, and they recompense load-serving utilities for the higher cost of that power.
"This has rocketed the development of renewable energy, particularly windpower, in Germany, Spain, Denmark, and also France," Gipe says. Further, the Chinese government passed a feed-in tariff law in March, which could position China to take the lead in windpower over the coming years and decades.
"Of course China wants to develop a manufacturing sector and sell turbines to us and everyone else," Gipe says. "The best way to do that is with a feed-in law that lets their own market know what it will be paid. If China does it right, they will have a windpower industry that is hell-bent for leather."
These trends are causing some analysts to wonder whether the United States should consider pursuing a similar approach. But with the exception of California's standard-offer contracts in the 1980s, the idea of feed-in tariffs has met a chilly reception in the United States, largely because the idea of allowing the government to set prices is antithetical to the American free-market paradigm, even though the utility ratemaking process effectively does just that.
"Don't make believe we have a free market in electricity," says Michael Eckhart, president of the American Council on Renewable Energy (ACORE). "It is a regulated market, and regulators need to create solutions for renewable energy just as they did for nuclear power when it was first commercialized. These are new variables, but there's no reason to change the methodology."
Politically, however, tax credits and other types of incentives have better prospects. "At the federal level, it seems easier to deal with tax policy than with a more direct pricing mechanism," says Ed Feo, a partner with Milbank, Tweed, Hadley & McCloy in Los Angeles.
Given this political reality, few wind supporters are lobbying for a feed-in tariff.
"A European-style tariff is unworkable in the U.S. political system," says O'Sullivan of FPL. "In Germany, they've made a political and regulatory decision to incentivize wind."
This decision, moreover, hasn't always resulted in the best resource decisions, O'Sullivan says. "Although there is a lot of new wind being developed, it is very high-priced. In Germany some projects get a 10-cent tariff. If we had that here, there would be wind turbines all over the place."
The problem is that wind turbines are efficient only in places with strong and steady winds. Feed-in tariffs support projects sited in poor wind-resource areas, and thus much of the windpower capacity built to capture a feed-in tariff is less productive than it would be under a more free-market system.
"The technology is fine, but it has a 15 to 22 percent capacity factor," O'Sullivan says. "Germany doesn't have many large wind projects. They are scattered all over the country. But in this country we see a 40 percent capacity factor, because we have competitive projects that make sense."
Incentives American Style
While the possibility of a federal feed-in tariff seems remote, similar incentives are emerging at the state level. In fact, standard-offer contracts could return to California if political winds continue blowing in their current direction.
California's Austrian-born governor, Arnold Schwarzenegger, has strongly supported renewable energy incentives in the state. In March, Schwarzenegger met with the German M.P. who authored the country's feed-in tariff, Hermann Scheer. At the same time, Schwarzenegger resurrected legislation defeated in 2004 that was aimed at installing photovoltaic modules on 1 million California roofs, modeled after Germany's "100,000 roofs" program.
Time will tell whether the "Governator" might similarly propose a feed-in tariff to spur wholesale development of renewable power. In the meantime, however, California already has the most aggressive RPS program in the country, envisioning 20 percent of the state's electricity being generated from renewable sources by 2020.
Fully 21 states now have adopted RPS or similar structures that set targets and incentives for windpower and other renewable developments. Many of these programs have proved highly successful: The Texas PUC, for example, recently announced it expects the state to achieve its goal of adding 2,000 MW of renewable energy by 2006, which is three years early.
Other state programs have been less successful, generally because their mandates have not been as strong. Nevertheless, industry analysts consider RPS programs to be just as important as the federal PTC, and the growing list of states adopting RPS schemes lends credibility to the concept.
"Because the PTC comes and goes, the real driver behind the business is not the PTC, but the renewable portfolio standard," Feo says. "An RPS is a subtle feed-in tariff. In effect it says the price will be the best we can get to meet the goal for a given technology, and as a policy matter we are willing to pay a higher price for that technology."
An RPS can be viewed as a demand-side incentive, versus the supply-side PTC. This distinction is important, because it suggests a combination approach for incentives could spur windpower forward in the United States. "Looking where wind has developed the fastest, it has been where states have created demand-side credits or penalties on the side of the offtakers," says Auerbach of Goldman Sachs. "Many states are saying we need both a state RPS policy and a federal PTC. They coalesce to make windpower more attractive."
How long such incentives must be in place, however, is an open question. Current legislation envisions a five-year extension of the federal PTC, and wind advocates are lobbying for extensions of 10 years or more. At some point, however, the economic and regulatory situation will change, and such programs might become obsolete.
"Eventually the ratemaking apparatus would take over the job, once we can monetize the benefits and determine what we are willing to pay," Eckhart says. "We are still in the phase where we don't know how to price renewable energy attributes."
However, as regulators and utilities implement RPS and integrated resource planning (IRP) programs, they are steadily gaining knowledge about key factors, such as fuel-price and environmental risks, and are developing new ways to assess the risks and account for them in the supply planning process. "Major utilities are becoming increasingly sophisticated in their ability to evaluate risks," says Ryan Wiser, a scientist with Lawrence Berkeley Laboratories in Berkeley, Calif. "Two risks frequently highlighted in utility IRPs are natural gas price risk and future carbon regulation. An increasing number of utilities already are valuing windpower on its risk-mitigation characteristics."
In hopes of helping the industry in its transition to an even more sophisticated approach to valuing resource options, ACORE recently formed a committee to begin the process of planning a national "green-tag" trading market for renewable energy credits. Such a mechanism would allow market forces to work in establishing prices for the external values involved in renewable energy. "We are trying to make this work before the state rules get so entrenched they can't compromise,"
Eckhart says. "We are looking for national solutions that would bring all the state rules into harmony, so there can be a national market."
Such harmonization would help wind take major strides into the power-generation mainstream. But even then, electric utilities still might be less than enthusiastic about integrating windpower into their resource plans, for two primary reasons. First is the transmission-planning and interconnection problem that FERC and regional transmission organizations are working to resolve (see "Wind, Wires & Coal," p. 34). Second is the fact that investor-owned utilities are prevented from earning a return on windpower investments commensurate with the risks and costs of developing the resource.
"If an independent developer builds a project that is financed largely on the credit of his contract with us, he benefits from returns under a framework that isn't available to us," says Sparby of Xcel Energy. "The impact is there are fewer potential investors to develop wind, with the playing field being tilted away from utilities."
This problem is not unique to windpower, but it is exacerbated by the unique challenges that wind presents to a utility.
"The best a utility purchasing windpower under long-term contract can hope for is to break even," Wiser says. "Not only do utilities have the fundamental desire to build rather than buy, but wind also represents a maturing technology with which many utilities don't have a lot of experience. Is it any surprise they are resistant?"
Wiser suggests the power industry must address this dilemma before utilities can be expected to truly embrace windpower. "We have to figure out how to provide an incentive for utilities, not just a stick," he says. "We are in the very early phases of considering that."
Specifically, two states, Colorado and Hawaii, have included language in their RPS laws that direct the state PUC to establish a profit-making incentive for utilities. Such regulatory initiatives are nascent and untested, but they represent first steps toward engaging utilities in the wind-development effort rather than dictating the effort to them. With utilities on board, windpower would stand a better chance of becoming a flagship power-generation technology.
However, until such policies become an established part of the ratemaking process, the destiny of windpower will remain largely in the hands of a fractured U.S. Congress and exemplified by a patchwork of disparate state policies.
If political will fails, windpower likely will continue the on-again, off-again growth pattern it has exhibited in the past several years, and its contributions will remain marginal. But if lawmakers can form a consensus long enough to set forth a clear vision for renewables in America, the windpower industry might finally overcome the boom-bust cycle and emerge as a vital and vibrant utility resource.
Michael T. Burr is Fortnightly's editor-at-large, and is an analyst based in Minnesota. E-mail him at info@mtburr.com.
Wind, Wires & Coal
Many of America's strongest and steadiest winds blow in places like North Dakota, Montana, and Wyoming, far from load centers that need the power. This is a major problem, because securing transmission capacity to remote areas can cost more than the wind farms themselves.
"It's not a problem if you have windpower in the service territory of the utility using the output," says Bill Pascoe, president of Pascoe Energy Consulting in Butte, Mont., a former senior vice president with Montana Power, and chairman of the Western Electricity Coordinating Committee (WECC). But in the West, where no RTO yet exists, transmitting windpower likely means crossing several utility territories, with pancaked rates for each.
Furthermore, even in the windiest areas the wind is intermittent, which inflates the cost of transmission service. If a wind farm requires firm-transmission rights, then it will pay for that capacity whether the wind is blowing or not. "We haven't come up with a good solution for that in the West," Pascoe says.
Policymakers and utilities are working on the dilemma, however. The Western Governors' Association, for example, has commissioned several studies to evaluate transmission needs and the "seams" problem. And in January, FERC proposed a set of procedures (Order No. 2003-A) for interconnecting windpower on a non-discriminatory basis.
These developments are important, but they don't resolve the most fundamental transmission issue for many projects-i.e., the cost of building long transmission facilities to reach remote wind sites. A solution, however, might be emerging from an unlikely place-a deep, dark coal mine.
Strange Bedfellows
Coal mines in North Dakota, Montana, and other states offer a plentiful source of fuel for power plants, but like wind resources, these mines are located far from load centers. This common ground creates an opportunity for wind farms and coal-fired power developments to coordinate and cooperate for mutual benefit.
"Definitely there is synergy between wind and mine-mouth coal, but integration and environmental issues are still big stumbling blocks," says Roger Hamilton, a wind industry consultant, former commissioner on the Oregon Public Utilities Commission, and energy adviser to former Oregon Gov. John Kitzhaber.
Further complicating the potential synergy, the timeline for developing a coal-fired plant is much longer than for a windpower facility. This makes it difficult for project sponsors to cooperate on transmission development. Also, coal is seen as a less-than-ideal fuel to combine with wind, given the resources' diametric environmental positions, and the relative difficulty of ramping a coal plant up or down on short notice.
"For the most part, coal is less flexible operationally than natural gas," says Randall Swisher, executive director of the American Wind Energy Association. "But there certainly is a lot of interest among public officials in the West to try to meet the needs of both the coal and the wind industry."
Indeed, to address the stumbling blocks, several groups, including the Western Governors' Association, the Bonneville Power Administration and the National Renewable Energy Laboratories (NREL), have mobilized studies and projects aimed at quantifying the synergies and conflicts between coal and windpower. One such project, the 500-MW Nelson Creek lignite project proposed by Great Northern Energy and Kiewit Mining Group, showed the coal plant could dispatch its output to accommodate just 60 MW of wind generation. But other studies appear more hopeful, in one case indicating a 100-MW wind facility in Wyoming can rely on unused transmission capacity in the path to Denver, and get curtailed only 2 to 3 percent of the time.
"Wind can take advantage of the times that transmission capacity is available," Hamilton says. "But this requires utility operators to change the way they do business."
It also might require wind developers to change their thinking about coal. Given the history of rancor between the two groups, getting wind developers to work with coal companies-to share the costs of building transmission lines, for example-might prove impossible. Many environmental supporters of wind oppose building new pulverized coal-fired plants under any circumstances, even if it provides an opportunity for windpower development.
"Typically we are not marching arm-in-arm, because we represent the wind industry and they represent the coal industry," Swisher says. "There will be some synergy, but what each industry is looking for is significantly different."-M.T.B.
Articles found on this page are available to subscribers only. For more information about obtaining a username and password, please call our Customer Service Department at 1-800-368-5001.
Public
Utilities Fortnightly & Spark
