The PTC, which adds a critical $0.018/kWh to the sales price of each kilowatt hour of wind power, is available to private business with a tax liability. The REPI is a similar sized incentive for non-profit owners of wind farms, such as public utilities, that are not taxed. To date, the financial viability of nearly all wind projects has been dependent on one or another of these credits.
With a timely extension of the PTC, a series of states are likely to see their generation of wind power soar. The big winners will be Washington in the Northwest, where as much as 321 MW is proposed, and California and Kansas, each with 200 MW in the pipeline. States with more than 100 MW in development for 2004 are Iowa, Maryland, Minnesota and Wisconsin. Less advanced are about another 800 MW of projects that, with a seamless PTC extension, may have made it into the pipeline -- but now that is highly unlikely.
Among the major players with projects up for 2004 are FPL Energy, which has 400 MW planned, and Navitas Energy, with 160 MW in the pipeline. They are continuing pre-construction activities, based on a belief that the PTC will be extended early enough this year to make projects feasible. Work by developers who need outside capital, but are unable to get it without the guarantee of PTC payments, could come to a standstill, however.
Enxco says the delay extending the PTC will substantially reduce what it can realistically build this year. After installing 97.5 MW in 2003, the company has 350 MW in sight for 2004, says Enxco's Steve Yatsko. But even if the PTC passed tomorrow, he said last month, "It would be hard to do all these projects this year."
Yatsko says a wind project's return on equity all comes from two tax advantages: the PTC and a clause allowing accelerated depreciation against tax of investment in new equipment; that clause expires at the end of this year. The result is a "ratcheting-up" of rates for power purchases, he says.
While most projects planned for the year already have land leases, and environmental and siting issues resolved, without a PTC in place developers are unable to order transformers and turbines or to build transmission. It takes about six months after ordering turbines to get them to the site, says Cielo Windpower's Walt Hornaday. "So, if they aren't ordered by late spring, that would push the project off to 2005," he says. Cielo has 40 MW planned, but is uncertain about 320 MW more.
For projects that are more certain, developers can hurry that timeline along by getting into the queue for equipment with turbine manufacturers, says Yatsko. The longest lead-time, however, is often for transformers and that will always slow a project.
The PTC is just one among the litter of failed initiatives in 2003. An electricity provision that largely consisted of the Federal Energy Regulatory Commission's (FERC) plan to standardise electricity markets was wrenched out of the energy bill long before it stalled, as was a renewables portfolio standard (RPS) contained in the Senate version of the legislation. Either of these initiatives would have been a boon for wind development.
The proposed new market design would have lowered the costs of integrating wind into power systems across the nation (Windpower Monthly, February 2004), while a federal RPS would have established the consistent and reliable competitive market that renewable resource developers need to build further capacity and lower project and finance costs. As it is, the nation is divided into power regions that have accepted the principles of the FERC's plan and now allow wind power fair access to the market, such as the California Independent System Operator, the Bonneville Power Administration in the Northwest and the PJM Interconnect in the East, and regions which deny fair access to wind power. On top of that division is another between states with some form of RPS, and those without.
RPS failure positive
A federal RPS would go a long way to opening up access to the entire nation's wind resource instead of just bits of it. It would also allow the wind industry to step off the PTC roller coaster. The Senate's version of the energy bill included an RPS requiring 10% of the nation's electricity to come from new renewable energy sources by 2020, but House Republicans removed it when the two bodies met to negotiate a final package.
That abrupt end to the proposed RPS was actually no bad thing, says Nancy Rader of the California Wind Energy Association, one of the principal architects of the RPS concept. She worries that the current president and Congress would have passed a faulty RPS that could have pre-empted standards in the few states that have workable laws. An RPS, when constructed properly, creates both a protected market for renewables and employs market forces to push down prices. Eventually, as prices fall to make renewables fully competitive, the regulatory protection afforded by the RPS is no longer needed.
As if the failure to win a federal RPS was not bad enough, the mechanism did not have a particularly good year at state level either. In 2002, California and Nevada adopted significant RPS rules, but no states did so in 2003, even though several legislatures took up the issue.
A problem with the piecemeal, state-by-state approach is that some states adopt standards that lack implementation mechanisms needed to make the regulation work as intended. While 15 states have some type of minimum standard for renewables, only one -- Texas -- has a properly structured RPS which uses renewable energy credits (RECs) to encourage a competitive market and ensure full compliance with the standard.
Despite the poor state record in RPS implementation, Rader is encouraged by recent action in her home state of California. The state's 20% RPS by 2017, which is still undergoing some design tweaks by state regulators, will certainly be in full swing this year. It could also be accelerated. Utilities already have projects in the ground or out for bid. A recent Massachusetts initiative also shows how an RPS can be made to work. The state says it will underwrite the price of RECs as a way to jump-start a healthy REC market (Windpower Monthly, February 2004).
Green market growth
Consumer demand for green power in the United States is on the rise, not only in the number of utility and independent green energy programs, but in a growing consumer market for tradable renewable credits (TRC), according to the National Renewable Energy Laboratory (NREL).
Although the numbers are not yet in, Blair Swezey at NREL expects that a report his group is working on will show a significant increase in the amount of wind generation specifically driven in 2003 by programs offering customers green power at a premium -- and that growth will continue at a rapid rate this year. He especially touts the sale of wind's green attributes through TRCs as a reason for this growth.
One of the reasons for the success of the Texas RPS is its use of renewable credits for tracking RPS compliance, credits which also provide an additional source of revenue for wind project owners. A similar initiative in the works this year is a West Coast-wide renewable credit market, says Rachel Shimshak of the Renewables Northwest Project. Called for by the Center for Resource Solutions, it is being discussed by the Western Governors Association and the California Energy Commission.
Can green programs, especially programs focused on wind, continue to grow at the current rapid rate without a PTC? Swezey says he is not sure. But neither is he convinced that the disappearance of the PTC -- should an extension not make it into law -- would put a stop to sales of green power. "The PTC improves the economics of wind, vis-à-vis other generation, so it is important to wind," he says. "However, I'm not sure it is a deal breaker. A utility could factor not having a PTC into the green premium and raise the price, but it's hard to say whether that would make the program less successful."