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Market Directions: 2010

Renewable energy consultant Nadav Enbar may have offered the understatement of the year when he described 2009 as “pretty messy.”

Messy, indeed. Projects were scaled back, postponed or cancelled altogether; sources of finance dried up almost overnight; demand for electricity fell; and natural gas prices remained remarkably low through much of the year playing havoc with project development economic forecasts.

“Development was slow going, particularly for large projects that required upfront capital,” said Enbar, Boulder, Colo.-based research manager for IDC Energy Insight.

Despite the mess — or perhaps because of it — two trends emerged that seem likely to drive renewable energy markets well into 2010.

Utility Involvement

First was the steadily growing utility role in the renewable energy sector. No longer “simply” off-takers through purchased power agreements with independent power providers, utilities are emerging as a significant development force. Their emergence is driven by ongoing access to capital, growing comfort in renewable technologies, an array of financial incentives and — in the case of solar photovoltaics — a drop in price that makes PV an attractive investment.

The price decline spurred at least seven utilities across the country to begin developing PV facilities for their own rate base, said Lisa Frantzis, managing director for renewable and distributed energy with Navigant Consulting. Those utilities include Southern California Edison, Pacific Gas & Electric, Public Service Electric and Gas and Duke Energy, among others. “I have never seen so much interest,” she said.

A related development is the growing use by utilities of investor equity, tax equity or pools of tax equity capital to develop projects.

“Utilities have tax burdens that are roughly six to seven times higher than what has historically been the pool for tax equity finance,” said Chris O’Brien, who heads market development efforts for thin-film silicon maker Oerlikon Solar. “Now utilities can use the credits themselves, increasing the opportunity for them to invest directly in projects,” either to include in their rate base or as a non-regulated investment.

Investor-owned utilities seem to have weathered the economic downturn better than other sectors. “The important thing was we (investor-owned utilities) were able to continue to borrow on a long-term basis” during the financial crisis, said Mark Agnew, director of financial analysis for the Edison Electric Institute, which represents many investor-owned utilities.

At the height of the financial crisis, a number of those utilities cut their capital expenditure budgets by an average of 10 percent. As the year progressed, however, many of those cuts were reversed. “We’re back on track for capex in 2009-2010 in the mid-$80 billion range,” Agnew said.

Another utility trend is that for the first time, more than half of the utilities polled by the Electric Power Research Institute said they considered themselves renewable energy project owner-operators. That factor is likely to put more downward pressure on costs as utilities work to cut costs further, said Bryan Hannegan, vice president of environment and generation at EPRI. “The days of freewheeling, ‘I’ll buy it at whatever cost’ are ending,” he said.

Government Intervention

A second major trend likely to influence the sector during 2010 is the federal government’s financial market intervention, which included some $67 billion of stimulus money, loan guarantees and grant programs for the renewables industry. Intervention actually began last autumn when Congress extended an already existing series of tax incentives and then took the step of making utilities eligible for the credits for the first time. In February after the economy fell on the floor Congress passed the American Recovery and Reinvestment Act (the “stimulus bill”). Included were a variety of loan guarantee and grant programs offered through the departments of Treasury and Energy and intended to keep money flowing for project development and new manufacturing initiatives.

“The government stimulus made up for the shortfall in private sector finance,” said Hannegan. The money helped the renewable energy industry maintain momentum it otherwise would have lost.

The federal financial aid has allowed virtually every developer to opt between receiving a production tax credit or an investment tax credit, said Energy’s Insight’s Enbar. And it also allowed developers to receive up-front grants, “which is, in some ways, the best way to get financing.”

The stimulus was critical to filling the gap to “keep companies from going belly up,” Frantzis said.

(To learn more about how one wind developer leveraged stimulus money and a novel “pre-pay” strategy to develop a 60 MW project, read The Deal, here.)

One question for 2010 is whether or not the federal stimulus money is sustainable over time. Barry Worthington, executive director of the U.S. Energy Association, offered the reminder that “what the federal government giveth, the federal government can taketh away.” He wondered whether pressures to balance the federal budget may lead Congress to retrench on some of the financial programs that benefit the renewable industry. Tighter fiscal policy, he cautioned, could eclipse interest both in climate change and the push for national renewable energy standards.

A related question is the extent to which the private financial sector reenters the renewables market. Loan conditions tightened and lenders showed little appetite for billion-dollar-plus projects during 2009. Instead, lenders favored projects in the range of $300 to $400 million earlier in the year, then as markets recovered, expanded that range to $700 million to $800 million.

Even so, lenders are showing an aversion to risk, which extends to everything from technology or manufacturer risk to site-specific risks. For example, one proposed wind energy project on a site at 8,000 feet of elevation in southeastern Nevada offered a capacity factor of around 40 percent. Despite the quality of the wind resource, sizable infrastructure requirements kept the project from obtaining finance.

“The number of projects deferred or cancelled is really sad,” said Blair Loftis, vice president and national director of alternative and renewable energy for engineering firm Kleinfelder. The company currently is involved in perhaps six wind projects, one-third the number it counted 18 months ago.

“We’re still helping wind clients, but we don’t have as many boots on the ground,” Loftis said. Instead, the company spent part of 2009 recasting itself as a developer’s agent in project planning. And it’s focusing resources on utility-scale solar, photovoltaics in particular.

“We have an enormous number of projects underway” in solar PV, most in the range of 5 MW to 40 MW, Loftis said. The projects may be relatively small, but they are scalable and thus offer long-term business prospects. “You can add 15 to 20 MW and grow them,” he said. Equally important, capital requirements are less daunting. “Instead of needing to raise $500 million to develop a sizeable wind farm, a solar PV development might cost $100 million or so and then can be scaled up over time.”

Because of this and other examples, Ed Feo wonders whether the federal loan guarantee program may eventually form the basis for the still nascent “green bank” concept. “Does it become the vehicle for federal support for renewables,?” asks the Los-Angeles-based partner in the law firm Milbank, Tweed, Hadley & McCloy LLP and co-chair of the firm’s project finance and energy practice. If yes, then perhaps the federal government could end up as a principal, or even the principal, source of finance.

Small-scale Preferred

A third trend relates to project scale and scope. Ongoing frustrations with siting, permitting and transmission access have some developers seeking the path of least resistance. That favors small, distributed projects.

This strategy is being pursued by Southern California Edison, among others, as it deploys 250 MW of rooftop-mounted solar PV across its service territory. Rather than site all that capacity in a single project, the utility is adding it in 1 and 2 MW increments. The approach aims to achieve several things.

First, it spreads capacity across the local grid, distributing benefits and drawbacks inherent in the solar resource.

Second, building on rooftops eases many of the siting and permitting headaches that accompany greenfield development. Local building codes and permits still must be followed, however.

The development focus in the solar energy sector likely will shift from “enormous solar farms in the desert to 1 to 20 MW projects co-located with substations,” said O’Brien. The approach allows for new capacity without the need for additional transmission, a third benefit to the distributed energy approach.

(Mike Taylor with the Solar Electric Power Association notes that unlike PV projects and with the exception of a project at Florida Power & Light, utilities largely have not opted to own centralized solar projects. He said this could be due to a “lingering notion of technology risk.”)

Ongoing worries about permitting and siting are leading developers to take deliberate steps to site projects close to an interconnection, said Kleinfelder’s Blair Loftis. In the West in particular, developers may prefer negotiating with multiple landowners rather than deal with the federal Bureau of Land Management where many project proposals now are logjammed. Too few staff to review too many development proposals is one reason for the delays.

“Renewables are not the oil and gas industry of the future, we’re the industry of today and we need to have staffing” at state and federal permitting agencies, said Karl Gawell, executive director of the Geothermal Energy Association. The sheer volume of applications — which Gawell characterized as a “tsunami” — and the lack of staff at federal and state permitting agencies are slowing the development process.

Cautious Optimism

Most sources expressed cautious optimism that the worst of the recession is over and that 2010 will see growth resume. They point to the infusion of federal stimulus dollars and renewable portfolio mandates in most states that compel adopting renewable energy technology.

At the same time, however, sources noted conflicting trends that make it too early to tell whether or not sustainable recovery is likely in the next 12 to 18 months.

It’s a tough time to predict the future, said Jeff Dennis, a regulatory specialist with the Edison Electric Institute. On the one hand, demand for electricity is down, but state renewable portfolio standards and federal policies continue to push renewable energy deployment. “There are so many competing drivers that are 180 degrees from each other,” Dennis said.

One uncertainty is the prospect for a federal renewable energy standard. Work on legislation to create such a standard stalled during the autumn as lawmakers argued over health care reform. Several sources suggested the outcome of the health care debate and proposals for financial sector reform may actually determine whether or not a comprehensive energy bill is possible.

“Watch health care,” said USEA’s Barry Worthington. That debate has left some lawmakers wondering whether a comprehensive energy and climate change bill is the best course. Work in a more piecemeal and incremental fashion might be the preferred route. “The administration may be more empowered with a renewable energy standard as law even without a comprehensive bill,” Worthington said.

Regardless, if Congress fails to pass any sort of a bill before mid-2010, the prospects of getting climate legislation done next year will begin to fade. That leaves Congress with little more than a six-month window to complete its work. “It’s very difficult to get much out of Congress after July 4th” during an election year, Worthington said.

But if congressional action on federal standards is sluggish, renewable energy portfolio standards or goals in place in a majority of states are continuing to have an effect. California this fall raised its goal for renewable energy as a percentage of overall generation to 33 percent by 2020. But here too, uncertainty exists.

Can California meet its near-term goal of 13 percent renewables by the end of 2010? Sources said hitting that goal seems a stretch at present. In California as elsewhere, transmission adequacy remains a major impediment. Equally vexing are bottlenecks within federal agencies responsible for approving requests for projects on public lands–everything from transmission to projects themselves–a big factor in the west where federal landholdings are vast.

“The government has taken some good steps to incentivize renewables,” said Martin Gross, power systems president for ABB. But he believes those steps fall short of enabling the country to reach a goal of even 15 percent renewable energy in the U.S. generation mix by 2020.

“Fifteen percent at an availability of 30 percent would require 500 GW of installed capacity nationwide,” he said. “How does that happen?” For one thing, investors need a predictable 10-year return on their investment. For another, firm in-service dates for new transmission need to be set. “If you don’t see that it will be a continuation of 2009 with delays, delays, delays, delays,” Gross said.

Transmission and permitting will be perennial issues for renewable energy projects for the foreseeable future, said EPRI’s Bryan Hannegan. Opposition continues to large-scale developments, even those that promise low-carbon renewable energy. “We may have misled ourselves,” Hannegan said. “Folks still won’t want those in their backyards.”

PV Shines On

One bright spot in 2010 may be utility-scale solar photovoltaics, which shows signs of emerging from the economic turmoil well positioned for growth. PV panel prices dropped by around 35 percent in the last year and seem likely to continue to drop. That’s good news for developers. But the price decline comes largely at the expense of suppliers, who have too much manufacturing capacity and too much supply.

Manufacturers saw the market start to reverse in the third quarter of 2008 when the Spanish government moved to curtail what it saw as an overheated domestic market. That market also accounted for around 40 percent of the world’s large-scale PV demand. The Spanish market contracted some 80 percent on the government’s retrenchment and suppliers worldwide started to see inventory pile up.

The Spanish government’s action had a “dramatic and immediate impact on companies that ramped up capacity” to meet global demand, said Chris O’Brien of Olerikon Solar.

Hard on the heels of the Spanish reversal came the collapse of the U.S. tax equity market, which had been a cornerstone for much of the lending that supported renewable energy development.

That collapse “sent a chill through the market,” O’Brien said, and it added to the fall in component prices.

“Everyone in the channel needs more profit to stay in business,” said Ron Kenedi, vice president of solar energy solutions for Sharp Solar. Having seen a 35 percent drop in PV panel prices in the last year, Kenedi said, “I don’t see how that (sort of price decline) can continue.”

Unpredictable Natural Gas?

A wildcard in any 2010 forecast is natural gas, which saw volumes soar and prices fall during 2009. In the still-unsettled waters after the economic storm, a wide difference of opinion exists when it comes to the implications for renewables.

On the one hand, the drop in natural gas prices “helps wind enormously,” said USEA’s Barry Worthington. Low natural gas prices could further discourage coal-fired power plant development. And it could affect the economic viability of new nuclear power plants.

On the other hand, Blair Loftis at engineering firm Kleinfelder said “as long as natural gas prices are low it will suppress the (renewable energy) market.”

And Jeff Anthony, director of business development for the American Wind Energy Association, said “a wind project does not look as economical with low gas prices.” To its advantage, however, wind offers long-term fuel price certainty and relatively short project construction times. In places where wind competes head-to-head with natural gas capacity, those factors can still benefit wind.

Finally, EPRI’s Bryan Hannegan said that although the historically low price of natural gas is “not good in terms of the renewable industry trying to build” new capacity, ongoing pressure exists through renewable portfolio standards to build new renewable energy capacity.

That may be enough to counter natural gas’s economic effects, And as the economy has righted itself in recent months, interest in developing renewable energy projects has resumed.

“The market is hungry for good economic projects,” said Tim Howell, managing director and commercial leader for power and renewable energy with GE Energy Financial Services.

Technology Innovation

Also driving change in 2010 and beyond is technological innovation. Energy Insight’s Nadav Enbar said innovation allows for production cost reductions and installation cost reductions, either one of which improves a project’s financial performance.

Solar PV may be among the most innovative technologies at present.

For example, Oerlikon Solar achieved a new stabilized record efficiency level for amorphous silicon (a-Si) single junction PV cells. Recent test results reconfirmed and approved by the National Renewable Energy Laboratory show efficiencies of more than 10 percent power conversion. These results set a new world record for amorphous thin film silicon PV technology. The improvement is important because higher-efficiency thin film requires considerably fewer balance of system components, O’Brien said.

Competitors have not been standing still. Cost-leaders in crystalline technology have been driving costs down by using lower-cost polysilicon and less expensive manufacturing processes. A cadmium-telluride competition by FirstSolar showed promise of continuing to drive down costs still further. During the second quarter of 2009, FirstSolar became one of the first PV manufacturers to produce modules for less than $1 a watt.

“The importance of producing a module at under $1 a watt is enormous,” said Enbar. “There is enough disparity between production costs that they (FirstSolar) become the low-cost leader.” The cost currently is less than $0.90 a watt and could fall to just above $0.50 a watt by 2013. Work is underway to drive down balance of plant costs, such as inverters and racking.

Solar may be seeing the most dramatic technology changes, but wind is among the most advanced renewable energy. It will still be awhile before the onshore wind market becomes saturated in the U.S., but a lot of movement offshore exists. The coming months could also see the first offshore wind farms developed in the U.S. This comes 20 years after some of the first offshore turbines were installed in Denmark.

Duke Energy may be among the first to install offshore turbines with plans to invest $35 million for three turbines in waters off the North Carolina coast in Pamlico Sound. The Atlantic coast could be home to more than 1 GW of offshore wind farms, said the National RenewableEnergy Laboratory, which pegged the potential at roughly 900 MW off the Pacific coast. The U.S. Department of Interior said about 2 GW of offshore wind projects have been proposed in the United States. To date none have been built.

The controversial Cape Wind project off Cape Cod in Massachusetts is close to receiving its final permits, an important milestone prior to obtaining financing. That project could see 130 wind turbines with a generating capacity of 420 MW. Developer Cape Wind Associates has spent about eight years and $40 million so far on its efforts to build the facility in waters 5.5 miles from Hyannis, Mass. The total price tag is estimated to be $1 billion.

And the Bluewater wind project in waters off the Delaware coast first issued a PPA in 2008 and could make additional progress during 2010, buoyed by its purchase by NRG Energy announced Nov. 10.

Offshore wind could also move ahead in Texas, in part owing to the state’s unique regulatory environment. The state claims jurisdiction 10 miles into the Gulf of Mexico, more than three times the distance claimed by states along the Atlantic coast. That puts Texas projects beyond the range of important “view sheds” and also removes red tape by largely eliminating federal review.

In geothermal, work is underway to improve resource detection and development. Geothermal development can be more risky than either oil or natural gas development, said Dan Jennejohn with the Geothermal Energy Association. Dry holes are not uncommon. What’s more, it’s become more expensive to develop a geothermal field. In the past a geothermal project was not considered financeable unless one-third of a well field was drilled and confirmed. Now the figure is closer to two-thirds to as much as 70 percent confirmed.

“Lenders are applying the same increased scrutiny and decrease in tolerance for risk as in other industries,” said the Association’s Karl Gawell. Even so, technology developments are underway on fracturing techniques to enhance a geothermal resource. The Department of Energy provided $400 million for technology development, and was oversubscribed by a factor of five.

In the hydroelectric sector, interest is growing in new developments and repowerings. “It’s time to reinvest in hydro,” said Linda Church-Ciocci, executive director of the National Hydropower Association. Efficiency improvements are expected at a number of existing sites. And interest is growing around areas such as dam-less technologies that insert turbines into navigation locks that previously had not been powered. Pumped storage projects are also gaining renewed attention as a way to provide storage capacity for wind and solar. Conduit and water system projects are among the low-power projects that are seen as more feasible.

Stimulus funding provided $32 million for hydro. “We anticipate seeing a significant boost to projects on existing hydro facilities to improve their efficiency,” Church-Ciocci said. “Certainly the stimulus money is working.”

As proof, electric power generator PPL Corp. announced plans last April to file a new application with the Federal Energy Regulatory Commission for a $440 million project that would add 125 MW of generating capacity at the Holtwood hydroelectric plant on the Susquehanna River in Lancaster County, Penn.

“PPL has reconsidered this project in view of the tax incentives and potential loan guarantees for renewable energy projects that are in the federal economic stimulus package,” said William H. Spence, executive vice president and chief operating officer of the company, which controls 1,100 MW of generation including coal, natural gas, oil, uranium and water. “These stimulus package benefits could make the project feasible again by more than offsetting the factors that caused us to withdraw our original application in December (2008) and the further decline in future energy prices since that time.”

While regulatory and other hurdles still must be cleared, the utility said it may put this new generating capacity into service by the spring of 2013.

When federal tax credits were reinstated a year ago, expectations were that 2009 would be a good year for renewable energy development. Recession and financial collapse raked the industry, much the same way a hurricane reshapes a landscape. Financial markets still are recovering, the federal government (for now anyway) is a major source of capital, utilities are playing a larger role technology improvements continue to drive innovation and price reductions.

Sources agree the basic policies are in place to drive and sustain renewable energy development in the near term. Barring an economic relapse, optimism is high that the next 12 to 18 months will see recovery and growth across most renewable energy sectors.

The hope is that the “messy” capitalism that Nadav Enbar said characterized much of 2009 is indeed behind us.

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