Utilities Developing More Solar Projects

But experts are now seeing shifts in the industry that reflect changing models and an increased acceptance of renewable-based technologies. As solar power continues to spread beyond the traditional hotspots, it’s now the utility companies are often driving that change, according to SEPA’s 2010 utility solar report. 

For utilities, the reasons behind their continued renewable energy investment in a market dominated by coal, natural gas and nuclear power is as diverse as the companies themselves. For some, it’s been a mandate set forth by their state. For others, it’s been a natural part of diversification as utilities look to hedge against the volatility of fossil fuels. And in many markets, the driving force has been consumer demand in tandem with the falling prices for solar technology.

“It’s very much policy driven. Targets still comprise a majority of the activity,” said Bob Gibson, Vice President of Market Intelligence for SEPA. “Utilities see the costs continuing to come down. Even with that, most of the growth is to meet the portfolio standard. But they see it as the start of having a truly diversified portfolio.”

At Duke Energy in North Carolina, the utility is working to balance state mandates, growing customer demand and overall cost.

“We’re trying to bring as much on as we can in ways that applies with law and makes it cost effective,” said Duke Energy Spokesperson Jason Walls. “In the solar industry, the price has come down dramatically. But there’s a lot more work that needs to be done to make it cost effective.”

Walls said that technology and efficiency gains have been evident, but that the solar industry still needs to refine its manufacturing process to drive down costs even further. The North Carolina mandate requires utilities to have 12.5 percent of energy produced come from renewable sources by 2021. Without that, said Walls, the regulated utility would not be as heavily invested in renewables like solar.

“Every time you diversify, it’s a good thing,” said Walls. “I don’t think it’s comparable to think about solar being able to compete with nuclear and coal from a cost perspective.”

Walls said that technology and efficiency gains have been evident, but that the solar industry still needs to refine its manufacturing process to drive down costs even further. The North Carolina mandate requires utilities to have 12.5 percent of energy produced come from renewable sources by 2021. Without that, said Walls, the regulated utility would not be as heavily invested in renewables like solar.

“Every time you diversify, it’s a good thing,” said Walls. “I don’t think it’s comparable to think about solar being able to compete with nuclear and coal from a cost perspective.”

New Projects

For years, utilities benefited from power sold into the grid from independent power producers. But in 2010, many of those same utilities benefited from exponential growth in power they produced.  

In 2010, large-scale utility-led developments included a 48-megawatt Copper Mountain PV project in Nevada and the 30-megawatt Cimarron PV project in New Mexico. The nation’s largest single project was not a PV development but rather a 75-megawatt concentrating solar power installation at the Martin Solar Center by Florida Power & Light. The project marks the largest CSP development in nearly 20 years. (See table, below, which shows the 10 largest projecs developed in 2010. Table courtesy SEPA)

Of the 561 megawatts (MW) of solar capacity added last year, 140 MW are actually owned by the utilities. “The ownership trend is a truly significant finding,” said Julia Hamm, president and CEO of SEPA. “It represents a 300 percent increase over the numbers reported in 2009. We expect the growth in utility solar power to continue.” 

But the growth has not always been easy, said Gibson, and each utility has its own concerns, it’s own set of standards and it’s own customer expectations. 

“A lot of people would like to see solar in their communities,” he said. “Utilities are finding that they can make it happen in different ways. They’re starting to look at utility ownership as an option. Some are seeing that ownership may pencil out to be more advantageous. They’re finding ways to make it work and to make it more compatible.”

According to SEPA, the rate of growth is expected to remain stable with 1,100 MW of new developments planned to come online over the next couple of years. 

“We see the pipeline as very rich,” said Gibson. “We’ve seen growth continuing even during the economic recession. That’s another suggestion that it’s on pretty firm footing. We expect this growth will continue. We saw huge growth in 2008 to 2010. Still, overall, it’s a pretty small part of the energy portfolio. But utilities are asking themselves, ‘How will we do solar in the future?’ The future is not very far off, and prices are giving them more confidence. They’re going after solar aggressively, even if they’re not ready for it.”

Maintaining that momentum, said Gibson, is as much about policy as it is about technology.

“Incentives are already being scaled back because the cost has scaled down,” he said. “It’s part of the maturing process, but we’re not quite there yet.”

Regional Breakdown

The West Coast still dominates the solar utility market, with about two thirds of the U.S. capacity. It remains the most mature market, in part due to more aggressive mandates from states like California, an abundant source of sunshine and a consumer base that is more committed to renewables. 

The East Coast, meanwhile, is quickly catching up in terms of renewable energy portfolios, consumer demand and total capacity. Gibson points to New Jersey, North Carolina and Florida as three East Coast states taking different approaches to implementing solar.

New Jersey is perhaps the most mature market on the East Coast, but it’s also the one facing the most uncertainty. Gov. Chris Christie has recently announced that his state will pull out of the Regional Greenhouse Gas Initiative (RGGI), a carbon-emissions pact that unites states in the northeast.

While the end of the RGGI cap-and-trade program is expected to make implementing renewables less cost effective, Gibson expects the market will move forward.
“It will probably tap the brakes [on the momentum],” he said. “But utilities there certainly want to do it. There will be economic growth if there is a big enough market. But you don’t want to pull out all the policy. New Jersey is not yet a mature market.”
North Carolina, meanwhile, has a mandate, some significant projects and backing from many key members in the state.

“The legislature there is pretty supportive, and R&D is welcome,” said Gibson. “It’s a good market for continued growth.”

The real test case may be in Florida, which has lot of sun, a fairly isolated power structure and no state regulations that require renewables. Yet it put up two of the nation’s 10 largest projects in 2010, including the 75 MW CSP installation.

“The state needs energy,” said Gibson. “It’s a peninsula, so it needs to have local generation on a large scale. It’s more limited in terms of getting connected. But will it be cost effective to have investors without a portfolio?”

The biggest struggle -- and perhaps the largest area of untapped potential -- is in the central part of the United States, which has made relatively few strides outside of certain pockets such as Chicago, Austin, Texas, and Madison, Wis.

“It’s a policy issue,” said Gibson. “What do states want in terms of energy portfolios? In New England and the West Coast, there are populations that are more motivated. Oklahoma and Texas have huge solar resources and perhaps new markets.”