While the pace of installations of distributed solar systems for homes and businesses has steadily risen over the past few years, utilities have mostly stayed out of the picture. However, that appears to be changing now as more and more utilities are looking at solar energy as major contributor to their current and future renewable energy portfolios.
The shift has occurred for a number of reasons, including rising fossil fuel prices, renewable portfolio standards (RPSs) coming into effect in many states and an American public that is becoming increasingly interested in renewable energy sources. There remains, however, some concern over whether this interest will translate into putting megawatts (MW) of solar energy generating capacity on the ground and the roof.
"2008 was a foundational step for utility-scale project announcements," said Julia Hamm, executive director of the Solar Electric Power Association (SEPA), whose aim is to help the solar industry work with the utility sector.
"SEPA is aware of contracts totaling over 1,500 MW of PV and 4,000 MW of concentrating solar thermal. However, very few are digging dirt or hoisting onto roofs yet and there is a high level of uncertainty for some projects," said Hamm.
Hamm pointed to a number of key utility-scale solar projects that SEPA is watching.
California's Pacific Gas and Electric (PG&E)
In 2008, PG&E entered into an agreement with Topaz Solar Farms LLC, a subsidiary of OptiSolar Inc., to install 550 MW of thin-film PV solar power. The utility also signed a contract with High Plains Ranch II LLC, a subsidiary of SunPower Corporation, for 250 MW of solar PV. Thin-film panels for the Topaz Solar Farm will be designed and manufactured by OptiSolar.
In total, the projects are expected to deliver approximately 1.1 million megawatt-hours annually and could begin power delivery as early as 2011. PG&E expects it to be fully operational by 2013.
The utility has also signed a long-term agreement with El Dorado Energy LLC, a wholly-owned subsidiary of Sempra Generation, to purchase 10 megawatts of PV-produced energy from Sempra's El Dorado Energy Solar facility in Nevada (RenewableEnergyWorld.com will be touring this facility in March and we'll have an in depth look at the project). The El Dorado facility is located on 80 acres adjacent to Sempra Generation's existing gas-fired power plant in Boulder City, Nevada. Power deliveries to PG&E have already begun. The project will generate up to 23.2 gigawatt-hours of renewable energy annually.
Cleantech America LLC and GreenVolts Inc. also signed deals with PG&E to develop utility-scale PV projects that could deliver up to 7 MW of utility-scale solar energy for PG&E's customers throughout northern and central California, with project completion dates of this year.
In addition to solar PV, PG&E has been active in pursuing solar thermal power, and has signed a deal with Solel to purchase renewable energy from the Mojave Solar Park, to be constructed in California's Mojave Desert. The project will deliver 553 MW of solar power. The utility is also involved in a 177-MW solar thermal project with Ausra Inc. The plant, to be located in San Luis Obispo County, California, is expected to begin generating power in 2011.
Finally, PG&E entered into two contracts with San Joaquin Solar LLC, a subsidiary of Martifer Renewables Electricity LLC, for a combined 106.8 MW of solar thermal-biofuel hybrid power. Located near Coalinga, CA, the solar-biofuel projects will deliver a total of 700 gigawatt-hours (GWh) annually.
North Carolina's Duke Energy
Another project that is being closely watched by the industry is Duke Energy's distributed PV project. It was originally announced in June 2008 as a US $100 million, 16-MW project. Then in late 2008, Duke scaled back the project to $50 million and 8 MW. Now it appears that the project is in danger of being scrapped altogether because of a recent ruling by the North Carolina Utilities Commission (NCUC) that would not allow the utility to take advantage of the federal investment tax credits for solar energy.
Duke said that the NCUC decision, issued December 31, 2008, would have made it impossible for the company to proceed with the solar plan without facing very sizable financial risk and possibly violating federal tax rules associated with energy investment tax credits.
The company said that if it proceeded with the solar program under the commission's order as it is currently written, the company could lose more than $250 million in federal tax credits associated not only with its solar project, but potentially with other Duke Energy power plant projects as well.
In the NCUC's order, Duke said that it would be allowed to recover costs up to an amount equal to the third place solar bid that was part of the 2007 RFP for renewable energy sources. The commission did leave open the possibility that Duke could seek recovery of additional prudent costs that exceeded this third place bid through a base rate case. However, the commission did not guarantee that it would grant full recovery of such costs.
Duke spokesman Dave Scanzoni said that the company is hopeful that an appeal it filed to the decision will be upheld and will allow the company to move ahead with the project in North Carolina. That could open the door for Duke to try similar projects in other markets, including Ohio and Indiana.
"We certainly see solar as a growing component of our portfolio. We see more solar initiatives going forward as well. Solar is going to be a major part of our future," Scanzoni said.
Other Projects: Arizona, Florida, California and New Jersey
SEPA and the rest of the industry are following the progress on a number of other projects that run the gamut of solar technology.
Arizona Public Service (APS) is working on a 280-MW solar thermal project with a storage component that industry insiders are closely watching. Abengoa Solar has signed a contract with APS, to build, own and operate the Solana plant, scheduled to go into operation by 2011. It will sell the electricity produced to APS over the next 30 years for a total revenue of around $4 billion, bringing over $1 billion in economic benefits to the state of Arizona.
NextEra Energy Resources, formerly FPL Energy, is planning a 75-MW hybrid solar plant, which broke ground in December. The Martin Next Generation Solar Energy Center will consist of approximately 180,000 mirrors over roughly 500 acres of land. The facility combines a solar-thermal field with a combined-cycle natural gas power plant. NexEra and SunPower are also set to install a 25-megawatt (MW) power plant in DeSoto County, Florida and a 10-MW project at the Kennedy Space Center. The DeSoto plant is expected to be completed in 2009.
This week, Southern California Edison (SCE) and BrightSource Energy reached agreement on a series of contracts for 1,300 megawatts (MW) of solar thermal power. The agreement, which now requires approval from the California Public Utilities Commission (CPUC), calls for a series of seven projects to make up the total capacity. The first of these solar power plants, sized at 100 MW and located in Ivanpah, California., could be operating in early 2013 and is expected to produce 286,000 megawatt-hours (MWh) of renewable electricity per year.
Last year, the CPUC approved the FSE Blythe project that First Solar Inc. is developing for Southern California Edison. Initially a 7.5-MW solar photovoltaic (PV) facility, the project has the potential to expand to 21 MW.
Public Service Electric and Gas Company (PSE&G) this month asked New Jersey regulators to approve a US $773-million proposal to bring 120 megawatts of solar power directly to communities and customers throughout its service territory. PSE&G will invest in, own and operate the grid-connected solar energy systems and will collaborate with experienced solar developers, installers and manufacturers to develop projects.
Will More Utilities Get on Board?
SEPA's Julia Hamm said that while these and other projects are a great start, utilities and solar companies can do more to work together. She thinks utility staff could benefit from more knowledge of solar in general.
"First, education of utility staff needs to be top priority. We are seeing more interest from utility planning and procurement staff, not just solar incentive program managers. That's a good sign — their interest is indicative of the utility's recognition of the potential of solar moving forward," she said.
Hamm would like to see more utility programs aimed at gradually increasing their uptake of solar. "2008 was really a wake-up call that solar is scaling up and the utility's involvement in this process is crucial."
Ensuring market certainty is another way for utilities to build up their solar programs said Hamm. "The use of traditional RFPs and PPAs to procure solar is one mechanism, but there are others. [Programs should] provide both scale and increment — 50 MW per year for 5 years for example," she said.
Hamm explained that utilities might enter into energy "pre-purchase" contracts, where utilities provide capital financing for a solar project as a pre-purchase of, perhaps, 10 years of electricity.
Lastly, all stakeholders need to prepare for the future by addressing important issues like transmission that cause problems in the industry.
"Stakeholders of all stripes need to get involved and address the potential bottlenecks of transmission, permitting, and grid integration now, so that 5 years from now, we are ready for the industry's growth," she said.
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