By David Wagman, Chief Editor
Utility-scale solar power generation has captured headlines in recent months as both solar thermal and photovoltaic projects are being proposed across the United States.
A combination of factors seems responsible for the activity.
First, Congress last fall renewed federal tax credits that benefit a variety of renewable energy sources, including solar. Previously, Congress renewed the credits for two years at a time. This past autumn, however, Congress agreed to an eight-year extension for solar projects. It also extended the credits for the first time to utilities.
Second, the cost of photovoltaics has dropped. In turn that has cut construction costs from an estimated $6,000/kW a year ago to around $3,500/kW more recently. Technology improvements have been one factor affecting prices. But a larger factor has been the addition in recent years of new manufacturing capacity (particularly in China) to meet robust global demand. That robust demand largely collapsed last autumn as economic growth slowed, stopped or reversed, depending on your location. The oversupply of PV has created a buyer’s market, which is benefiting those companies able to secure project finance dollars.
Third, renewable portfolio standards remain in force across roughly 60 percent of U.S. states. In many cases the standards specify how much renewable energy that each state must have by a certain date. Because the goals are the result of government mandates rather than market forces, utilities in general still must work toward adding renewable energy resources to their generating portfolio even during a recession.
Fourth, there’s some creative thinking going on when it comes to deploying both photovoltaics and solar thermal resources at a utility scale.
For example, business planners at Southern California Edison saw an unmet need in the 1 to 2 MW rooftop photovoltaic market. As a result, the utility proposed to regulators that it build 250 MW of this sized resource. State regulators approved the plan, but doubled the program’s scope by encouraging non-utility developers to add 250 MW on their own. The utility’s plan is to spend $875 million over five years for the 250 MW, a pace that will see it add around 50 MW of PV capacity a year.
The new PV is likely to be scattered around the utility’s service territory. That’s because placing all the PV in one location could overload local circuits. Dispersing the capacity also reduces the chance that clouds will disrupt power generation, an ongoing problem for PV. Further, because transmission ranks as the No.1 barrier to renewable energy growth in California, adding a lot of small, distributed resources results in little tangible effect on the distribution system.
As a second utility example, NV Energywhich serves Nevadamay add a solar collector field at two gas-fired power plants near Las Vegas. The installation would create an integrated solar combined cycle (ISCC) power plant in which solar Btu’s replace at least some natural gas Btu’s. And Florida Power & Light is already building a 75 MW ISCC to handle duct firing load at its Martin plant. The solar resource coincides well with peak demand periods at both utilities. Substituting solar thermal for natural gas for peaking purposes could make economic sense.
Just how widespread solar generation becomes in the next 12 to 18 months remains to be seen. Credit markets remain difficult and most projects require a long-term purchased power agreement. Pricesparticularly for PVmay recover as economic conditions improve. And, even though federal tax incentives now include utilities, not every utility feels comfortable with solar technology to pursue outright ownership. Then, too, not every utility wants to own generation assets. SoCalEd prefers owning transmission and distribution assets. NV Energy appears open to ownership and earning rate base returns on its investment.
Regardless of when the solar market finally catches hold, one thing’s for certain: the sun will be waiting.