Solar scale-up seems to be happening even faster. Although there are still plenty of small projects—in the kilowatts and single-digit megawatts—many recent contracts involve massive systems in the 200-MW, 500-MW and even the gigawatt range.
Of course, few if any of these large projects would exist today without federal tax subsidies and state-level renewable portfolio standards (RPS)—especially those with solar carve-outs. And solar power still suffers many of the same limitations that plague wind power. Namely, it’s variable and non-dispatchable; its capacity factor never will rival the typical fossil, nuclear or large hydro plant; and on a per-kilowatt basis, it remains more expensive than the least-cost fossil alternatives—or wind power in most cases.
Nevertheless, the dramatic scale-up in project size is bringing solar into the mainstream as a utility-scale generation resource—and as an investment opportunity (see “Chasing the $un”). No longer can solar be dismissed as a novelty or a publicity stunt, à-la the solar panels on Jimmy Carter’s White House. Further, solar brings some advantages that suggest its long-term potential exceeds that of wind power, perhaps by a wide margin.
Solar projects are easier to site because sunlight is geographically ubiquitous and more consistent than wind is. And solar facilities produce power in a way that’s more closely matched to the load curve—i.e., they reach their maximum output just as cooling demand is peaking.
These factors alone are enough to assure opportunities for solar energy. But a third factor might prove to be a game changer: solar still has a lot of room for improvement in efficiency and cost. Wind technology can still improve too, but such improvements likely will be incremental. By comparison, PV’s cost-per-performance ratio has been advancing at an exponential pace—and there’s no reason to expect that pace will slow down much any time soon.
Despite the promise, contracts for large projects haven’t yet translated into much steel in the ground. The fact is, of the many announced projects exceeding 100 MW in size, exactly zero have entered service. The country’s largest operating PV plant, Sempra’s Copper Mountain facility, has a maximum capacity of less than 50 MW, and the biggest solar thermal plants, the 80-MW SEGS VIII and IX plants, were built 20 years ago.
That’s not to say some of the mega-solar projects now in development won’t get built. Abengoa Solar, for example, secured $1.45 billion in financing to build what it says will be the world’s largest parabolic trough CSP plant, the 250-MW Solana project near Phoenix. Abengoa has a 30-year PPA with Arizona Public Service, and a loan guarantee from the Department of Energy. Projects like that, fully financed and now in construction, seem likely to reach the finish line.
But a string of major project cancellations raises real questions about how many of the current crop will survive.
• Developer Solar Millennium in late January 2011 canceled its plans to build a 250-MW parabolic-trough plant near Ridgecrest in California’s Mojave Desert. The project reportedly was canceled after concerns were raised about its effect on habitat critical to endangered desert tortoises and other threatened species.
• Southern California Edison in December 2010 canceled a 20-year, 663.5-MW power purchase agreement (PPA) it had signed with a parabolic-dish project that began development in 2005, also in the Mojave Desert. Soon thereafter, the project’s developer, Stirling Energy Systems, sold the project to K Road Power, which abandoned the parabolic-dish technology for most of the project, in favor of PV panels. The change in plans negates a key license the project received from the California Public Utilities Commission, and in effect sends the project back to the drawing board.
• Last June, the developer of a hybrid solar and biomass project planned for Fresno County, Calif., withdrew its license application, citing “issues regarding project economics and biomass supply amongst other things.” The project had a 107-MW, 20-year PPA with PG&E.
• Developer Starwood Energy Group in late 2009 canceled a PPA with Arizona Public Service for a 290-MW solar thermal project after Lockheed Martin withdrew as the general contractor, citing “unexpectedly high supply base costs,” as well as the overall size and risk profile of the project.
Several other projects have fallen under the crosshairs of environmental advocates and Native American groups. Most recently, in December 2010 petitioners led by the La Cuna de Aztlan Sacred Sites Protection Circle sued the Department of the Interior, alleging Interior’s Bureau of Land Management violated several federal statutes when granting permits to build projects on public lands that contain burial grounds and cultural relics. The lawsuit challenges permits for BrightSource’s Ivanpah, Tessera’s Imperial Valley, Solar Millennium’s Blythe, NextEra’s Genesis and Chevron’s Lucerne Valley sites.
Whether such setbacks are merely part of the technology’s growing pains, or whether they reveal fundamental flaws, might determine whether the current vision for utility-scale solar can succeed.
To the degree solar projects fail because their owners can’t access financial markets, utilities might bring a compelling solution. Utility backing can reduce financing costs and provide a more solid economic foundation than many independent developers can deliver. Further, utilities can help projects overcome the regulatory, technical and operational challenges that any new technology is bound to encounter in its journey to maturity.
And make no mistake, solar technology remains immature. The first wave of utility-scale projects—and project failures—revealed some of the pitfalls. But project sponsors will continue running into problems, and utilities and regulators can expect tough questions from investors and ratepayers when the bills come due for fixing those problems.
From a policy perspective, bringing solar into the mainstream serves customers’ interests, because it adds technology options to the fuel-diversity menu. And from a business perspective, solar power clearly is emerging as a viable generation investment.
Utilities have a natural and essential role to play in realizing solar energy’s vast potential, and making it work as part of a safe, reliable and affordable power system.
In the printed version of the February 2011 article, “Capacity Contest” (p.25), we erroneously stated that American Electric Power had left the Midwest ISO to become a member of the PJM regional transmission organization (RTO). In fact AEP decided not to join the Midwest ISO upon the dissolution of the proposed MISO rival, the Alliance RTO, and instead joined PJM.
In the printed version of the January 2011 “People” department, we stated that Calpine named Thad Hill CEO. In fact he was named COO.
Fortnightly regrets these errors, and has corrected them in the online versions of the respective articles.