The Department of Interior’s new policy is not much different than the status quo we have fought to change.  Although the policy attempts to encourage companies to build in special “solar energy zones,” these zones still contain vast swaths of ecologically intact desert habitat that host rare and endangered plant and animal species.  The policy would also allow companies to build on 19 million acres of “variance” lands in some of the most remote corners of our deserts. Although the policy establishes some exclusion zones where future energy development will be prohibited to protect natural and cultural resources, the policy will still allow dozens of industrial project applications pending review to proceed without any restrictions in the exclusion zones.

The success of the solar industry is not dependent on access to public lands, as we have already seen in the United States and other countries. California already has over 1,300 megawatts of rooftop solar panels, over 750,000 homes in Australia have installed solar panels, and Germany now generates over 25,000 megawatts of clean energy from mostly local solar installations.  Truly clean and sustainable energy can be generated in our cities, and not on public lands.

Specifically, the petition notes that the FiT formula in the CPUC decision does not recognize one of the greatest benefits of rooftop solar installations to other utility ratepayers—the avoidance of new transmission and distribution costs, which are required when the utility companies invest in expensive and remote power plants far from the point of use.

The petition calls out CPUC and the utilities for failing to implement the right policies to encourage local clean energy, pointing to Germany as an example of how robust feed-in-tariffs have encouraged 15 times more solar installations than California in just one year, even though California gets far more sunshine. 

Utility companies continue to pose a barrier to the deployment of distributed generation and the use of existing FiT programs. Southern California Edison’s own FiT program—known as CREST—has only brought 5.25 megawatts of new projects online out of a total program capacity of 200 megawatts, four years after the program began, in part because of a punitively low FiT rate and administrative delays by the utility company.

California has already installed over 1,200 megawatts of rooftop solar panels, with a significant number of installations in median income neighborhoods, despite weak incentives.  Making local clean energy available to all interested ratepayers requires a healthy FiT program that favors individuals over utility companies, and fully recognizes the considerable benefits of distributed generation. 

Ratepayers have long been subjected to poor utility company decisions to buy power from remote locations, contributing to the destruction of our environment and requiring unnecessary and expensive new transmission lines.  Ratepayers that generate clean energy and share that with the grid should have equal access to cost recovery since they generate higher quality power while avoiding costly new transmission lines.

Solar Done Right supports a FiT rate of 25 cents per kWh in the first 2 years targeting systems under 100 kW, with tiered reductions every 2 years thereafter, with a goal of installing 3,000 MW per year contracted over 15-20 years.  This rate establishes a fair rate of return to interested ratepayers and will result in rapid conversion to a clean, decentralized, dynamic and reliable grid while ensuring that rates do not increase for non-generating ratepayers. This rate is high enough to stimulate interest and motivate the vast segment of ratepayers who are eager to be a part of the renewable marketplace.  By comparison, utilities in California are paying as much as $1.88 per kWh on the market at peak demand, benefiting corporate power generates hundreds of miles from our communities.  A robust FiT that encourages more distributed generation could help our communities meet daytime power needs while employing tens of thousands more people in the state, boost property values, and meet renewable portfolio standards (RPS).

Fairly compensated, residential-scale solar should be the first priority of the state of California and the CPUC.  A robust FiT would also encourage the rapid establishment of “community solar gardens” for renters and lower income participants under SB 843, and encourage conservation of electricity and civic engagement - all policy goals at the state level.  Monies paid to ratepayers injects resources directly into communities, creates local jobs, increases property values and generate multiplier effects that will set our economy and tax base back on track.

With distributed generation, we have the opportunity to generate clean energy at the point of use and give our wildlands a break from further destruction caused by an increasingly costly, destructive and inefficient remote industrial solar, wind and transmission power infrastructure.  It is time for CPUC and our utility companies to encourage—not obstruct—our transition to local clean energy.

Policies such as Property Assessed Clean Energy (PACE) and a healthy feed-in-tariff can boost rooftop solar even more. In the meantime,  California was taking other steps to promote local clean energy. On 24 May, the California Public Utilities Commission passed a rule requiring utility companies to increase the number of customers that can benefit from a program crediting them for any excess energy generated by rooftop solar panels and sent to the grid.  The ruling is a critical step and keeps the door open for rooftop solar, but the cap on rooftop solar likely will have to be raised again in the next two years.

Separately, the Public Utilities Commission in May passed an order encouraging utilities to establish a program for commercial and multi-family residential customers that would allow them to pay for energy efficiency upgrades and rooftop solar on their monthly utility bill.  The Commission does not have the authority to require such a program to benefit homeowners, but legislation championed by the Environmental Defense Fund, State Bill 998, will give the Commission the authority to do so.  On-bill repayment will help make energy efficiency and rooftop solar more accessible to people in California, allowing them to pay back the up front costs over time, and attaching the costs to the property where the improvements were made.

Separately, the “Solar for All” legislation (A.B. 1990) passed the Assembly in May, and is now pending in the State Senate. The bill will require utilities to institute a feed-in-tariff sufficient enough to generate 375 megawatts of local clean energy in disadvantaged and impoverished communities, bringing the benefits of rooftop solar to the communities that often suffer the most environmental injustice. 

We still have a long way to go to top progress made elsewhere—over 500,000 rooftop solar installations in Australia, and over 25,000 megawatts of distributed solar generation installed in Germany—but California is taking positive steps toward generating more clean energy at the point of use, sparing our wildlands for future generations.

Send comments to FHFA at by 26 March, and be sure to include “RIN 2590–AA53,  Mortgage Assets Affected by PACE Programs” in the subject line of your message. You can draw from any of the talking points below to personalize your message.

PACE_Talking_Points_PDF.pdf

• FHFA should rescind its opposition to PACE programs that are necessary tools for communities to pursue more sustainable energy use and generation.

• PACE programs help us reduce our dependence on fossil fuels, promote clean air, and lower our utility costs over time.  Energy efficiency and rooftop solar installations also improve property values. 

• PACE programs are also in the public’s interest because energy efficiency and distributed generation are cheaper than building expensive new power plants and transmission lines that require the destruction of natural resources and cherished wildlands.

• Municipalities have a well-established history of using special assessments similar to PACE to finance community benefits, including improvements to personal property.  FHFA has not challenged these other special assessment programs, nor does it have authority to do so.

• A pilot PACE program in Colorado generated over one hundred jobs and nearly $20 million dollars in economic activity and over one hundred jobs in just one year, according to the Department of Energy. 

• Generating local clean energy, boosting our economy, and reducing our dependence on fossil fuels is not just in the interest of municipalities.  These are also priorities for our Federal government, and the FHFA’s decision to challenge PACE is inconsistent with these priorities.

Big Solar and Wind facilities will require so much ecologically intact land that we will ultimately lose many of the places and wildlife we want to protect from global warming, including habitats that sequester greenhouse gases (GHGs).  So far, energy companies have submitted applications to develop almost 230,000 acres, or about 360 square miles, of public land in California alone —the vast majority of it undeveloped wild lands—for solar and wind projects.  These projects would only supply a fraction of our energy needs, but would needlessly industrialize many of our intact wildlands.

Given the urgency of climate change, isn’t rooftop solar deployment too slow?

Distributed generation (DG) installations increase rapidly with the right policies. Over half of Germany’s 53,000 megawatts (MW) of clean energy are generated by smaller installations owned by individuals, and that number is growing rapidly. Germany installed 3,000 MW of solar in Dec. 2011 alone. In Australia, over 500,000 homes have rooftop solar thanks to a successful feed-in-tariff. The US has been slow to adopt policies proven effective elsewhere, but even so California has installed 1,000 megawatts of rooftop solar. Not a single watt of large-scale industrial solar has come online since solar “fast-tracking” was implemented in 2005. The NREL has identified the potential for 80,000 MW of rooftop solar in California alone, far more than would be needed to reach even the most ambitious RPS/RES goals.

See: Germany solar: http://energyselfreliantstates.org/content/american-and-germany-getting-their-renewable-energy-just-desserts and http://www.bloomberg.com/news/2012-01-06/germany-s-solar-surge-leaves-biggest-market-steady-in-2011.html, Australia: http://www.smh.com.au/environment/energy-smart/solar-panel-users-climb-through-roof-20111205-1ofjx.html.

Aren’t deserts too hot, dry and inhospitable to support much life?

While many people believe that deserts are inhospitable places that support very little life, nothing could be further from the truth. According to the Endangered Species Coalition, our diverse North American deserts, home to many thousands of species and hundreds of diverse ecosystems, face a threat from global warming that is second only to that of the Arctic. Even seemingly sterile desert landscapes such as dry lakes teem with living things.

Don't tortoises like the shade solar facilities create?

Federally threatened desert tortoises — and other sensitive species like burrowing owls and kit foxes — use burrows and desert plants for shade. When a site is developed for solar, these animals are relocated or forced out of the area. Diseases may be spread and as many as half the adult tortoises moved from their homes may perish from the rigors of handling and relocation. The vast majority of juveniles and eggs, which can number in the thousands on single sites, may perish undetected. Fences are placed around the entire project site, excluding tortoises and larger animals and interrupting normal migration patterns across large areas. Industrial solar development radically alters 100% of the project site, which can be as large as 10 square miles. Before construction can begin, the entire area is graded flat by heavy equipment — or mown down, with effectively the same impact to the plant and animal life — to place the photovoltaic (PV) panels or mirrors. Destroying desert soils can cause or exacerbate airborne partriculate matter, erosion, and flooding problems.

Won’t the economy of scale with larger installations mean their power will be cheaper?

It’s cheaper per watt of power generated right now to install a small rooftop system in Germany than to install a giant desert installation in the US. Sensible policy can drive down prices much faster and more effectively than corporate giveaways. German Feed in Tariffs (FIT’s) have resulted in a 10% drop in electricity prices as onsite solar reduces the need to buy expensive daytime peak-period power. FITs provide income to people and local economies, whereas when Big Solar cash goes to Chevron, BP, Goldman Sachs or Morgan Stanley, and is pulled out of the community.

What about preserving valuable agricultural land from industrial solar and wind development?

There’s no need to pave productive agricultural land over with solar panels or giant wind turbines. The Environmental Protection Agency has identified millions of acres of severely degraded and contaminated lands suitable for industrial wind and solar in its Re-Powering America’s Land program and millions more rooftops, parking lots, urban brownfields, highway medians and other developed spaces would benefit from shade and high-value power provided by solar panels.

Don’t we need all scales of renewable energy production in order to combat climate change?

Distributed generation could handily meet our renewable energy needs without pursuing remote, utility-scale development on our irreplaceable wildlands. Unfortunately, in the US, the energy and banking industries work to block common-sense, effective solutions like increasing efficiency and local generation even though these solutions are faster to implement and better for our environment, our economy, our communities and our atmosphere. The poor allocation of limited grid distribution capacity and financial and technical resources to remote, corporate-owned central solar primarily benefits utility investors while depriving individuals, businesses and local communities of the opportunity to develop and benefit from their own renewable resources. See: "Centralized v. Decentralized Clean Energy – We May Have to Choose" by John Farrell.

Don't desert panels produce a lot more power than panels in less-sunny areas?

Photovoltaic and air-cooled concentrating solar plants are less efficient and transmission losses highest when temperatures are high and when the power is needed most. 10 to 14% of the electricity is lost through long-distance transmission, effectively negating marginally higher insolation. PV is modular: there is no increase in power production gained by aggregating panels in a single site. Transmission infrastructure is also inherently vulnerable to weather, natural disasters, cyber hacking/terrorism and human error, while local micro-grids are ideal to accommodate local solar generation at peak times without ever accessing transmission infrastructure.

Wouldn't the large-scale solar projects bring a lot of jobs to the community?

Solar power plants can be controlled remotely and only a few people are needed to manage large plants. Once the 1- or 2-year construction cycle is over, very few permanent jobs remain, depending on the technology. Construction workers are normally hired by contractors who maintain their own skilled labor force, so that local hiring may be minimal. By contrast, the installation of distributed rooftop solar produces up to 3.5 times as many jobs and local economic benefit. Rooftop solar and efficiency upgrades also increase property values and if feed-in-tariffs are in place, improve prosperity for the community.

Why should NIMBY’s (“Not In My Backyard”) get to stall our best chance to combat global warming?

Solar Done Right supports generating renewable energy in our backyards, on our rooftops, and in our neighborhoods. Objecting to corporate dominance over our economy, democracy and environment is not NIMBYism. Local solutions of efficiency upgrades, passive heating/cooling and distributed solar/microwind in the built environment are the most effective, fastest and fairest way to combat global warming. That said, we should all be concerned about our own “backyards”, and get to know them. The principle of "Think Globally, Act Locally" is a sound one. People will conserve and protect the places they know and love, i.e., the wild lands and neighborhoods around them. If every community installed rooftop solar, conserved energy, and cared for their “backyards”, we would achieve much toward reducing GHG emissions and confronting the climate crisis.

What is the difference between Net Metering and Feed-in-Tariffs?

Net metering is when a ratepayer receives a credit against their utility bill for energy they generate from rooftop solar or other onsite renewable energy generation. The credit is generally based on the current retail electricity rate with scant (or no) payment for generation above onsite consumption. If designed well, over time, a FIT will cover the full cost of the installation and provide a small profit to the owner/generator, similar to the profit that a utility would enjoy. In Germany 100% of the power generated on rooftops is purchased by utilities and the ratepayer-generator buys power from the grid in the usual way. The Australian system, in contrast, net meters for energy consumed onsite, and the ratepayer is paid a premium for energy generated above what it uses. FITs are a much more effective incentive for ratepayers to improve energy efficiency and install rooftop solar. A well-designed FIT can be a tremendous boon to community prosperity, as opposed to industrial wind and solar which impose large costs on local counties while diverting profits out of the community.

What is PACE?

A Property Assessed Clean Energy (PACE) bond provides upfront financing to residential and commercial property owners who wish to implement energy efficiency measures and install small (usually up to 1 MW) renewable energy systems.  The funds are repaid through an annual assessment (usually 20 years) on their property tax bill, making the loans extremely low-risk to the lender, and are generally paid from the property owner’s financial savings from the improvement.  If the property owner later sells, the assessment need not be immediately repaid out of the proceeds but instead stays with the property, making it extremely low-risk to property owners.  PACE bonds can be issued by state, county or municipal financing districts or finance companies and the proceeds can be used to retrofit both commercial and residential properties.  PACE is not a tax but rather a voluntary program where only those property owners who opt into the program are asked to pay.   Learn more about PACE and how to restore this type of financing at: http://pacenow.org/blog/

Industrial-scale solar power generation is economically feasible only because recent policy has brought massive taxpayer-funded subsidies to the table. Ironically, many of the names behind Big Solar that are taking advantage of this policy are familiar from the realms of Big Oil (BP and Chevron) and big bailouts (Goldman Sachs and Morgan Stanley).

Direct subsidies, loan and profit guarantees

Government subsidies have added significant momentum to the development of industrial-scale solar power generation on public lands.  A large commitment of American Recovery and Reinvestment Act (ARRA) funding has been allocated to subsidize solar projects. Initially, solar developers had been offered a 30 percent investment tax credit (ITC) as an incentive to develop new projects. However, because the recession slowed investment (and because investors complained they would not realize the benefits of the ITC for several years), the Administration decided to offer grants in lieu of the ITC for projects that could present substantial progress by certain deadlines. Many projects rushed toward the end-of-year deadline in 2010 to qualify for these grants, and funding was extended through 2011.  The government grants cover up to 30 percent of a project’s cost.

Some individual projects were chosen by the Administration to receive loan guarantees that by December 2011 totaled $5.85 billion for projects on public land and $4.72 billion for projects on private land.

Because it is believed no commercial banks are willing to extend these loans in the current economy, the lender is the Federal Financing Bank, a branch of the Treasury Department, and the guarantor will be the US Department of Energy. In other words, these risky loans are being made and guaranteed by taxpayers.

In November 2011, as the grant and loan-guarantee programs were about to expire, both economic doldrums and an emerging scandal imperiled the chances that the programs would be renewed. Solar-panel manufacturer Solyndra, which had received a loan and loan guarantee of $535 million had declared bankruptcy, and DOE was under fire for having failed to protect taxpayers’ interests when the department was aware of the company’s instability.

Whatever the fate may be of the loan guarantee and grant programs, in addition to taxpayer largesse, energy companies have the advantage of several built-in subsidies that guarantee profit. Power Purchase Agreements between the generators and the purchasers of energy guarantee power will be purchased for an established period of time. And transmission line projects are guaranteed both cost recovery (via ratepayers) and a return on equity that is generally between 10 and 13 percent (varying by state). Remote, industrial-scale projects that will require additional transmission-line development are thus especially lucrative.

New Rental Formula

In leasing, exchanging, or selling public land, the BLM is required to obtain Fair Market Value. In 2007, Interior issued an Instruction Memorandum (IM) outlining the process and regulations by which public land would be leased to solar developers. The IM explained that solar projects would rent rights-of-way on federal land, the same process that applied to uses such as pipelines and transmission lines. Appraisals would be conducted by the Interior Department and rent would be based on the appraisals and local market conditions pertaining to rental rates. Unlike transmission or pipeline corridors, however, where land use is only partial—allowing for other uses to continue under or over the installation—rents for the solar projects would be based on full use of the land.

In June 2010, the agency announced and initiated a new methodology for arriving at the rental fees solar developers would pay for public land rights of way.  The new rental rates would be based on two factors:  a “base rent” that was derived from county-by-county average agricultural land values, and a “Megawatt Capacity Fee” based on the MW size of the project. In the press release that announced the new methodology, BLM Director Bob Abbey stated that with this approach, “we are providing the solar energy industry the level of certainty it needs about the costs associated with projects on the public lands.” Indeed, the IM issued for the new policy listed rental rates by state and county for areas where solar development was proposed, eliminating the normal delay and potential uncertainty involved with a site-specific appraisal.

There is deserved controversy around the new fee basis. Using average agricultural land values is a significant departure from standard federal land appraisal methodology, which would likely base the land value on a “highest and best use” of rural-industrial development and would probably result in a higher value. Land values in the desert based on agricultural use would tend to be low.

On the other hand, the MW capacity fee appears to penalize projects that have higher capacity and include energy storage. In a statement to the press regarding the seeming illogic of this, a BLM spokesperson said, “the agency was following a mandated formula that takes into account the efficiency of a technology. And he noted that more efficient solar thermal power plants can have adverse environmental consequences like greater water consumption.”

Some bills introduced in 2010 proposed to use “lease sales”— such as those issued for oil and gas extraction on public lands, and obtained through competitive bidding—to determine the payment for solar development on public land. This approach is more straightforward than the new formulation, and by the very nature of competitive bidding, would be more likely to arrive at a Fair Market Value.10 None of these legislative proposals has yet succeeded.

Conclusion

Policymakers should closely scrutinize the scope of taxpayer funding for Big Solar. Developers clearly stand to gain with a system predicated on heavily-subsidized, concentrated, remote solar development on public land and large-scale, new transmission infrastructure with guaranteed return on investment. Whether taxpayers and the public interest benefit is less clear.

[We must do] everything we can to put the bulls-eye on the development of solar energy on our public lands.
– Interior Secretary Ken Salazar

The public lands that all American citizens hold in common are a unique manifestation of our history and values.  They also have historically been a battleground of the competing interests that lie along the spectrum between preservation and exploitation.

Ultimately, the concept of “multiple use” on public lands is well established and generally accepted to be the enduring policy. Public lands serve many, often incompatible needs and uses, including recreation, both mechanized and muscle-powered; wildlife habitat; mineral extraction; timber production; livestock grazing; watershed protection, and oil and gas development.  Indeed, the major mission of the Bureau of Land Management (BLM), which oversees vast areas of land in the western U.S., is to oversee and issue permits, leases, and rights of way for commercial uses of public land. Controversies over BLM-managed public land largely revolve around the tension between the agency’s utilitarian and conservation missions.

In the past few years, the government has shown new interest in advancing “renewable,” non-fossil-fuel energy, through wind, solar, and geothermal generation.  A key aspect of the policy is the assumption that much of this will occur on federal public lands managed by the BLM.  The 2005 Energy Policy Act called for the development of technology to deliver an additional 10,000 MW of renewable energy from public lands by 2015.  In 2010 and 2011, both the scope of proposed renewable energy development and the level of financial and political commitment increased rapidly. Shortly before taking office, president-elect Obama called for a doubling of renewable energy production by 2012.

The rush for renewables is also driven from the state level, where states have established Renewable Portfolio Standards (RPS) dictating increasing percentages of power be derived from renewable sources by certain dates. California, for example, established a 20 percent RPS by the end of 2010 and 33 percent by the end of 2020.

Both the Administration and the majority in Congress favor programs that will streamline and ramp up solar development on public land. S. 1642, a bill introduced in 2009 by Senator Jeff Bingaman (D-NM) sought to speed the permitting process by centralizing permits in one office per state and establish a pilot program of renewable energy projects where competitive bidding would be used for applicants to obtain leases of public land.

In late 2009, Senator Dianne Feinstein introduced a bill that would also centralize permitting and fast track some solar projects. While aimed mostly at a specific area of the California Desert, Feinstein’s bill was the first to include provisions that would distribute some of the proceeds from solar project leases on public lands to the state and county where the project is located. The bill bogged down in controversy over the fast-track provisions and was introduced again in 2011 without those features.

In November 2011, Senator Jon Tester (D-MT) and co-sponsors introduced S. 1775, the Public Lands Renewable Energy Development Act,  aimed at greatly expanding such development by calling for swift completion of the BLM’s Solar Energy Zones Programmatic EIS (see below), and for a similarly broad-scale analysis of suitable sites for solar and wind development on National Forest land. The bill also establishes a solar and wind leasing pilot program to determine the efficacy of opening up to solar and wind leasing any public land not otherwise precluded from such use by land use planning or special designation.

Clearly, expediting solar development on public land is an easy call for policymakers. There is seemingly no hesitation to commit whole swaths of public land to this purpose.

It is not inconsistent with existing policies that large solar power-generating facilities should be proposed on public lands,  particularly since vast areas of open space— with high and largely uninterrupted daytime insolation (sunlight intensity and duration)—are in the desert Southwest, where public land ownership is very high. The states in which federal land is targeted are California, Nevada, Arizona, New Mexico, Utah, and Colorado.

When lawmakers and business interests turn to public lands for utilitarian purposes, however, the many non-utilitarian values of the land can be easily forgotten or discounted.  What was recognized yesterday as treasured open space may now be perceived simply as empty real estate. Too easily and too often, policy-makers turn to public land as a cash-cow, a warehouse, or a liquid asset. In lean times, proposals to sell off public land will always arise, and big schemes are proposed to make use of land that seems to be wasted if it is not “in use.”

With 253 million acres in BLM-managed lands alone, it may seem that the public lands, and their potential for use, are endless. Yet much of this area is already damaged or fragmented by mining, urban encroachment, oil and gas operations, livestock grazing, motorized recreation, and other uses. Large, contiguous areas that retain their ecological integrity are increasingly rare: these are some of the areas most acutely threatened by large-scale uses such as industrial solar.

Both the climate crisis and our acute need to find alternative energy sources are relatively new phenomena; the headlong rush to make use of every square inch of public land is not.  We must find a way to address the former without perpetuating the latter.

Big Solar’s Footprint

The scale, intensity, and duration of impacts introduced by industrial solar are massive. Solar plants are proposed to be sited on public land for which the developer rents a right-of-way. However, unlike the typical right-of-way issued by the BLM— where a buried pipeline or an above-ground transmission line has a limited footprint that does not preclude other uses—industrial solar plants comprise near-total coverage (and total land-use conversion) on the sites they occupy.

The average utility-scale solar plant will occupy an area in the range of 2,000 to 3,600 acres, or 3 to 5.5 square miles. Although leased rather than sold to the developer outright, the site will be utterly transformed, completely converted to its industrial use, will no longer serve non-industrial functions, and will be off-limits to the public. In essence, public land used for these plants is no longer public. 

Moreover, even beyond the 30- or more-year duration of “virtual privatization” (the average lifetime of the projects), conversion to industrial use is essentially permanent. The environmental impacts are likely to be such that restoration to or recovery of previous ecological function cannot occur. (Indeed, the BLM has stated that ecological recovery can be expected to take 3,000 years). The sites may be permanently relegated to industrial uses. Having been stripped of the special qualities and functions we value in public lands, they will in effect become private industrial land.

In addition to the rights-of-way for the plants themselves, many miles of transmission lines will be proposed to carry the energy. Because it is not known which solar projects will ultimately be approved and constructed, the transmission-line mileage cannot be quantified. However, a decision on federal plans for energy corridors to be designated in the 11 western states (for pipelines, transmission lines, or both) proposes 6,000 miles of corridor on federal lands, about 5,000 miles of them across BLM land. The BLM has anticipated that land disturbance for transmission and road construction associated with a typical solar development is “likely to be limited to [a] corridor of 25 mi (40 km) length or less.”

Fast Track Projects

The first wave of high-profile solar projects were part of a “fast-track” initiative the Interior Department had announced in 2009, which would give priority to projects that had already made substantial progress through permitting. Many developers were rushing to meet deadlines that would qualify them for grants and loan guarantees offered by the Department of Energy, including big funding opportunities put forward as part of the Recovery Act economic stimulus.

In 2010, nine fast-track solar projects on public land were approved, all of them signed by Secretary Salazar rather than at the usual Field Office level. Six projects approved in California covered 21,324 acres, and three projects in Nevada covered 8,538 acres. In 2011, one project in California has been approved and involves 4,165 acres. The total area covered by approved fast-track projects is 34,027 acres.

Pending Projects

According to the most recent data provided by the BLM, more than half a million acres of public land are already under lease application for solar projects. Two of the six states where development is planned to occur, Utah and Colorado, do not yet have any pending projects.

The Solar PEIS and Supplement

The biggest policy initiative for solar development on public lands is embodied in the Solar Study Areas initiative, another one of the components of Interior’s aforementioned Fast-Track policy, and the associated programmatic planning effort.

Separate from the active projects described above, the BLM Solar Programmatic Environmental Impact Statement (PEIS) is a special planning-level project conducted under the National Environmental Policy Act (NEPA) that is looking at areas of BLM land with high solar potential and characteristics conducive to utility-scale solar plant development.  The PEIS is intended to result in the identification of the best areas for “solar energy zones” to be established, to analyze the potential environmental impacts of large-scale solar projects, and to propose standard litigation requirements projects must meet.  The selection of lands to be carried forward as established Solar Energy Zones (where solar applications would receive priority status over other uses) is supposed to ensure the exclusion of lands with environmental or other conflicts, such as endangered species habitat, visually sensitive areas, wildlife corridors, cultural sites, etc.

The Solar Study Areas (SSAs) as first conceived encompassed 24 land tracts in Arizona, California, Nevada, New Mexico, Utah, and Colorado. The areas with the most land under consideration lay in the Mojave, Colorado, and Sonoran deserts of California, Arizona, and Nevada.

The original SSAs contained a total of 676,000 acres, with more than half of the acreage in California, and 30% of the overall total concentrated in the Riverside East study area, which extends east from Joshua Tree National Park to the Colorado River. 

Late in 2010, as the release of the draft PEIS it was widely assumed, and regularly reinforced through statements from Interior, that the PEIS would begin with the 676,000 acres of SSAs and work from there to narrow appropriate lands for solar development, in the six states. Thus, the public was unprepared for the choice of a Preferred Alternative that would keep 22 million acres of public land – about 33 times as much acreage as the SSAs – open to lease applications.

The PEIS generated some 80,000 comments. In July 2011, Salazar announced approval of two solar, one wind power, and one transmission project and simultaneously announced that the BLM and DOE would be issuing a supplement to the draft PEIS that would address “key issues” brought forward in response to the draft and provide “enhancements” to the proposal.

In October 2011, the supplement was released, now with a preferred alternative that includes 285,000 acres in 17 Solar Energy Zones (most of the former SSAs) and an additional 20 million acres available under a variance process that would allow “well-sited” projects. 

Conclusion

Despite the considerable hoopla with which the new preferred alternative was announced, it only underscores Interior’s refusal to significantly limit the amount of public land made available for Big Solar.

Ultimately, not all of the public lands being eyed for solar development will be exploited for this use. Yet, driven by the real need to develop renewable energy, policymakers are clearing not giving adequate consideration to the consequences of turning public lands into an energy factory. It is essential that we not lose sight of the environmental impact and virtual privatization of public lands that could result from a heedless pursuit of remote, industrial-scale solar development.

• The concise briefing papers on this website can help you learn more about the many facets of Big Solar’s impacts and costs, as well as the alternative of Distributed Generation, and become an expert and citizen activist for truly clean, renewable energy.
• Pass this information along to your friends and networks, so we can get our message spread far and wide and get renewable energy policy turned toward a real solution to the climate crisis.
• Submit comments on blogs and newspaper websites, and send letters to the editor of your local paper.

Help re-shape national energy policy

Email or phone the office of your congressional representatives, both in the House and Senate. Check out these House and Senate committees and their energy and public land subcommittees and contact the chairs and any members from your state.  With your unique voice, let them know you oppose the use of our public lands as a solar-factory industrial zone.  Some facts and ideas to inspire you:

• Current proposals would place large-scale solar plants, most covering 5,000-7,000 acres apiece, on fragile, biologically-rich lands in the Mojave and Sonoran deserts and Colorado Plateau that are home to diverse, rare, and threatened species. Long-term plans are focused on developing hundreds of thousands of acres of our public land in Arizona, California, New Mexico, Nevada, Colorado, and Utah. These lands belong to all American citizens, no matter where you reside.
• Small, distributed, point-of-use solar is faster, more democratic, has far less environmental impact, and would benefit ratepayers and taxpayers.
• Other countries, particularly Germany, are way out ahead of the U.S. in using effective, efficient, environmentally-sound rooftop and urban solar as a major source of energy.
• The current policy is driven not by sense or effectiveness, but by politics and money. Big Solar will benefit huge corporations and investors – BP, Chevron, Morgan Stanley, Goldman-Sachs. Big Energy & Old Money can’t deliver us from the climate crisis they have helped create.
• Public lands now available for many uses will be transformed into permanent industrial zones. Even if the plants are dismantled following their 30 to 50-year operating life, the land they occupy can never be returned to its former state.
• U.S. taxpayers are funding billions of dollars in loans through the Treasury, backed up by loan guarantees from the Department of Energy, to kick-start solar plants that depend on unproven technology.
• Remote siting of solar plants will require literally thousands of miles of new transmission lines, also on our public lands. Long-distance transmission – not required for point-of-use solar power generation – is not only ugly and damaging, but extremely inefficient. Line losses can be as much as 7–10 percent.
• Our solar energy should be developed and generated from the built environment – rooftops, parking lots – and already degraded land.
• Construction of industrial-scale solar plants will itself directly and indirectly generate substantial greenhouse gas emissions.
• Remote, utility-scale solar cannot provide baseload power, only peak power. Further, there is no plan or requirement that these plants offset existing fossil-fuel energy sources, such as coal plants; they may add to power generation, but there will be no concomitant shutdown of dirty generators.

Contact your state legislators

We need to make rooftop solar easier for citizens and ratepayers. Your state regulations need to allow:

• Net-metering, under which ratepayers get credit against their energy bill for energy they generate.
• Feed-in tariffs, a policy requiring that utilities purchase power generated from renewable resources, including residential and commercial rooftops.

You can be even more effective if you identify the committees in your state legislative bodies that oversee energy or renewable energy issues and contact the chairs and staff. E.g., in the California State Senate, two relevant committees are Renewable Energy and Smart Grid, and the State Assembly has a Committee on Natural Resources that oversees renewable energy and energy efficiency.

Investigate local bulk purchase options

Though cost of installation of rooftop solar can be prohibitive, joining with others in your area to install in bulk can mitigate that expense, as well as providing policymakers with proof of substantial local interest in distributed generation. One way to do this is to sign up at One Block Off the Grid (1BOG.org), a solar consolidator. You can sign up with no obligation. When they reach a certain number of people who express interest in your area, they will set up a meeting to show you and your neighbors how it all works. If enough of you are serious about it, 1BOG sends out the group project as a Request For Proposals to several local installers. They will vet the proposals, materials, and companies and select one that makes sense. The discounts for contracting a larger project can run 15–20 percent off what you would pay if you hired the contractor on your own.

A solar strategy that would have been stateof-the-art in the 1990s, prior to the advent of low-cost solar photovoltaic (PV) power, is now being executed. This is a victory for the broad government, utility, and environmental organization support that solar thermal technology has gained over the last few decades. It is also a victory for the lobbying power of this coalition over economic common sense. Solar thermal has lost the cost-effectiveness race to solar PV. The federal government has not yet absorbed the significance of this important development.

The Department of Energy (DOE) is in the process of completing a potentially landmark study, the Solar Vision Study (SVS). It maps out a strategy to provide the United States with 10 to 20 percent of its electric energy from solar power by 2030. The document appears to be intended to serve as technical support for a national strategic commitment to solar thermal development.

However, the draft SVS, while containing much useful information, is flawed. The SVS proposes that half of the nation’s solar power will come from solar thermal installations, based on a low and unsupported cost-of-energy forecast for solar thermal plants. The SVS also presumes that the Southwest will be the hub from which this solar power is generated and transmitted to other parts of the country, while estimating an almost trivial transmission expense to make this happen.

Bias in the current administration’s ill-conceived use of limited ARRA funds to subsidize obsolete solar thermal technologies may explain why the draft SVS does not evaluate solar thermal technology with a neutral and critical technical eye. A revised and corrected SVS would envision a solar future that is effectively 100 percent solar PV. This PV future would also be predominantly smaller-scale PV connected at the distribution level, to avoid the expense of transmission. Otherwise, enormous costs for the new transmission capacity would be necessary to move remote Southwest solar power to demand centers around the country. The future is distributed PV if the strategic objective is the least-cost solar energy generated and delivered to the end-user. The Germans, Chinese, Taiwanese, and Japanese seem to understand this. It has not yet sunk in at the highest levels of the US government.

Outmoded Solar Thermal Gives Something For Everybody – At Taxpayer Expense

In the late 1970s and early 1980s, relatively high levels of funding were made available via DOE to develop a variety of solar thermal technologies, including parabolic solar trough, power tower, and solar dish (Stirling) engine. Demonstration projects were built and operated. Parabolic solar trough and power towers concentrate solar energy on a working fluid, heat it to a high temperature, and transfer that heat to water to generate stream. This steam is then run through a conventional steam turbine generator to produce electric power. Solar dish engines focus solar energy on an engine that uses hydrogen as the working fluid. The engine drives a small electric generator.

During the Reagan years, federal funding for solar thermal was substantially reduced.

Between 1985 and 1991, ultimately 354 megawatts of parabolic solar trough power plants were constructed in the Mojave Desert. These plants were financed with standard-offer, “must-take” utility contracts. Parabolic solar trough plants are the one form of solar thermal technology that has an extensive track record in commercial operation. The term “solar thermal” generally refers to parabolic solar trough plants unless additional clarifying information is provided.

California’s renewable portfolio standard (RPS) legislation, initially signed into law in 2002, gave new impetus to building solar thermal plants. The state’s greenhouse gas reduction legislation promulgated in 2006, targeting an 80 percent reduction in greenhouse gas emissions be 2050, provided further support. However, since 1991, other than one 64-megawatt solar thermal plant built in the Nevada desert in 2007 (Nevada Solar One) and two 5-megawatt demonstration plants built in California in 2008 and 2009, there have been no solar thermal plants built in the United States.

Development of large-scale solar thermal projects in the California desert in the 1980s established a framework for solar energy development—large, remote solar thermal plants requiring transmission to reach demand centers. The government solar thermal demonstration projects and commercial solar trough projects also established a constituency of solar thermal supporters—DOE, research laboratories contracting with DOE, aspiring solar thermal project developers, and major environmental organizations concerned about climate change. The investor-owned utility lobby is also supportive of remote utility-scale solar projects to the extent they require new transmission or major transmission upgrades that can be put into the utility rate base. The substantial political clout of this combined constituency is now bearing fruit in the form of ARRA loan guarantees and cash grants preferentially being directed to solar thermal projects.

Government subsidies for solar thermal projects would not necessarily be a negative development if these technologies remained the most cost-effective solar option for generating electric power. But that day has passed. Solar thermal has lost the cost-effectiveness race to solar PV. Subsidies spent on solar thermal technologies are wasted subsidies.

Showing Solar Thermal No Longer Competitive With Solar PV

CPS Energy, the San Antonio public utility, offers a case study in cost-based solar energy project selection. CPS Energy was developing a 27-megawatt Tessera Solar dish engine project in West Texas. The power-purchase agreement (PPA) between CPS Energy and Tessera was recently cancelled due to Tessera’s inability to get project financing at the agreed-upon PPA terms. The cancelled Tessera project was subsequently replaced with three 10-megawatt distributed PV projects to be built around San Antonio.

The PPA rate for the CPS distributed PV projects is $150 a megawatt-hour. There will be no transmission cost, as these projects will be built within the San Antonio demand center itself. San Antonio has a good solar resource. However, it is 10 to 20 percent less robust on an annual basis than Southern California coastal and desert sites.

What is true for San Antonio is even more so for Southern California. It has by far the most operational solar thermal capacity in the country and has been evaluating the cost of solar thermal projects in detail for years. Current cost-of-energy data developed by California energy authorities makes clear that solar thermal cost of energy is much greater than the cost of energy from the distributed PV projects being developed by CPS Energy.

The California Public Utilities Commission estimates the cost of energy from a base-case, dry-cooled solar thermal plant at a best-case Mojave Desert site in Southern California is $202 a megawatt-hour. The Commission estimates a new transmission cost of $34 to $46 a megawatt-hour to move this desert solar power to load centers. Transmission losses consume about 5 percent, the equivalent of $10 a megawatt-hour, of this remote solar energy production. As a result, the “all-in” cost of energy for this representative solar thermal project is approximately $250 a megawatt-hour.

In the Mojave Desert, the solar exposure is about 20 percent better than in San Antonio, while that for Southern California demand centers Los Angeles and San Diego is about 10 percent better. If the same three 10-megawatt distributed PV projects located in San Antonio were located in or near Los Angeles or San Diego, they would produce approximately 10 percent more electricity over the course of a year for the same capital and operations and maintenance cost. This means that the PPA rate of $150 a megawatt-hour at the San Antonio solar PV site adjusts to a PPA rate of about $136 a megawatt-hour at sites in or near Los Angeles or San Diego for roughly the same return on investment.

Few consumers would doubt which solar electricity option to select if one option delivers solar electricity at $136 a megawatt-hour and the other option produces the same commodity at $250 a megawatt-hour. The proposed solar feed-in tariff for the city of Los Angeles, which would include commercial rooftop PV, ground-mounted PV, and residential PV, has a 2010 composite rate of $220 a megawatt-hour and drops rapidly in future years. Even this proposed feed-in tariff is substantially less than the “all-in” cost of energy for solar thermal projects. Yet both the state of California and the U.S. government are making major strategic commitments to the highest-cost $250-a-megawatt-hour solar thermal option.

Solar Thermal Projects Built With ARRA Subsidies – Castles In The Sand

Investors laud the ARRA program for eliminating the investment risk associated with solar thermal plants. However, the investment risk is there in the first place because of questions about the cost-effectiveness of the solar thermal technologies relative to the better competitor— solar PV. Without ill-conceived government intervention, the obvious risks would kill these solar thermal projects. These technologies were cutting-edge at one time. They no longer are. A recent story on the critical role of ARRA loan guarantees and cash grants in making these solar thermal projects possible captures the frenzy of investors to cash in on the government’s largesse.

This first wave (of solar thermal plants) may very well be the last for a long time, according to industry executives.

Without continued government incentives that vastly reduce the risks to investors, solar companies planning another dozen or so plants say they may not be able to raise enough capital to proceed.

“I think we’re going to see a burst of projects over the next two months and then you’re going to hear the sounds of silence for quite a while,” said David Crane, chief executive of NRG Energy, on Wednesday after he announced that his company would invest $300 million in the Ivanpah plant.

Solar developers depend on two federal programs to make their projects financially viable. The most crucial is a loan guarantee program, expiring next September, that allows them to borrow money on favorable terms to finance up to 80 percent of construction costs.

The other is the option to take a 30 percent tax credit in the form of a cash payment once a project is built. Although the tax credit does not expire until the end of 2016, the option to take it as a cash payment disappears this year, making it far less valuable to a start-up company that is just beginning to generate revenue.

“Without the Department of Energy coming in to assume a lot of the risk, you might not find lenders willing to lend, particularly if you’re a start-up with untried technology,” said Nathaniel Bullard, a solar analyst at Bloomberg New Energy Finance. (Woody, T. [2010, October 28]. Solar power projects face potential hurdles. New York Times, http://www.nytimes.com/2010/10/29/business/energy-environment/29solar.html).

While the federal government pours funding into solar thermal projects, the superior cost-effectiveness of solar PV over solar thermal continues to increase. A renewable energy trade publication succinctly sums up the current state of the competition between solar PV and solar thermal.

The relentless price declines of PV panels allow developers to build PV plants at a lower cost than their CST (concentrating solar technology) cousins. This issue is illustrated in the following capital-cost-per-watt chart (an excerpt from the upcoming GTM Research CSP Report). In 2010, the price to build a CSP park run by troughs, power towers or dish engines will cost between $5.00 and $6.55 a watt.

On the other hand, utility-scale PV projects can squeak through at less than $3.50 a watt (DC). By 2020, the CSP solutions are expected to be in the $2.40 to $3.80 a watt range, but by that time, PV plants could be below $2 a watt (DC). Trough and tower plants are behind PV, and not likely to catch up. (Kanellos, N., & Prior, B. [2010, October 18]. Are solar thermal power plants doomed? GreenTech Media, http://www.greentechmedia.com/articles/read/is-CSP-doomed/).

DOE’s Study Is Playing Solomon When The Winner Is Not In Doubt

DOE released the draft SVS for review in May 2010. As of November 1, 2010, the final version of the SVS had not yet been published. The two fundamental premises of the SVS are the following: (1) it is possible to meet 10 percent or 20 percent of U.S. electricity demand from solar resources by 2030 and (2) this solar energy will be provided in approximately equal proportions from utility-scale solar thermal and solar PV power plants, with utility-scale solar PV plants providing a large majority of the PV capacity. The draft SVS does not look at a scenario where a substantial amount of the solar power is generated by distributed PV.

The agency invited peer review of the draft document from professionals working in the field of solar energy. Presumably this was done to validate the data and conclusions included in the draft SVS, and to allow DOE to make necessary adjustments in the final version to assure the document gained wide acceptance as technically accurate and sufficiently substantial to serve as the basis for national policy decisions on solar energy development. However, at least as of the date of publication of this article, DOE has determined not to respond to peer review comments until after the final SVS is released.

In its current form, which is a mix of accurate technical information and spectacularly optimistic solar thermal cost projections, the SVS will be of little value for policymaking. The lack of technical or cost support for building 43,000 to 63,000 megawatts of high-cost solar thermal projects by 2030, a fundamental thesis of the SVS, means the document runs the danger of being little more than a political advocacy piece for solar thermal promoters— cloaked in a DOE binder.

Half-Truths And Bad Information Abound

Much of the information in the draft SVS chapter on cost of solar PV is accurate and current. Selected but critical bits of information in the draft solar thermal chapter are contradictory and wrong.

For example, the SVS indicates graphically that solar thermal is substantially more cost-effective than solar PV. This was true in 1990 but false in 2010. The report also asserts that solar thermal plants equipped with thermal storage can have capacity factors as high as 50 percent, without clearly explaining how that could be possible using the conventional definition of capacity factor. This erroneous or misleading information is used as technical support for advocating that vast economic resources be committed to building sufficient solar thermal plants to contribute half of the nation’s solar electric output by 2030.

Solar Power At Night?

The capability of solar thermal plants to operate through the night if equipped with sufficient thermal storage is also put forward as a major justification. However, the SVS does not make an economic case for following this approach. Much of the electricity generated from the stored thermal energy would be produced at night during periods of low demand, when the solar thermal plant will be competing for market share with existing and much lower-cost nuclear, hydroelectric, natural gas combined-cycle, and some coal for decades to come.

In contrast, a strong economic case can be made for either solar thermal or PV plants to be equipped with limited storage to allow full capacity output during summertime peak demand periods when time-of-use power prices are high, assure reliability under all climatic conditions, and serve as nonspinning reserves. There is probably no economic case for building solar thermal plants or solar PV with more than two to three hours of storage until at least 2030. There is no economic justification now to equip a solar thermal plant so that it can convert high value daytime peaking power into lowest-value off-peak power released between 10:00 p.m. and 6:00 a.m.

“Capacity Factor” Mysteriously Redefined

The draft SVS uses the term capacity factor in an unconventional manner for a solar thermal plant with thermal storage. The document states that solar thermal plants without storage have capacity factors of 20 to 28 percent and that plants with 6 to 7.5 hours of storage have capacity factors of 30 to 50 percent. However, the high capacity factor for the solar thermal plant with storage is an artifact of what is in effect an artificial throttling of maximum output of the plant and not an almost magical increase in the ability of a solar thermal plant with storage to extract more solar energy from the sun.

Thermal storage is also expensive. The estimated average 2010 capital cost of a 200-mega watt dry-cooled solar thermal plant with six hours of thermal storage is $7,750 a kilowatt, 42 percent more than the capital cost of a solar thermal plant without storage. The estimated average 2010 capital cost of a 20-megawatt fixed distributed PV array without storage is $3,800 a kilowatt.

There is a nearly $4,000-a-kilowatt difference in the capital cost of these two solar options. Including lead-carbon battery storage to the PV system would add about $500 a kilowatt to the cost of the PV system. This means that adding three hours of energy storage, sufficient for the PV system to act as a completely reliable peaking power system when electricity demand and power prices are high, would add around $1,500 a kilowatt to the PV system cost. The overall system cost of the PV system with three hours of storage would be $5,300 a kilowatt. This is well below the $7,750-a-kilowatt capital cost of the solar thermal plant with storage while providing economically “right-sized” energy storage capacity tailored for current and foreseeable energy market conditions.

In a plant with thermal storage, the quantity of solar troughs is oversized for the steam turbine generator such that some of the thermal energy must be transferred to storage. For example, a collector array with capacity sufficient to meet the steam requirements of a 100-megawatt steam turbine generator is instead designed and constructed with a 70 megawatt steam turbine generator, and the rest of the thermal energy is sent to storage. This is equivalent to operating a 1,000-kilowatt PV array, sending a maximum of 700 kilowatts to the grid, and diverting the remaining electric power to battery storage for later use. Storing energy for later use is not a unique characteristic of solar thermal technology. The total amount of heat energy produced by the solar thermal plant without storage rated at 100 megawatts is the same as that produced by a solar thermal plant—with the same collector array—that is equipped with a 70-megawatt steam turbine generator and thermal storage to absorb the heat energy not immediately converted into electricity. Yet the solar thermal plant with storage is credited in the draft SVS with a capacity factor that is as much as double the capacity factor of the solar thermal plant without storage. This creates confusion and the illusion that solar thermal with storage achieves a much higher capacity factor than a plant without thermal storage.

Transmission Cost Way Off The Mark

The draft SVS projects that the total new transmission cost will be only $44 to $47 billion to develop solar resources predominantly in the Southwest to deliver 485 terawatt-hours and 824 terawatt-hours to primarily eastern load centers. California is currently projecting it will spend $27.5 billion for sufficient transmission to move 24 terawatt-hours of solar generation to California load centers, and California solar resources are relatively close to these load centers. Extrapolating real California transmission cost estimates to 485 terawatt-hours of solar generation gives a projected transmission cost of (485 terawatt-hours/24 terawatt-hours) × $27.5 billion = $556 billion. Extrapolating real California transmission cost estimates to 825 tera watt-hours of solar generation gives a projected transmission cost of (824 terawatt-hours/24 terawatt-hours) × $27.5 billion = $994 billion. The SVS must be more realistic in its estimate of the cost of transmission or it will present an erroneous picture of the total cost to policymakers and the general public.

Land-Use Arguments Faulty

The SVS excuses large consumption of land for solar thermal by saying it is less than is being consumed for coal mining each year. This statement has two implications: (1) construction of solar thermal will result in a concomitant reduction, at least, of land disturbance due to coal mining and (2) solar thermal is less destructive than land disturbance caused by coal mining and therefore affected parties should accept solar thermal as an inherently better option for the general national good than coal.

There are a couple of problems with this justification. First, the SVS concedes that solar power will displace natural gas, not coal; therefore, no coal mining disturbance will be reduced because of the construction of solar thermal. Second, affected parties are by definition local and are unlikely to link the negative environmental impacts caused by solar thermal development and associated transmission lines to a lessening of environmental impacts (which the SVS indicates will not occur anyway, at least under one of its scenarios) in a distant part of the country. This lack of justification is especially true given that many of the affected parties in areas where large amounts of solar thermal are being planned are already aware that the distributed PV alternative could provide the same amount of electricity with lower overall cost and almost no environmental impact.

False Claim—Solar Thermal Necessary Quickly For Environmental Reasons

California provides a useful case study of the urban legend that only large-scale solar plants can provide the rapid capacity build-up needed to address climate change. The California Public Utilities Commission reference case to achieve 33 percent renewable energy by 2020 includes 10,000 megawatts of new solar capacity. The large majority of this capacity is assumed by the commission to consist of utilityscale desert solar thermal plants. This 10,000 megawatts of new capacity will be added over ten years, an average of 1,000 megawatts added each year. Promoters of the utility-scale desert solar thermal strategy relentlessly stress that only utility-scale solar plants can add capacity quickly enough to achieve California’s ambitious renewable energy targets and effectively address climate change.

Approximately 2,800 megawatts of utilityscale solar thermal projects have been approved by the Department of Interior (DOI) as of October 2010. All of these projects are in California deserts. DOI land-use authorization is a necessary step for any solar project that will be located on federal public lands under Bureau of Land Management control. Many of these projects will also receive ARRA loan guarantees and cash grants. Approximately 1,400 mega watts of this capacity consist of Tessera dish engine projects. In my opinion, despite the loan guarantees and cash grants, these dish engine projects are unlikely to be built due to the technical immaturity and relative unreliability of the technology.

About 17,000 megawatts (21,000 mega watts [DC]15) of PV were installed worldwide by the end of 2009. In contrast, the worldwide capacity of solar thermal at the end of 2009 was 664 megawatts. Most of this solar thermal capacity was built in California in the 1980s and early 1990s.

Other Nations Opting For Solar PV

While California and the federal government work hard to preferentially advance the cause of high-cost solar thermal, the world is building lower-cost solar PV.

Germany, which is approximately the same size as California, added about 4,000 megawatts of distributed PV in the first eight months of 2010. The vast majority of German PV is going on rooftops and parking lots. The mechanism that Germany is using for this spectacular PV installation rate is a feed-in tariff. This is a tiered rate paid by the utility to the solar developer, commercial building owner, or homeowner that provides modest profit for the solar power generated. As noted earlier, the feed-in tariff proposed for Los Angeles would produce substantially lower-cost solar electricity than the Commission’s predominantly solar thermal reference case.

By the end of 2010 Germany will have added approximately 10,000 megawatts of distributed PV in the three-year period from January 2008 through December 2010. While California lumbers forward with a high-cost, controversial solar strategy built around remote utility-scale solar thermal plants, with the hope that 10,000 megawatts can be built in ten years, Germany is demonstrating now that 10,000 megawatts of distributed PV can be added in only three years. Germany has also become a world leader in solar PV development. The country generated $7.8 billion in export earnings from solar PV (€5.6 billion) in 2009.

Former Secretary of State George Shultz and former CIA Director James Woolsey are both calling for German-style feed-in tariffs to accelerate the use of solar power in the United States. Governor-elect Jerry Brown of California called for 12,000 megawatts of local renewable power, out of 20,000 megawatts of new renewable energy capacity, in his June 2010 Clean Energy Jobs Plan. The German feed-in tariff program is leading to fast and noncontroversial deployment of solar power.

Conclusions

The current federal government preference for solar thermal plants, which would have deservedly faded away without massive government subsidies in the form of ARRA loan guarantees and cash grants, is the wrong strategy. Solar PV is a more cost-effective solar technology, and the gap in cost-effectiveness between solar PV and solar thermal will continue to grow. DOE’s draft SVS, intended to provide the technical support for an ambitious national strategy to meet up to 20 percent of the nation’s electricity demand with solar power by 2030, is flawed in its treatment of solar thermal technology. An unsupported and low forecast of solar thermal cost is used in the draft SVS as a basis for advocating the construction of up to 63,000 megawatts of solar thermal capacity by 2030.

A strategy focused primarily on distributed PV would be the most cost-effective approach to rapidly expanding solar power production in the United States. Germany has demonstrated that a spectacularly high distributed PV installation rate is sustainable when an appropriate contract structure, the feed-in tariff, is utilized. Feed-in tariffs are cost-effective relative to solar thermal. The cost of solar electricity generated under a proposed feed-in tariff for Los Angeles would be significantly less than the “all-in” cost of electricity from utility-scale solar thermal projects in California’s deserts.

It is time for the United States to stop wasting limited resources on obsolete solar thermal technologies and to embrace the formula for solar success pioneered by Germany.

[This briefing was first published in the National Gas And Electric Journal. Reprinted with permission of the author.]

The U.S. could avoid the elevated economic and environmental costs of remote utility-scale solar power development, and greatly expand the direct involvement of individuals and communities in renewable power generation, with a policy that favors distributed PV. Priority development of solar PV and solar hot water heaters within our built environment (cities and towns), combined with high value energy efficiency measures, could meet much of U.S. clean energy and greenhouse gas emission reduction targets.

This paper highlights the cost and environmental advantages of distributed PV, on rooftop and smaller in-city installations, over remote utility-scale solar power. In light of the recent and ongoing tragedy in the Gulf, we should be wary of energy projects – conventional or renewable – that can permanently alter healthy, functioning ecosystems when there are cheaper, cleaner, safer, and more reliable alternatives. In the case of solar power, the U.S. can accomplish the dual goals of improving the economy and improving the environment by prioritizing the deployment of distributed PV.

I. When all costs are factored in—including new transmission infrastructure and line losses—local, distributed solar PV (both polycrystalline and thin-film) is comparable in efficiency, faster to bring online, and less expensive than remote utility-scale solar thermal power or remote utility-scale PV plants.

Residential rooftop solar, the democratically owned solution: Residential solar PV is much more cost-effective now than most policy makers realize. For example, the residential rooftop solar consolidator 1 Block Off the Grid (1BOG)  reported the following actual installed costs in Watts direct current (Wdc), prior to any rebates, tax credits, or other incentives, for 2009:

These 1BOG prices, specifically the 4 kW residential PV systems sold in the San Antonio area at $6.00/Wac, already approach the capital cost estimate for a 200 MW dry-cooled solar thermal of approximately $5.50/Wac (see Table 1). In addition, solar PV prices are projected to drop at a much faster rate than solar thermal prices over time. Both the California Energy Commission and the Department of Energy project that solar PV prices will drop by half between 2010 and 2020, while solar thermal prices are projected to decline much more gradually. 

Comparison of net energy output: “Higher solar insolation,” meaning higher solar radiant energy, is the most common reason put forth for siting remote utility-scale solar projects in locations like the Mojave Desert. Yet transmission losses largely negate higher insolation and higher capacity factors of solar projects in Mojave Desert locations compared to the slightly lower solar insolation in urban centers like Los Angeles, Riverside, and San Diego.  Transmission losses average 7.5% (average) to 14% (peak) in California.  The difference in solar insolation between the Mojave and Southern California urban centers is approximately 10%, in the same range as expected transmission losses associated with remote solar projects.  This means there is no substantial difference in the net electric power delivered to customers from remote utility-scale solar plants in remote Mojave Desert locations and rooftop PV installations in Riverside or Los Angeles (for projects with the same rated capacity). 

Transmission costs

New transmission infrastructure needed to carry solar-generated energy from remote locations to urban demand centers entails substantial costs. These costs are borne by ratepayers, with actual costs for new California transmission lines currently running at ~$11 to ~$24 million/mile. 

A power delivery strategy that concentrates on large generation and transmission projects to meet load leads to substantial over-building, as projects are often justified on aggressive load growth projections that indicate new electricity supply will be necessary 5-10 years in the future.  This approach is highly profitable for investor-owned utilities (IOU), which are guaranteed a healthy rate of return for “steel in the ground” infrastructure projects like transmission and generation. Local installations such as rooftop or parking lot solar PV reduce peak load at the source of demand and thereby reduce or eliminate the need for additional conventional generation and transmission infrastructure. It is no surprise given how IOUs make money that these utilities are generally opposed to expanded development of local solar power.

Subsidies and externalized costs

Large-scale remote solar projects are preferred by Southwestern IOUs over local solar primarily because of the revenue that such projects can generate indirectly in the form of new IOU-owned transmission capacity. These large-scale remote solar projects enjoy a number of direct and indirect subsidies that are too seldom taken into account. These include federal cash grants and loan guarantees; exclusive use of public lands and resources designated for multiple use; waivers of millions of dollars in state application fees; and externalization of costs onto local communities and ecosystems.

Timeframes

Large-scale remote solar projects and related transmission lines take many years to complete.  In contrast, distributed PV can be brought online quickly.  Germany, using a simple and effective feed-in tariff (FIT) contract structure to spur cost-effective development of distributed PV, installed nearly 4,000 MW of distributed PV in 2009 and may install as much as 6,000 MW in 2010. 

Needed action

The Solar Done Right Coalition requests that permitting of all remote utility-scale solar projects and associated transmission projects be suspended on public lands, with the exception of proposed projects on Superfund sites or brownfield sites. Concurrently, solar energy subsidies and policies should be redirected to advance point-of-use solar solutions in the built environment to reflect the greater value of local solar to communities, ecosystems, the economy, and the climate crisis.

II. Large, remote solar projects could permanently reduce natural uptake of carbon by the desert environment cleared for development. In contrast, increased efficiency and distributed solar PV will reduce carbon emissions without this tradeoff.

Desert ecosystems may sequester substantial amounts of CO2: Researchers at the University of Nevada Las Vegas have been monitoring carbon uptake in Mojave Desert ecosystems for the past seven years and have consistently found substantial uptake, processing and sequestration of carbon.  Likewise, wetland and grassland ecosystems, such as those found in Colorado’s San Luis Valley (targeted for industrial solar development), are well-known for their ability to uptake and store CO2.  More study is needed to determine how much carbon uptake will be lost when thousands of acres of natural desert cover are converted to scraped earth and covered with solar collectors. To the extent that the lost carbon uptake is substantial, it undercuts the greenhouse gas reduction justification for building the solar facility at that location.

Transmission infrastructure emits greenhouse gas SF6: Sulfur hexafluoride (SF6) is the most potent greenhouse gas evaluated by the Intergovernmental Panel on Climate Change,  and eighty percent of the SF6 in the atmosphere derives directly from electrical transmission infrastructure.  With an atmospheric life of 3,200 years, one pound of SF6 has the same global warming impact of 11 tons of CO2 and nothing sequesters it.  The Environmental Protection Agency has identified SF6 as one of six emissions most critically in need of regulation.  With policies favoring transmission, the U.S. may contribute to a surge in unnecessary SF6 emissions.

Remote utility-scale solar construction and operation creates substantial emissions: Emissions from the manufacturing, transportation, construction, transmission, and operations associated with remote utility-scale solar are substantial.

For example, over 4 years of construction, the 370 MW Ivanpah solar project in California will release 17,779 metric tons of CO2-equivalent emissions, with additional operating emissions of 27,444 metric tons of CO2.  During the construction of the 250 MW Blythe solar project, 103,900 metric tons of CO2-equivalent emissions will be released. The project will cause a loss in carbon uptake of about 8,806 metric tons of CO2 per year due to vegetation removal, plus 14,789 metric tons of CO2-equivalent for operations. Decommissioning is expected to emit nearly as much again as construction.  These projects are not benign with regard to environmental impacts.

Emissions are reduced only if the offset power is not used: The EPA has set forth its requirements for accounting for emission reductions which can be used as a guideline :

“… emission reductions from offset projects [must] meet four key accounting principles—they must be real, additional, permanent, and verifiable.”

Needed actions

The Solar Done Right Coalition requests that the GAO immediately undertake a comprehensive, cradle-to-grave analysis of the total emissions related to all aspects of remote utility-scale solar development and associated transmission, and compare these to the total emissions derived from producing an equivalent amount of intermittent power from local PV, hydro and high-efficiency natural gas. The EPA’s accounting requirements should apply to all remote utility-scale solar projects proposed. The solar developers and utilities buying the power should be required to demonstrate that the EPA accounting requirements will be met before a construction permit can be issued. Calculations should be based on actual outputs in verifiable kWh, rather than rated capacities.

Pending completion of the GAO study, neither federal funding, including loan guarantees and investment cash grants, nor construction permits should be issued to projects for which the National Environmental Policy Act (NEPA) or other relevant federal environmental laws have been wholly or partially overridden on the basis of presumed reduction benefits from these remote utility-scale solar projects.

“Fast-tracking” of remote utility-scale solar projects, based on the untested presumption of overwhelming reduction benefit, should be immediately halted.

The EPA should study the phase-out of SF6.

The 2005 Energy Policy Act should be amended to (a) site the mandated 10,000 MW of clean energy production described in the Act on federal buildings and federal properties within the built environment rather than on public lands; and (b) repeal the National Interest Electric Transmission Corridors provisions.

III. Distributed generation, supported through Feed-in Tariffs (FITs), Property Assessed Clean Energy (PACE) loan financing, and expanded net metering would be more effective than remote utility-scale solar in creating renewable energy and addressing the climate crisis.

FITs are proven to work quickly, economically, and reliably: FITs provide a simple contract mechanism for individual homeowners and business owners to profitably install as much solar PV as their buildings/properties will allow, maximizing the potential of rooftops, parking areas, and brownfields in urban and suburban environments. Germany installed over 714 MW of solar PV in the three months of 2010, 80 percent of which is rooftop systems under 100 kW. This is more PV than was installed in that country during the first half of 2009.  Even as its solar PV tariffs shrink, Germany continues to increase the amount of PV installed. The reason for this is the rapid decline in the cost of PV systems. As stated earlier, DOE currently projects that the cost of solar PV systems will drop by half between 2010 and 2020.  The steadily declining German tariff for solar PV reflects this market reality. 

A recent study done by the Los Angeles Business Council and UCLA indicates that 3,300 MW of rooftop solar is currently “economically available” for German-style FITs for Los Angeles. The study indicates that the FITs program would create over 11,000 local jobs.  Modest feed-in tariffs would also cost ratepayers very little. The UCLA study projects an average monthly additional cost of only $0.48 per month for households and $9.37 per month for business and industry for the first 10 years of the proposed 600 MW FITs program. Based on historical and projected price increases in natural gas and the rapidly declining cost of solar PV, after 10 years a net savings to all ratepayers is projected. 

Germany’s numerous rooftop installations, supported by generous feed-in tariffs, have had minimal impact on non-generating ratepayers,  while providing unprecedented gains in clean energy generation and jobs creation while providing a reasonable return on investment for PV system owners.

PACE loans make local efficiency and PV improvements possible: PACE (Property Assessed Clean Energy) loans that allow ratepayers to amortize the costs of rooftop solar and efficiency upgrades over 20 years and repay them along with property tax payments have proven very popular where offered. There is no cost to taxpayers or other ratepayers, and virtually no risk to lenders or borrowers. Unfortunately, Freddie Mac and Fannie Mae (FM) have suggested that because property tax assessments take the first lien on the applicable property, PACE loans will pose a threat to the supremacy of mortgages held by these agencies.  Although California and other jurisdictions are demanding that FM treat these funds like any other property tax assessments,  FM’s current position has resulted in a collapse in PACE loan funding.

Expansion of net metering programs would help in the interim:  All states that establish or maintain RPS to meet clean energy goals should account for all net metered clean electricity and off-grid power as eligible power for meeting RPS goals, not simply as “demand reduction” as is currently done. By failing to count clean, net metered solar power as renewable power, such programs create an artificial preference for large, central-station power plants. 

Community benefits of local focus are substantial: In addition to improvements in property values and the creation of well-paid local jobs from efficiency upgrades and local solar PV, the local focus provides “green energy premiums” to communities, rather than merely profiting large corporations. This stimulates a cycle of local spending, local jobs creation, debt reductions, and other tangible economic benefits. 

Needed actions:  Fannie Mae, Freddie Mac, and FHFA must immediately reverse their positions on PACE loans.  These loans should be classified similarly to local bond issues (which also take first lien as part of a property tax assessment) and not as “loans” for purposes of seniority of lien.  Substantial additional federal funding for PACE loans should be made available to stimulate job creation, decrease energy consumption and emissions, and bolster sagging property values to keep families in their homes. PACE is a very strong tool with which to meet stated societal, economic, environmental and political goals, and ongoing PACE funding should be made available immediately to lead our nation down the path to sustainability.

FITs similar to Germany’s should be implemented nationwide, with fair tariffs and simple contract requirements, so that system owners receive return on investment for doing the right thing. Amendments to the Public Utility Regulatory Policies Act could be made to ensure that fair market value, based on cost of generation, and access to the grid are afforded to all Americans willing to invest in this nation’s renewable energy infrastructure.

Policies like the California RPS, which has largely been a failure to date, should be discarded in favor of well-crafted FITs.

Net metering should also be standardized, expanded and improved as an interim step until fully functional FITs are in place. Understandably, states will want to administer their own programs, but there should be some Federal minimum standards established to ensure that national objectives for greenhouse gas reduction are being met. 

Conclusion

This is an overview document. More detail is available in the reference documents, reports such as the study recently prepared by the Sierra Club of California on the economic benefits of local solar power compared to remote utility-scale solar power, as well as materials and updates which will be periodically made available on our website http://www.solardoneright.org. 

Some of what we know of the potential impacts, and most of what we know about the quality of environmental analysis being conducted, has come from the environmental review documents for large solar power projects now requesting certification by the California Energy Commission,  and from reviews by the California Public Utilities Commission .

Energy development footprint

Utility-scale solar thermal and photovoltaic developments are typically designed in the 200 to 500 megawatt (MW) range with project footprints of 1,000 to 7,000 acres. Meeting the goal of 80,000 MW of concentrated solar thermal generation under California’s 33% RPS will require 500,000 acres of land. Such large impact areas on desert lands will have lasting effects on the viability of species, habitats, and ecosystem functions. As explained in the accompanying brief on public lands, the total public land area under application for industrial-scale solar as of July 2010 was just under 1.1 million acres.

Transmission footprint

The new transmission line rights-of-way associated with many projects constitute a significant and often-ignored impact of industrial desert solar. Almost all existing transmission lines from large solar projects will need to be upgraded, causing widening and new linear desert ecosystem disturbance far from actual project sites, and multiplying environmental impacts.

Impact on the environment

Impacts are summarized in these categories:

1. Soils
2. Water resources
3. Desert ecosystems
4. Air quality
5. Significant species
6. Corridors
7. Important bird areas
8. Visual and sound pollution

Soils

Parabolic-trough solar thermal power plants require 100% vegetation removal and grading to remove features such as low hills and swales and create uniform topography. Even so-called Low Impact Design projects using heliostat-mirrors aimed at central power towers, Stirling engine dishes, and ground-mounted photovoltaic arrays require scraping areas around fixtures and for access roads. The results are soil compaction, soil removal, and erosion.
In a preliminary Low Impact Design of Ivanpah Solar Electric Generating System in California, approximately 412,600 cubic yards of vegetation would be mowed and mulched, and 245,000 cubic yards of soil would be cut, moved, and filled — enough material to fill Yankee Stadium three-quarters full.

Proposed project sites are often located in flood plains or on alluvial fans that convey stormwater between mountains and valleys. Many projects are proposed to be built over ephemeral mountain and desert washes which carry large floods. Flood-control measures such as berms, artificial cement channels, detention basins, and soil-cementing provide an additional source of ecosystem disruption in such areas.

Water Resources

Water for cooling tower “makeup” — flushing the cooling towers of accumulated salts and sediments — process water makeup, and other industrial uses such as mirror and panel washing would be supplied from on-site groundwater wells. It is uncertain how much make-up water will need to be added in closed-system solar thermal plants: the steam system would have to be blown down (water drained to maintain chemical and solids levels in boilers). If dust problems have been underestimated, mirrors may have to be washed more often to maintain optimal operating conditions. At some plants mirror washing has to be conducted as often as once a week.

The Abengoa Mojave Solar Project proposes pumping water for wet-cooling from the Harper Lake Basin’s aquifer, so critically in overdraft that it is in adjudication. The Ridgecrest Solar Power Project proposes to use drinking water from the Indian Wells Valley Water District city water supply tank, which pumps wells in a basin also in critical overdraft.

Even in basins that are not yet overdrawn, a single project could have significant impacts. The Ivanpah Solar Electric Generating System facilities would require pumping groundwater from a new well for water lost in the dry-cooling process, and wash water for the heliostats, as well as potable water for power plant worker water needs. Approximately 16,000 gallons of water per night would be used for mirror washing, almost 6 million gallons per year, or 18 acre-feet. Estimates for mirror-washing water run as high as 42.6 acre-feet per year.

Solar thermal plants will need evaporation ponds or blow-down ponds associated with generator cooling. Solids and chemicals associated with rust control procedures will accumulate in this ponded water. They can enter the groundwater and affect drinking water supplies and aquifer water quality.

Desert Ecosystems

Many solar projects are proposed for sites in the Mojave and Sonoran deserts that have rich and diverse biological resources. These include large intact areas of creosote-bursage scrub that are relatively free of weeds, have only light (and easily reversible) livestock grazing, see little off-road vehicle use except on designated tracks; and have no other development disturbance. Rare plant communities exist on many of these sites. Ephemeral streams contain unique plant associations that provide valuable wildlife habitat.

Cryptobiotic crust, a surface crust of soil particles bound together by organic materials, is a critical — and fragile — component of the desert ecosystem. Crusts are predominantly composed of cyanobacteria, green and brown algae, mosses, lichens, liverworts, and fungi. They contribute to soil stability, atmospheric nitrogen fixation, nutrient contributions to plants, and soil-plant-water relations. Living soil crusts also store CO₂ and their removal may reduce organic offsets to anthropogenic greenhouse gas emissions. Once removed or disturbed, cryptobiotic crusts are slow to recover. On sites in the Mojave Desert disturbed 82 years ago, some species of lichen have yet to re-colonize the slowly regrowing crusts.

It is proposed that when power plants are decommissioned and facilities removed, restoration and revegetation will be conducted on the sites, but restoration has been found to be problematic at other sites in arid ecosystems with large-scale disturbance, such as open-pit mines.

Desert and high elevation valley environments provide “ecosystem services” — environmental processes and resources that we often take for granted, such as providing pollinators for crops, maintaining biodiversity, contributing to climate stability, and preserving and building soils and maintaining watersheds and flood control. Only when they are lost to development such as large-scale solar plants do we recognize how essential they are.

In Colorado, the San Luis Valley contains one of the largest complexes of wetlands in the Southwest.  The value of wetland ecosystems as carbon sinks is well established.

Regional Air Quality

Original desert soils are a sink for dust until mechanically disturbed. Large-scale disturbance of desert soils would result in an increase in wind-borne dust. Many projects are located in air basins with federal designations of “nonattainment” for federal particulate matter (PM2.5 and PM10), and state-level ozone nonattainment. Without adequate fugitive dust mitigation, projects have the potential to exceed the PM10 threshold during construction and operation, and could cause localized exceedances during construction. Under the National Environmental Policy Act (NEPA), this potential exceedance of federal air quality standards would be considered a direct, adverse, significant impact. Erosion from clearing is likely to substantially increase the amount of airborne particulate matter during strong wind events. To control dust, large amounts of water will have to be used on roads and scraped areas. Soil binders and dust suppressants will also be used during operation to control dust: petroleum-based products will have long-term impacts on soils, making restoration of vegetation problematic; while less-toxic organic and water-based suppressants are only 80-90% as effective with and must be reapplied every two to three years, thus increasing the facility’s water use.

In Colorado, increased particulates blown onto surrounding snow-covered peaks have accelerated spring snowmelt.  The dust absorbs heat from sunlight and melts the snow more quickly.  This could have detrimental effects on the region’s agricultural sector.

Significant Species

State and federal protected species, and rare or sensitive species identified by Bureau of Land Management, state agencies, and organizations like California Native Plant Society, and the Colorado Natural Heritage Program, are often present on project sites. These include species such as desert tortoise (Gopherus agassizii), Mojave ground squirrel (Xerospermophilus mohavensis), burrowing owl (Athene cunicularia), golden eagle (Aquila chrysaetos), LeConte’s thrasher (Toxostoma lecontei), Gila monster (Heloderma suspectum), Mojave fringe-toed lizard (Uma scoparia), flat-tailed horned lizard (Phrynosoma mcallii), bighorn sheep (Ovis canadensis), and many rare native plants, including a lupine in the California desert that may be new to science. Because many projects are on a fast-track schedule, time may not be allotted to carry out surveys in late summer and autumn when many plants flower after monsoonal rains; many species may thus be missed. In certain counties, cacti and yuccas are protected and must be transplanted out of project footprints. Several of these species and genetically unique populations are under review for listing by US Fish and Wildlife Service, and cumulative solar project development will only increase the need for protection.

Problems and confusion concerning mitigation for such species have arisen several times for many projects. At the Ridgecrest Solar Power Project, for example, mitigation for desert tortoise and Mojave ground squirrel has been unresolved even after several workshops hosted by BLM and the California Energy Commission, with US Fish and Wildlife Service and California Department of Fish and Game in attendance. Questions have arisen about how enough land would be acquired for habitat mitigation and translocation of animals off the construction site. Many enhancement measures (such as tortoise exclusion fencing) are untested or have not worked, raising concern among biologists regarding whether the mitigation fund and habitat acquisition would actually provide any benefits to species. A mitigation fund further abstracts the actions taken on lands elsewhere from the impacts on the project sites. Agencies have not yet determined how to match up actual project impacts to large regional mitigation programs without violating legal protections for species.

Wildlife Corridors

Biologists have recognized the importance of maintaining the integrity of wildlife corridors, which enable animals to migrate and thus allow gene flow among populations. Survival of a species depends on resilience of its populations to environmental fluctuations, and this resilience is bolstered by large areas of habitat, movement corridors, and connectivity of genetic populations so that natural variation in the species can allow adaptation to changes. Resilience is reduced by habitat fragmentation, degradation, and competition from invasive species such as weedy plants increasing on lands disturbed by development (a new impact in desert ecosystems).

Building large solar projects in Chuckwalla Valley, for example, involves more than just removing Mojave fringe-toed lizard habitat. These animals are specialized on sand habitat, and cannot survive on rocky ground. Several solar projects will block part of the sand corridor, where sand is blown gradually over the years by winds from dry lakebeds and stream channels.

Bighorn sheep and desert tortoise both need migration corridors to move between mountain ranges. The cumulative impacts of renewable build-out in Ivanpah Valley could reduce the widespread tortoise population to small, isolated fragments of populations with no gene flow between them. Such circumstances can lead to extirpation of these small populations, as inbreeding increases and leads to reduced fitness and lack of resilience to natural disasters, disease, and climate change.

The sheer size of these solar facilities will create barriers between populations and potentially disrupt eons old migration patterns. As local populations are lost or isolated, linkages are lost. Connections between metapopulations (groups of local populations) must be kept intact. In the past, biologists looked at the size and quality of patches, but now there is more interest in the “matrix,” the areas between patches that provide connectivity.  The size and quality of habitat patches has been shown in studies to be a poor predictor of occupancy, and the matrix may be more important.

Many proposed solar projects would be located squarely in the middle of connectivity corridors: the Ridgecrest Solar Power Project, for example, would block a major connectivity area for the Mojave ground squirrel. Mitigation measures cannot actually mitigate very site-specific qualities such as connectivity. Certain projects have been sited directly in unique corridors that connect genetic populations of a species—other lands cannot replace this function.

Important Bird Areas

The potential impacts on avian species of industrial-scale energy development are of significant concern. The National Audubon Society has identified areas vital to bird species — including common and game species as well as rare species — and designated them as Important Bird Areas (IBAs). Clark Mountain in the East Mojave Peaks IBA, with monsoonal-influenced montane forests, is a critical breeding area for birds not found elsewhere in California, and is also adjacent to the proposed three-tower Ivanpah project.

Migratory Hepatic tanagers and Whip-poor-wills have rare breeding populations on Clark Mountain. No studies have been undertaken on how migrating birds would be affected by burn injuries sustained from flying through the beams of concentrated sunlight, although it is known that migrating or foraging birds have been burned to death flying through the superheated beams of sunlight aimed at central receiver towers at the much smaller Solar One installation formerly at Daggett, California.  With no information, no mitigation plan can be developed.

The San Luis Valley, Colorado serves as a major biannual stopover point for over 30,000 migrant Sandhill Cranes (Grus Canadensis tabida) as well as other migrant species, such as White-faced Ibis (Plegadis chichi), Black-necked stilt (Himantopus mexicanus) and other waterbirds that breed and nest in the Valley.  The impact of square miles of solar arrays on the San Luis Valley migrant bird populations is largely unknown but potentially significant and irreversible.

Visual and Sound Impacts

In the San Luis Valley retreat and agricultural tourism is a vital and growing part of the regional economy.  In addition, many residents have moved to the area to leave urban life and enjoy the area’s beauty.  Industrial solar development on the scale currently being proposed there will change the rural character of the region and degrade world-class visual and historical resources. Tessera Solar is proposing to install over 35,000 40-foot-high SunCatcher units, each powered by a 4-cylinder Stirling Engine. The noise levels produced could adversely impact a nearby community with over 24 internationally renowned retreat centers as well as the Great Sand Dunes National Park, the quietest National Park in the nation. 

There’s a right way and a wrong way to do just about everything, however. In the deserts of the American Southwest, most of the large-scale developments on the drawing board have been proposed for public lands, the bulk of those lands previously undeveloped.

Advocates of solar and wind energy development in fragile wildlands often refer to their projects as “renewable energy” development. In the strictest possible sense, the term is accurate: solar power will be abundant as long as the sun shines, and wind will blow across the landscape for about as long. But expand the scope of the discussion a bit and the validity of the term “renewable energy” becomes more doubtful. The energy transformed into electric power may be renewable, but what of the other impacts the power generating stations may have? In desert wildlands especially, development of massive industrial power generating facilities involves damage to the landscape that may take centuries, or millennia, to heal — if it ever does.

If energy company interests proposed cutting down redwoods for biomass conversion, or filling Yosemite Valley with a reservoir in order to generate hydroelectric power, most environmentally concerned people would scoff derisively. The redwoods would certainly grow back, and snowmelt would almost certainly recharge the Yosemite reservoir each year, but few people would limit their assessment of the projects’ “renewable” nature to the specific sources of energy harnessed. Most people would demand that the assessment of the “renewable” nature of the energy project address the nature of the habitats destroyed in order to install the power generating capacity — the old-growth redwood forest, the meadows and sheer rock walls along the Merced River — and the continuing damage to those ecosystems from those projects’ daily operations. We would ask how long it would take for those old-growth redwoods to grow back. We would ask how long it would take, once the Yosemite Dam was eventually removed, for the Valley floor’s ecosystem to regain its grandeur. And we would likely ask ourselves whether a forest 3,000 years in the making, or a valley four times that old at a minimum, were really worth losing for a few extra megawatts.

In the Bureau of Land Management’s California Desert District, just the handful of solar and wind energy project proposals that have been “fast-tracked” — chosen by the Obama administration for accelerated permitting and regulatory approval — would destroy just under 59,000 acres of publicly owned desert wildlands in the Mojave and Colorado deserts. All told, that’s more acreage than is occupied by the city of Lancaster, California. Sprawly Palm Springs occupies only a few dozen acres more. That’s a huge amount of land. Even more would be affected by the new transmission lines the projects would require. And that’s just the fast-tracked projects. Overall in California, the BLM is examining more than 350,000 acres of public land for solar energy development — an area larger than Los Angeles slated for possible habitat destruction in the name of “renewable energy.” Many more hundreds of thousands of acres are being studied in other Western states.

Let’s take a look at some of the aspects of those landscapes that this “renewable” gold rush would damage.

Desert aquifers

Fifteen thousand years ago the climate in Western North America was much different. The California deserts were far wetter; freshwater lakes filled many of the desert’s basins. Water from those lakes, and from the relatively greater runoff and snowmelt from the desert’s fringing mountains, pooled in large aquifers in the deep alluvial soil of the valleys. Most of the great pluvial lakes in the southern part of the desert dried up by about 7,500 years ago, but the aquifers they had left behind remain to this day, water tables sometimes several hundred feet beneath the desert valley surface. One such “fossil water” aquifer, beneath the Amargosa Valley, feeds the renowned springs at Ash Meadows, Nevada, home to the endangered Devil’s Hole pupfish. 

Annual recharge of these aquifers — the amount of water present-day precipitation adds to the total — is quite limited. In the Ivanpah Valley, for instance, astride the California-Nevada line south of Las Vegas, the total annual recharge of that valley’s aquifer amounts to an average of 800 acre-feet a year, according to one estimate. This water comes almost entirely from precipitation falling on the nearby Clark, New York, Ivanpah and Spring ranges. Eight hundred acre-feet sounds like a lot of water. However, the Ivanpah Valley groundwater basin spans more than 400,000 acres. Eight hundred acre-feet of water would raise the water table on an aquifer that size by about half a millimeter.

At that rate of annual recharge, it would take thousands of years to fill the Ivanpah Valley’s aquifer. Most aquifers throughout the desert, aside from those recharged by more well-watered mountains such as the Sierra Nevada and Transverse Ranges, are recharged at similarly slow rates. Desert groundwater from these aquifers is thus best considered a nonrenewable resource.

Artesian springs supplied by these fossil aquifers provide a crucial source of water without which wildlife would suffer. In places where humans have developed the desert, these aquifers are chronically overdrafted: settlements, agricultural irrigation, livestock watering, mining, resort development, and even golf courses all add to the demand on this precious and limited resource.

Whether they are photovoltaic or concentrating thermal in design, industrial solar facilities depend on regular cleaning in order to run at peak efficiency. Even a thin layer of dust on PV panels or mirrors can cut output by a considerable amount. Though research continues into dust-repellant coatings and dry cleaning methods, getting rid of dust means hosing down the relevant pieces of equipment. And in most of the desert, unless the facility is on the Colorado River or an aqueduct therefrom, that water will come up out of a well, adding to the demand on already overdrafted groundwater. Concentrating solar thermal facilities may use water either to drive steam turbines or for cooling, or both. Though engineering advances in concentrating thermal solar technology will likely make the installations far more water-efficient, the amount of water current designs use may be considerable. A plant proposed for the Amargosa Valley by the Solar Millennium corporation would have required 20 percent of that valley’s groundwater. Even the Ivanpah Solar Electric Generating Station, which would use air-cooling techniques to increase water efficiency, is expected to consume at least 100 acre-feet of water each year — an eighth of the annual water budget in the Ivanpah Valley.

If production of industrial-scale solar electricity requires such massive use of a nonrenewable resource, calling the result “renewable energy” seems deceptive.

Old-Growth Desert Vegetation

Visitors to the desert often assume that the wizened-looking large plants there are immensely old. As it happens, many of the most prominent desert plants — outside of the altitudinal range of the piñon-juniper forest, at least — have surprisingly short lifespans. Joshua trees and saguaros are good examples, with average lifespans below 150 years. Ocotillos, one of the more notable large woody plants in the Colorado Desert, endure for about the same length of time.

Desert shrubs, however, often outlive their larger tree companions by a considerable margin. In a 1995 study of woody plants in the Grand Canyon in which landscapes documented in 19th century photos were rephotographed, researchers found that a wide range of desert shrub species reached ages of more than a century. These included catclaw acacia (Acacia greggii); bursage (Ambrosia dumosa); fourwing saltbush and shadscale (Atriplex canescens and A. confertifolia); the cacti Echinocactus polycephalus, Opuntia acanthocarpa, O. basilaris, and O. erinacea; Ephedra; desert thorn (Lycium andersonii); Yucca angustissima; and, a bit surprisingly, the bunchgrass big galleta (Pleuraphis rigida).

A few desert shrubs have lifespans more properly measured in millennia rather than centuries. The best-known of these is the creosote bush, Larrea tridentata. Creosote stems put out side shoots every so often, expanding the plant’s width. As a creosote bush gains in width and the center of the plant eventually succumbs to old age, the shrub becomes a ring of stems and foliage. By measuring the ring’s width and dividing by the annual growth rate, the age of the ring can be determined. King Clone, a creosote ring near Landers with an average diameter of 45 feet, is estimated to be approximately 11,700 years old — placing its germination back in the last pluvial period, when freshwater lakes dotted the desert. 

Another long-lived, slow-growing species, the Mojave yucca (Yucca schidigera), also forms clonal rings. Estimates of the growth rate of Mojave yucca rings vary widely, but it’s relatively safe to conjecture that many such rings exceed 2,000 years in age. Clumps of Mojave yucca with a probable age of 1,000 years are widespread throughout the species’ range.

To be thorough, any discussion of slow-growing desert life must at least mention cryptobiotic soil crusts. These obscure communities of cyanobacteria, mosses, lichen and fungi stabilize soils, fix nitrogen that can then be used by other desert life, and slow runoff of rain and snowmelt. Cryptobiotic crusts are extremely fragile: a stray footstep can break a centuries-old crust, making the soil beneath it vulnerable to erosion by wind and water. Even a slight disturbance in a cryptobiotic crust can take many years to heal. A film of cyanobacteria can recolonize a damaged area within a decade, but the full complement of lichens and mosses may take as long as three centuries to regain its former vitality. It’s worth noting that burial by wind-driven soil is a major threat to cryptobiotic crusts. Bulldozing a swath of desert landscape for industrial energy generation may well cause a swath of continual downwind damage to such crusts, compounding over time as more crust dies and releases the soil beneath it.

Vegetative communities

As an old-growth redwood forest is more than a collection of large trees, so the old-growth desert is more than a collection of shrubs. The broad alluvial fans and plains so tempting to the alternative energy developers are often the home of plant communities that may have taken a staggeringly long time to develop.

At elevations too high or latitudes too cold for creosote to thrive, the unassuming shrub blackbrush (Coleogyne ramossissima) will often cover huge areas in an almost unbroken mantle. These thick stands of Coleogyne are unprepossessing, even uninteresting to the average traveler. They feed wildlife with their seeds and provide nurse-plant shelter for other desert plants, Joshua trees a prime example, and as far as even most desert aficionados are concerned, that is the extent of their interest. 

In 1987, Robert H. Webb, John W. Steiger, and Raymond M. Turner published the results of a study of disturbed areas west of Death Valley. Some of those areas had been disturbed by human activity in the late 19th century, some by debris flows in the last few thousand years, and some by debris flows of Pleistocene age. They determined the rate at which desert plants recolonize disturbed areas. They found that Coleogyne is very slow to revegetate areas from which it had been stripped.

Webb, Steiger and Turner found that blackbrush took as long as “tens of thousands of years” — their words — to revegetate up to 20 percent cover in the areas they studied. Other studies have reaffirmed their findings. The consensus is that the thick, uniform stands of blackbrush so prevalent in the high deserts probably took from 5,000-10,000 years to develop.

Individual blackbrush plants may live as long as 400 years. They grow slowly, and “recruitment” — successful reproduction with offspring surviving to maturity — is rare. Biologists who’ve studied the species have suggested that blackbrush reproduces in “pulses,” its seedlings surviving best in years with heavy early spring rains. Those conditions may well have been more prevalent toward the end of the last pluvial, when — if current thinking is correct — at least some of the current stands of blackbrush got their start. As Webb, Steiger and Turner said it: “Time span for [vegetative] recovery [of blackbrush stands] may be longer than past periods of climatic and geomorphic stability.” Some of the blackbrush stands in our deserts have been developing since there were standing lakes in the Mojave with sabertooth cats and ground sloths drinking out of them. Their replacement under current climatic conditions may take even longer.

That’s if those communities come back at all. Desert ecologists famously refer to the still-visible tank tracks left more than half a century ago by the US Army, training under General Patton during World War II. The Army’s wartime impact on the desert extended beyond making tracks. A few miles northwest of Needles at Arrowhead Junction, the military established Camp Ibis — part of the Desert Training Center — in 1942. The camp was decommissioned two years later. Building the camp involved blading large swathes of creosote-Mojave yucca vegetation for an airfield, building footprints and a network of roads. Though all structures were removed in 1944, the extent of the blading is still clearly visible in current satellite photos. Native plants have colonized much of the cleared area, but those plants are very different from the ones removed. Despite abundant creosote and Mojave yucca surrounding the camp and providing a source of seeds for revegetation, the cleared areas are carpeted mainly in burro weed (Ambrosia dumosa), which may inhibit the germination of other plants by outcompeting them for soil moisture. It may be that once disturbed or destroyed, desert landscapes in areas such as the former Camp Ibis will never regain their original ecological composition.

Conclusion

Our deserts are irrigated by water that fell thousands of years ago. Their slopes are covered in vegetative assemblages that have been developing for a span of time far longer than recorded human history, and some of the individual plants in them are almost that old — older than the rightly venerated ancient redwoods; older, some of them, than the oldest bristlecone pines. Once altered, those plant communities may never return to their original state even under optimal conditions. If the desert’s aquifers and vegetative communities are forever changed, the animal wildlife that has evolved dependence on local springs, plant habitat and edible vegetation — desert tortoises, bighorn sheep, and a raft of other vulnerable species — will suffer.

Losing a few thousand acres of old-growth desert would be a shame, yet hundreds of thousands of acres in the California desert are being studied as possible alternative energy sites. Given the permanent damage to an ancient, irreplaceable ecosystem that would result from industrial energy development in desert wildlands, it’s time we stopped calling such development “renewable energy.”

Capacity Factors and Transmission Losses

Before we describe how industrial solar plants incur their greenhouse gas debts, we should clarify common misunderstanding about the rate at which those plants pay off their debts with “carbon-free” energy. Industrial desert solar plants are routinely described as having projected output many times higher than the likely actual figure. This is because many descriptions of the plants’ capacity fail to take into account their “capacity factors,” which is the factor by which one must multiply their rated maximum output to take into account times when the plant will be unable to generate power at the optimal capacity.

For example, the proposed Ivanpah Solar Energy Generating System is billed as a 370 megawatt (MW) generating plant once it is completed. That figure is accurate, in that the plant probably will generate 370 megawatts of power around noon on a cloudless day in mid-summer, when the sun is as close to directly overhead as possible. But when the sunshine striking the plant is less energetic, for instance during winter, on cloudy days, during night, early morning and late afternoon hours, the plant’s output will be significantly less. During high winds, which happen frequently in the Ivanpah Valley, the mirrors will need to be secured, rendering the plant inoperative. The plant will likely need frequent maintenance, which reduces output during times when it is offline. Utility experts refer to this kind of correction for actual real-world output as a plant’s capacity factor. Coal and nuclear plants commonly have capacity factors in the 60-90% range: they can run non-stop near peak output for weeks on end. Solar plants’ capacity factors run closer to about 25-30% at best. The California Energy Commission estimates the likely capacity factor of the Ivanpah SEGS as around 28%.

For this very reason the figures often cited in news articles referring to solar plants’ output with a phrase such as “enough to supply 400,000 homes” are almost always misleading, if not completely incorrect. To determine how much generating capacity is needed to power a certain number of homes, the relevant unit isn’t megawatts, but megawatt-hours. A 100 MW solar plant with a capacity factor of 30% will produce only a third the megawatt-hours produced by a 100 MW coal plant with a 90% capacity factor. Most homes don’t use electricity only when the sun shines; in fact, they often use more when it doesn’t. Tying solar-plant power generation to a certain number of homes is largely meaningless. (Conversely, since rooftop PV systems are often used in conjunction with batteries to store energy, you can say each rooftop produces enough electricity to power a home).

Adding to — or more accurately, subtracting from — the issue of lower-than-anticipated delivery of energy from these sites is the problem of transmission inefficiency. As high-voltage electricity flows through transmission lines, a significant percentage of its power is lost due to resistance in the conductor. Average transmission losses in the North American grids are somewhere around 6.5-7%.  Moreover, resistance in a transmission increases as its temperature rises, and summer temperatures in the deserts are routinely 20-30 degrees F higher than elsewhere on the continent, with afternoon highs above 115F not uncommon. Under such circumstances, losses in power transmitted from desert industrial solar plants may be considerably higher than the US average.

Concrete

The concrete used in solar installations is a large contributor to the GHG burden. Concrete is a mixture of sand, gravel or aggregate, and cement, which is produced by heating limestone to about 1450°F. This process contributes a large amount of CO₂ to the atmosphere, both from the energy consumed to heat the limestone and as the heated limestone gives off CO₂. The cement industry is the second largest CO₂-emitting industry, after power generation, producing about 5% of global man-made CO₂ emissions.  The amount of CO₂ emitted by the cement industry is nearly 900 kg of CO₂ for every 1000 kg of cement produced.  High-quality concrete used in industrial applications may be as much as 25% cement.  Such concrete weighs approximately 2400 kg per cubic meter, and thus each cubic meter of concrete used in construction of solar power facilities contributes 540 kilograms of CO₂ to the atmosphere solely from the production of the cement included. That’s more than the maximum amount of CO₂ the state of California allows a coal-fired plant to emit per each megawatt-hour of energy produced. 

A cubic meter of concrete is a cube measuring a meter (about 39 inches) on a side. A standard cement truck holds six cubic meters. Concrete will be used throughout most remote solar sites in significant quantities as footings for equipment, foundations for buildings, berms and culverts to divert flash floods, and for other purposes.

In addition, transporting the concrete from supply yards to the construction site incurs a significant additional CO₂ contribution, especially at remote sites not served by rail.

Transportation

It is not only concrete that must be shipped to the site of a large desert solar installation, but all building materials not extracted from the site itself must be shipped in, often across considerable distances. Some sites of proposed public-land renewable energy projects in the desert Southwest are 50, even 100 miles from the nearest communities with substantial workforces. This means that unless barracks housing is built on the site — with additional environmental cost — commuting workers add to the CO₂ debt the project must be accounted for, especially during the construction phase.

Sulfur Hexafluoride

One of the least-known greenhouse consequences of industrial-scale solar generating facilities — or indeed of any high-voltage industrial facility — is the use of sulfur hexafluoride, or SF₆. SF₆ is an inert, non-toxic gas five times heavier than air that is used as a reliable gaseous insulator in high-voltage transformers, circuit breakers and switchgear.

Though it is inert and thus non-toxic, SF₆ does pose a toxicity risk to people and wildlife under certain circumstances. If exposed to high-voltage discharges SF₆ molecules can be bonded, forming disulfur decafluoride — a highly toxic gas once considered for possible use as a chemical weapon.

The main danger SF₆ poses, however, is to the climate. SF₆ is 23,900 times as potent a greenhouse gas as CO₂, making it the most potent greenhouse gas the Intergovernmental Panel on Climate Change has evaluated.  In other words, a pound of sulfur hexafluoride contributes as much to global warming as 11 tons of CO₂. SF₆‘s overall contribution to the global GHG problem is relatively small, likely contributing to less than one percent of total warming from all sources.  But in the context of power generation projects which purport to reduce greenhouse gas emissions, SF₆ emissions become particularly relevant — especially if those projects require long-distance transmission, which accounts for around four-fifths of SF₆ emissions.

There are almost no natural “sinks” for SF₆ — it is not taken up by living things or absorbed by water, soil or rock — so it stays in the atmosphere until it breaks down, which can take as long as 3,200 years.

SF₆ leaks out of pressurized switchgear and circuit breakers over time, and is also released to the atmosphere during maintenance, replacement of equipment, and — most notably for determiningthe greenhouse gas burden of new industrial-scale energy projects — during installation of new equipment. While older circuit breakers may hold up to 2,000 pounds of SF₆, more modern designs such as those that would be installed for new generation and transmission facilities cut that to around 100 pounds.  The EPA estimates that even the most aggressive leak detection, repair and recycling programs could only cut SF₆ emissions by about 30 %. 

As most SF₆ emissions are generated in long-distance transmission of electrical power, the more remote a new facility is, and the more additional miles of transmission line needed to deliver its power to the grid, the higher the SF₆ burden of each new generating facility will be. In 2010 the EPA estimated average emissions of between .58 and .89 kilograms of SF₆ for every mile of transmission line per year over the last decade.

As an example of direct impacts of industrial solar projects on SF₆ emissions, consider the proposed Tessera Solar project at Calico, in California’s Mojave Desert, which would place tens of thousands of solar-heated Stirling engines on 8,230 acres of public land.  Tessera itself projects that through routine leakage from circuit breakers on the site, its project would emit 36 pounds of SF₆ into the atmosphere each year — the equivalent of 384 tons of CO2.  The actual figure, given wear and erosion of seals in the desert’s intense heat, UV radiation, and wind-driven sand, is likely significantly higher—and that only accounts for emissions from the project site. In order to transmit the energy created at Calico to the grid, the adjacent Southern California Edison Pisgah Substation would be expanded from five acres to 40 acres, an eight-fold increase in size and likely similar increase in routine SF₆ emissions.

Distributed generation, naturally, by drastically reducing the need for new transmission lines and substations and perhaps even allowing the decommissioning of older lines, offers an opportunity to curb SF₆ emissions dramatically in the long run.

Water

Water use at industrial solar facilities is mainly a concern due to oversubscribed streams and aquifers. The additional demand on local water supplies by big solar plants often puts wildlife in danger of losing the springs and seeps on which they rely. Yet there is a greenhouse gas aspect to water as well. In the arid and semiarid West, prodigious amounts of energy are used to move water from one place to another. In California, fully 20% of the state’s electrical consumption results from the pumping, transport, purification, and treatment of water.  Energy used to transport water to industrial solar facilities will either be supplied from non-solar sources, in which case it adds to the facilities’ greenhouse debt, or it comes from the facilities themselves, in which case that power cannot be counted toward paying down that debt.

In the deserts, excepting those places adjacent to the already oversubscribed Colorado River or its aqueducts, water used in industrial solar facilities will almost always be pumped groundwater. (A preposterous example of this is Tessera’s proposed Calico plant, the water for which would be pumped from the Cadiz aquifer sixty-five miles away, and then shipped to the site by rail.)  In 2005, Robert Wilkinson of the University of California, Santa Barbara estimated the typical energy consumption of wellwater pumping in southern California’s Chino Basin at 2,915 kilowatt-hours per million gallons,  a figure likely similar to those for the deserts’ deeply buried aquifers.

Water consumption at industrial solar power plants varies widely by the type of plant. Concentrating solar thermal facilities may use water either to drive steam turbines or for cooling, or both. Conventional solar thermal technology is found in both “wet-cooled” and “dry-cooled” forms. The amount of water a wet-cooled plant uses may be considerable. The existing Solar One plant in Boulder City, Nevada, a wet-cooled 64-megawatt capacity solar trough field, consumes about 400 acre-feet each year. An acre-foot of water is that amount that would flood an acre of land a foot deep, or 325,851.4 gallons. To pump the 400 acre-feet of water Solar One uses each year, if we use Wilkinson’s Chino Basin pumping energy consumption estimate, would consume close to 380 megawatt-hours of power.

Dry-cooled plants use ambient air to cool their boilers rather than water. This saves a considerable amount of water, but not without cost. Dry-cooled facilities often involve more extensive infrastructure to channel convecting air, and they become less efficient as the air temperature rises — which is, ironically, not only the time when the facility would ideally be most productive, but also the time when electric power demand is likely to peak.

Even dry-cooled plants still use a lot of water. The Ivanpah Solar Electric Generating Station, which would be a dry-cooled plant, is expected by its promoters to consume at least 100 acre-feet of water each year —an eighth of the total annual water budget in the Ivanpah Valley. 

Whether they are photovoltaic or concentrating thermal in design, industrial solar facilities depend on regular cleaning in order to run at peak efficiency. Even a thin layer of dust on PV panels or mirrors can cut output by a considerable amount. The aforementioned project at Calico, which would involve shipping water by rail, is billed as a “no-water-use” project using Stirling engines, but despite those engines’ putatively water-free operation the project’s 34,000 solar dish mirrors will still need cleaning, and this — along with fire protection, creation of hydrogen for the Stirling engines, and drinking water for workers — is why water would be shipped from Cadiz.  Though research continues into dust-repellant coatings and dry cleaning methods, getting rid of dust requires hosing down the relevant pieces of equipment. The cleaning method may add a significant amount to the facility’s greenhouse debt. At Ivanpah, plans are to drive diesel-powered water trucks through the facility every so often to spray the mirrors, adding that diesel fuel to Ivanpah’s GHG debt.