The California Public Utilities Commission voted 5-0 to approve two power purchase agreements between developer BrightSource Energy and Southern California Edison. The contracts will see power flowing from the yet-to-be-built Rio Mesa 1 and Sonoran West. At the same time, the commission rejected Edison’s request to approve three other contracts with BrightSource.

Edison actually sought approval for all five contracts, totaling 1,000 MW, back in 2009, when energy storage played no part. Then it re-negotiated the contracts with BrightSource in 2011 after BrightSource had modified those power plant proposals to reduce their environmental impact.  This time around, energy storage made its way into three of the contracts.

The decision was a compromise. The commissioners were set to vote on the five contracts back in August, but postponed it because they were wrestling with which of the five they should approve. The commission’s own staff recommended approving contracts for three projects that would include storage and denying two projects that wouldn’t have storage. With energy storage, a utility could bank electricity when demand is low and release the power when demand is high. It makes a solar power plant act more like a conventional fossil fuel power plant, which can produce power any time of the day.

So while using storage will add cost and increase the price of a contract, its benefits outweigh the expenses, the commissioners said, particularly since California requires its utilities to increase the amount of renewable electricity in their supplies until it reaches 33 percent by 2020. Under law, utilities need to provide power reliably to their customers regardless of the sources of their electricity.

But commissioners didn’t see their vote for the five contracts as quite so black and white. One issue was the contract pricing and the other one was a more philosophical deliberation about how to chart a path to cleaner and more affordable energy by 2020. Commission President Michael Peevey came up with a compromise plan and won the support of the four other commissioners.

The contracts for Rio Mesa 1 and Rio Mesa 2, totaling 400 MW, are way pricier than bids submitted to Edison while it was renegotiating with BrightSource, the commission noted in its proposed decision. But the commissioners didn’t want to say no to both contracts because BrightSource plans to use newer technology that it says will use land more efficiently and therefore reduce its projects’ environmental impact. The commissioners wanted to give BrightSource a chance to use the new technology, so during its Thursday vote, it approved the contract for Rio Mesa 2 but said no to Rio Mesa 1.

The commissioners also said no to two of the three projects, Siberia 1 and Siberia 2, that contain energy storage because those two are proposed for a location that would likely require an upgrade of the transmission lines there in order to deliver power from the two solar farms. That upgrade would be so expensive as to “render the projects infeasible,” the commission said. The remaining project with storage, Sonoran West, is priced competitively against competing bids, so the commission voted for it.

Allowing BrightSource to use the new technology and storage is important for the state to get cleaner and cheaper power in the future, the commissioners said. Commissioner Mike Florio, who usually cites high prices as the chief reason for voting against certain contracts – he cast the lone “no” vote for the solar power contract between Abengoa and Pacific Gas & Electric last year – said he supported Peevey’s compromise because it promises a clear progression toward lower-cost solar power.

“Here the path is directly visible.” Florio said during deliberation Thursday. “I normally don’t support ratepayers having to pay for technological risks, but we will have to take some risks like these.”

Winning those contracts is crucial for BrightSource to raise money for building those plants. Investors will more likely put up money if they know BrightSource already has found buyers for its projects. Incidentally, the company announced yesterday that it had raised an equity round of $80 million. The company is building its first solar power plant called Ivanpah, in California.

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California lawmakers passed a bill in late 2010 that fell short of requiring utilities to invest in energy storage but did  give the California Public Utilities Commission the task of looking into whether a mandate is a good idea and what that mandate should be. The commission on Thursday approved a proposal that identified 20 ways that electricity storage could benefit the grid and consumers. That decision then kicked off a new round of discussion that could eventually lead to an energy storage mandate and turn California into a prime market for many types of battery and other storage technologies.

Similar to the existing state mandate that requires investor-owned utilities to buy or produce more and more renewable energy over time, an energy storage mandate could very well require the same utilities to put money into technologies that could store electricity for short and long-term use. For example, utilities could build their own energy storage systems or buy services from owners of energy storage farms. Ultimately, the costs of investing and using energy storage will be passed on to consumers.

The idea is to use energy storage to complement the growing amount of solar and wind electricity that is flowing into the grid. Solar and wind energy production can be intermittent because it depends heavily on weather conditions. That intermittency worries utilities and grid operators because an electric grid runs smoothly only when there is a balance of supply and demand — it’s something that is easily achieved with fossil fuel power plants because they can produce electricity around the clock. The grid now is not well equipped to handle big surges or quick declines of solar and wind energy.

Electricity from an energy storage system can help to maintain that supply-demand balance in minutes at a time, become a go-to power source when demand is particularly high (such a hot summer day), or serve as a backup power supply during blackouts (see the 20 uses identified by the commission).

The energy storage bill signed by then Govt. Arnold Schwarzenegger in 2010 was apparently the first legislation in the country to look at how energy storage might be necessary for meeting a state’s goals to increase its use of renewable electricity. The new law (PDF) was a watered-down version of an initial effort to require the state’s investor-owned utilities to use energy storage. Instead, the law requires the commission to start the process of determining whether energy storage is necessary for the investor-owned utilities by March 1, 2012. The commission has until Oct. 1, 2013 to adopt an energy storage procurement target if it deems storage necessary. If that happens, utilities will have until the end of Dec. 2015 to meet the first target, and the end of 2020 for the second target. Municipal utilities and public utility districts, which aren’t regulated by the commission, also have to follow similar deadlines.

Understandably, the state’s three biggest utilities – Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric – oppose setting energy storage targets. And so does the Division of Ratepayer Advocates within the commission.

The utilities argue that public subsidies can actually slow down the development of better and cheaper technologies. The Division of Ratepayer Advocates noted that “Picking arbitrary procurement levels, such as a MW [megawatt] level or a percentage level would most likely result in sub-optimal market solutions and increase costs to ratepayers without yielding commensurate benefits.”

You can be sure to hear a lot more debates about whether a mandate will help or hurt storage technology development and deployment. A lot of federal and private money has gone into energy storage technologies, particularly in the field of rechargeable batteries, because they are betting that electric cars and renewable energy storage will become big business. Just earlier this week, the U.S. Department of Energy announced a new round of battery technology funding.

The commission plans to hold a workshop on energy storage on Aug. 20, and another meeting is scheduled for Sept. 4.

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Actually, very fast. Since 2003, 2,871 MW of renewable electricity generation capacity has been installed to meet a state mandate, and about 11 percent of those came online during the first half of this year alone, according to a just-released state report. Another 2,740 MW are scheduled to come online by the end of 2012.

What’s the rush? The state mandate requires its investor-owned utilities to have 20 percent of their electricity from renewable sources by 2010 and 33 percent by 2020. The three big utilities – Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric – didn’t hit that goal by the end of 2010. But then, they had a three-year grace period. One of the highlights in the report is that, indeed, the Big Three reached that goal in 2011 (they filed their procurement report to the state in March this year).

Chevron, BrightSource solar oil plant, the tower and the mirrors

It’s been a lengthy and difficult lesson for the utilities and state regulators to figure out what projects are likely to succeed, how much money ratepayers should pony up for clean power and what the overall processes should be in place to distinguish the good projects from the bad. All these efforts are on-going, of course, because unforeseen issues will always pop up that require policy makers to tinker with the rules.

The report focuses only on the state’s renewable energy mandate for its investor-owned utilities, so it doesn’t include clean energy installations that fall under other state programs. For example, rooftop solar installations that serve businesses and homes aren’t counted in the report.

The state’s hunger for renewable energy has made it the home to some of the largest solar farms in the country. First Solar is building a 550 MW project in San Luis Obispo County and another 550 MW in Riverside County while SunPower is working on a 250 MW plant in San Luis Obispo County. BrightSource Energy is constructing a 392 MW solar field in the Mojave Desert.

But large projects tend to take a long time to secure permits and require new transmission lines to transport the electricity, all of which takes a lot of money. Besides, large projects also are more likely to attract strong opposition from environmental and community groups. California policy makers now champion smaller projects, particularly those under 20 MW. In fact, during the second quarter of this year, the clean power contracts approved by the utilities commission averaged 7.5 MW in size.

            Renewable Energy Installed To Meet California’s Mandate

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The California Public Utilities Commission voted 5-0 in favor of expanding the current “cap” on net metering, which requires utilities to allow for net metering for just 5 percent of the total electricity demand from its customers. The previous cap was determined by taking the highest peak demand ever recorded in the utility territory.

But solar energy proponents have argued that utilities should calculate the cap by adding up the peak use of individual customers instead, of using the highest peak. Using this method will take into consideration that each customer’s peak demand varies at different times. The commission approved this new method on Thursday, and this could in effect double the amount of electricity (in terms of megawatts) that utilities could allow in the net metering program. Without the new method, Pacific Gas & Electric, for example, could stop accepting new applications in 2013 because it will likely have reached the cap.

The net metering program is open to home owners, commercial building owners and schools, and it includes all renewable energy generation equipment (the majority is solar panels) of 1 MW or less. Customers who enroll in net metering don’t get a check for the electricity they export to the grid, but get credits on their utility bills. The commission sees the program also as a way to create jobs.

Utility push back

Lawmakers have raised the cap for net metering before, and such an effort faced strong resistance from utilities. Part of the argument against expanding the program is who will provide the cost for maintaining the electric grid for the program. Net metering customers don’t pay a grid maintenance charge even though they rely on it to export excess electricity and draw power from it when their solar panels aren’t producing power. That means customers who are not part of the net metering program may in fact be footing a significant cost of the program.

Some critics also contend that affluent customers are more likely to install solar panels and take advantage of net metering. People on different side of this debate have certainly offered numbers to bolster their arguments, but the commissioners say they want to do their own study and figure out if they need to modify the program. The commission staff will do a new cost-and-benefit analysis on this topic.

“The report should quantify the costs and benefits of (net metering) to participants and non-participants and should further disaggregate the results by utility, customer class, and household income groups within the residential class. The study should also seek to gather and present data on the income distribution of residential (net metering) participants,” according to the written decision the commission approved Thursday

The commission wants the study done by Oct. 1, 2013, and it would suspend the net metering program for new enrollees starting on Jan. 1, 2015 if it needs more time beyond that to reform the program.

Images courtesy of SolarCity.

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PG&E wanted permission to invest $9.9 million of taxpayers’ money into a solar manufacturing service from SVTC Technologies, which would offer solar companies engineering expertise and manufacturing equipment to create product prototypes. The service aims to help silicon solar companies, especially startups with no money to buy their own factory equipment for pilot production, to get their technologies ready for commercial production.

PG&E’s request is unusual because it typically puts money into power generation, not manufacturing technology development. The utility has been signing power-purchase agreements with solar power plant developers in order to meet a state mandate to get 33 percent of its power supply from renewable sources by 2020. It also is developing its own solar power projects to meet that requirement. The $9.9 million investment would’ve given PG&E an equity stake in SVTC’s solar business.

The utility’s request also came at a time when solar manufacturers in the U.S. and elsewhere have struggled to survive in a market with an oversupply of solar panels. Many companies have filed for bankruptcy or shuttered factories. Industry stalwarts First Solar and SunPower both announced factory closures and layoffs last month. Also, many solar startups are not using silicon but other semiconductors in their quest to make cheaper and better solar cells and panels.

PG&E said the investment in the SVTC project will help reduce the cost of solar power and benefit consumers. SVTC secured a $30 million grant from the U.S. Department of Energy last summer to run this prototyping service in Silicon Valley. SVTC’s president, Gunter Ziegenbalg, told me last month that the company was getting factory equipment from companies such as Roth & Rau and other in-kind services for the project. Overall, the project would cost $85 million to launch. SVTC needed the PG&E investment to claim the money from the DOE, and it was running up against a June deadline to do that.

Ziegenbalg also contended that the prototyping service will be in demand precisely because manufacturers are under more pressures than ever to improve the performance of their solar cells and panels in order to survive a tough market.

In a bid to persuade the commission to vote for the proposal, SVTC last month wrote a letter that offered to increase PG&E’s equity stake with the same $9.9 million investment. Both PG&E and SVTC refused to divulge the size of the proposed equity stake.

Commissioners Michel Florio, Catherine Sandoval and Mark Ferron voted for the proposed written decision to deny PG&E’s request. The decision said the manufacturing service project is too risky and there aren’t clear benefits to Californians. It also noted that PG&E initially claimed the project will make enough money to return the taxpayers’ investments, but it later changed its argument to say the main benefit for the taxpayers is to have potentially lower priced solar electricity. Critics also said PG&E should use its own money instead of funds from  ratepayers to invest in SVTC.

Commissioner President Michael Peevey had drafted an alternative proposed decision that would have approved the utility’s request. He supported PG&E’s argument that the project would likely lead to cheaper solar electricity, and he noted that research and development, by its nature, is a risky undertaking to start with, and no one can accurately predict the success rate of any such effort.

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Aerial view of Chevron, BrightSource solar oil plant

BrightSource Energy, which builds solar power plants and plans to do an IPO, has completed about a quarter, or 25 percent, of its first project, Ivanpah, which is on schedule to come online next year, the company said in a government filing on Friday. BrightSource spokesperson Keely Wachs tells us that the Ivanpah project is still on schedule to be completed in 2013.

Completing Ivanpah is crucial for BrightSource’s survival because the company has yet to demonstrate that it’s able to develop and deliver a large-scale project — doing so will help it line up more money and more customers. The company has raised $2.2 billion in equity and debt to finance Ivanpah’s construction.

The 392MW project has generated a lot of controversy because of its impact on the desert tortoise. In fact, the discovery of a higher-than-expected number of tortoises on the project site (located in California’s Mojave Desert) prompted BrightSource to halt construction on parts of the project last year. Work resumed in June.

The company posted $159.1 million in revenue and $111 million in net losses for 2011 in its Friday filing with the Securities and Exchange Commission. In contrast, BrightSource posted $71.6 million in net losses on $13.5 million in revenues for 2010.

The Oakland, Calif., company is one of a handful of developers building solar power plants in the U.S. using concentrating solar thermal technology, which uses mirrors to direct sunlight to heat water in a boiler and use the steam to run a turbine-generator to produce power. BrightSource’s power-plant designs place the boiler atop a tower.

The company started building Ivanpah in October 2010 and plans eventually to deliver 377MW from Ivanpah to Pacific Gas and Electric and Southern California Edison. The two utilities are big customers for BrightSource, which has inked 13 power sales agreements, totaling 2.4 GW, with them.

BrightSource re-negotiated five contracts with Edison last year and submitted the modified contracts to the California Public Utilities Commission last November. The two companies changed the terms for three of the contracts, mainly to reflect the addition of energy storage, which BrightSource says will enable it to deliver the same amount of power with one less power plant.

Either BrightSource or Edison can cancel the contracts if the commission doesn’t approve them, BrightSource said in its filing. The company is now seeking regulatory approval for two other projects in California.

Because BrightSource’s technology can produce very hot steam, it can have other uses besides electricity generation; for example, the company completed a project for Chevron last year for oil recovery. Chevron sends the steam to loosen oil that is stuck in rock fissures, making it easier to siphon out. The project provided BrightSource with an opportunity to demonstrate its technology for industrial operations, but cost a lot more than the company initially expected.

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The approval didn’t come easy. The sticking point was the cost of this contract, which is apparently extraordinary high and prompted the commission’s staff to recommend to either vote no on the contract or to modify it to reduce its cost (the contract price and terms are supposed to be confidential).

The California Public Utilities Commission debated not one but three proposals on what to do with the contract for a project called Mojave Solar, which  recently won a $1.2 billion loan guarantee from the U.S. Department of Energy that will cover up to 80 percent of the project’s cost, which will come from a private source. The company already has spent $70 million developing the project, the commissioners said. The project will have 280 MW of capacity but deliver 250 MW to the utility.

A project’s development and construction cost gives some clues about what the developer will charge for the power, but other factors, such as how efficient the solar equipment is at producing electricity and the cost of maintenance and operation also are factors. But just for some sort of comparison: BrightSource Energy secured a $1.6 billion federal loan guarantee to build a 392 MW solar farm in California while First Solar lined up $967 million for a 290 MW project in Arizona before selling it to NRG Energy.

California requires its utilities to secure 33 percent of their electricity supply from renewable sources by 2020. This mandate is driving much of the utilities’ investments in clean power.

While acknowledging that high cost, the four commissioners who favored it said cost shouldn’t be the only factor in deciding the merit of the project. They cited the five years and $70 million that Abengoa already has invested in the project and the benefit of promoting renewable generation using different types of technologies. Most of the more recent renewable energy projects are using photovoltaic technology because the cost of that technology is falling, which refers to solar panels, and some commissioners said the state shouldn’t rely too heavily on just one type of solar technology.

Abengoa plans to use a solar thermal technology that uses mirrors to concentrate sunlight to produce steam, which then runs a turbine to produce electricity.

“It’s worthwhile to spend a little more on projects like the Mojave Solar so the (state’s) renewable portfolio doesn’t rely heavily on a single technology. In other words it’ll be more balanced,” said Peevey, adding that solar thermal technology can generate power more consistently than solar panels.

The commissioners also said it would be a shame to lose that loan guarantee when raising money for a big solar project has always been one of the main obstacles for developers. Even changing the terms of the contract could cause Abengoa to lose the loan guarantee, said Michael Peevey, the commission president who led the effort to approve the contract.

The lone dissent came from Commissioner Mike Florio, who noted that the contract is actually not needed for PG&E to meet its renewable energy goals. The utility has signed many other contracts and will continue to do so, so there is no reason to accept the Mojave Solar contract that will cost $1.25 billion over 25 years, he said.

“I’m extremely troubled by the contract, primarily based on cost,” Florio said. “We will be better off if we pay the developer the $70 million they have invested and end this project.”

Abengoa is building the solar farm in southern California and plans to complete it in 2014.

Image courtesy of Abengoa Solar

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The California Public Utilities Commission (CPUC) gave the program a makeover Thursday, and among the key changes is a requirement that the technology used must reduce a certain amount of greenhouse gas emissions (the emissions from self generation must be lower than emissions from electricity bought from utilities). For example, energy projects that run on fossil fuels shouldn’t emit more than 379 kilograms of carbon dioxide per megawatt hour, though they can go up to 5 percent above that limit without penalty. Projects will only get half of the incentives if the extra emissions exceed 5-10 percent, and they won’t get any payments if they exceed the limit by 10 percent.

Incentives will be paid based on the electricity produced and only for the electricity used onsite, the commission said. The payments will be cut or withheld during years when the systems don’t meet emission reduction requirements.

The commission not only lowered the incentive rates but also banned the use of biogas produced outside of the California. This change will impact fuel cell development in particular. Fuel cells can run on both natural gas and biogas, and Bloom Energy’s customers have touted their use of biogas as a more eco-friendly alternative.

In addition the commission’s decision extended the program from Jan. 1, 2012 to Jan. 1, 2016. The commission suspended SGIP since January of this year so that it could save the money that was set aside for the program and use it when new rules are in place. It had to change the program to comply with a 2009 legislation (SB 412) that requires the use greenhouse gas emission reductions to determine eligibility.

The details

Eligible technologies for SGIP include fuel cells, waste heat capture, combined heat and power gas turbines, micro turbines, internal combustion engines, energy storage and wind turbines. The program once allowed solar panel installations, but the commissioners moved solar to California Solar Initiative programs in 2007.

The maximum incentives for different technologies will range from $0.50 per watt for gas turbines to internal combustion engines to $2.25 per watt for fuel cells. Wine turbines will fetch $1.25 per watt. The rates are lower than the ones available from 2007 to 2010, when fuel cells could get $2.50 per watt ($4.00 if using renewable fuels) and wind turbines at $1.50 per watt.

The program takes into account whether the fuels used to run the power generators are renewable or not, and also considers where the fuels come from.  The commission voted to ban the use of out-of-state biogas primarily because it wants to promote in-state biogas development, which it says will provide more local environmental benefit. The commission decision on the new SGIP program notes that California hasn’t seen a big increase in biogas development within the state in recent years, however. Using in-state biogas will allow electric customers to claim additional incentives.

The new SGIP also will limit the incentives for each project to $5 million, a change to ensure more electric customers can participate, said commission president Michael Peevey. The incentives come in the form of upfront rebates and payments made based on the power generated.

The program historically has included energy storage as long as it’s paired with equipment that produces electricity. The new program will now include stand-alone energy storage projects.

Impact on fuel cells & Bloom Energy

The changes to the SGIP could have a big impact on Bloom Energy, which has been a major beneficiary of the SGIP. The company and its customers were in line to get $215.8 million awarded by the commission last year, and it fought hard against a proposal to suspend the program last December.

The Commission’s latest decision not only lowered the incentives for fuel cells and cap the per-project incentive amount at $5 million, it also rules out the use of biogas that comes from out of the state. That means Bloom’s customers could get less money for the same-size fuel cells. They also won’t get the bonus for using biogas unless the fuel comes from within California.

Some of Bloom’s fuel cells run on biogas from out of the state. NTT America  installed five Bloom fuel cells at its data center in San Jose, Calif earlier this year and told us that the biogas was coming from Pennsylvania. That project would still be eligible for SGIP incentives because it was completed before the new program rules are to take effect.

The new SGIP rules won’t go into effect yet. The commission modified the criteria for the SGIP, but it will be up to program administrators to hash out the details for  implementing the changes. The administrators are Pacific Gas and Electric, Southern California Edison, Southern California Gas Co. and San Diego Gas & Electric. The utilities will have to file papers to detail how they plan to do so within a few months. They will then re-start the program and accept applications.

Commissioner Timothy Alan Simon said he was not so sure about the ban on out-of-state biogas, though he did vote “yes” for the program overhaul at the end of the hearing on Thursday. “We are in essence making it difficult for fuel cell technology that will simply revert to natural gas,” Simon said during the meeting.

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SAVE targets real estate brokers and appraisers, but the calculator has a simple setup that consumers can easily manage, too. Users enter information such as address, solar-system size, when the installation took place and whether the user owns or leases. The calculator makes use of weather data, local utility rates and data from two solar incentive programs run by the commission to calculate the energy savings.

It’s interesting to note that SAVE doesn’t pull data from California Solar Initiative, which is the biggest solar incentive program in the state, and it is overseen by the California Public Utilities Commission. So users will have to input some data manually, and this could lead to some fancy math to manipulate the results. The energy commission is working with the utilities commission on using the CSI data, said energy commission spokeswoman Amy Morgan.

The calculator spits out numbers such as how much users can save in energy costs (in low-, medium- and high-energy-use scenarios) over the remaining lifetime of the system. Each system generally lasts 20–25 years. You also get an annual energy-cost-saving figure for the current year. The idea with that is to use energy-saving figures to show a prospective home buyer how much she can save over time and therefore how much more she should pay for the home.

SAVE is a good starting point for consumers or real estate brokers who need some baseline numbers to work with. A solar-energy system is as pricey as a new car, and how much value that adds to a new or existing home is debatable and no doubt varies greatly depending on many factors, such as the home’s location and the quality of the equipment, installation and maintenance.

Lawrence Berkeley National Laboratory (LBNL) also recently ran an analysis to quantify what premiums solar can bring to sales values of new and existing homes in California, the largest solar market in the country. The report showed that solar homes in California had been sold for a premium at between $3.90 per watt to $6.40 per watt. That spread amounted to an average

of a $17,000 premium for a fairly new (roughly two years old) 3.1 KW system, which is the average system size in the data, the report said. The premium began to decrease as systems aged.

The information you get from the energy commission’s new online calculator is simplistic and  may not be as useful as the LBNL study, however. Homeowners who are willing to spend the money on solar, whether owning or leasing the equipment, probably already have received some energy-saving estimates from their installer or have done their own calculations before investing in a system.

The tool could be more useful to people who bought new homes that have already come with solar. Builders sometimes bundle solar into the overall home price, and the Berkeley Lab report noted that builders might be willing to charge less for adding solar in order to speed up sales. So a buyer isn’t likely to know the price of their rooftop solar equipment. A new homeowner probably doesn’t receive a breakdown from her builders of how much energy savings she could get over time.

The calculator is not meant to help consumers who want to figure out the cost and benefits of installing solar. For that the energy commission has another online calculator called Clean Power Estimator.

Photos courtesy of Solmentum, GigaOM

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The California Public Utilities Commission voted on Thursday to give renters of apartments or other multi-tenant housing access to a program that previously targeted only low-income residents. The program, so-called virtual net metering, allows renters to get credits on their utility bills for the electricity produced by a communal solar system on their complex.

The solar electricity won’t go to any tenant but will instead be fed to the grid and sold to the utility. The new program will be available to business tenants as well.

Virtual net metering bridges a gap between the more affluent and the low-income, as well as the home-owner and the renter, so people in the middle can benefit from clean power. It also creates new business opportunities for solar service providers and their equipment suppliers.

Since 2006, California has offered rebates to help homeowners offset the cost of putting solar panels on their roofs. It’s the much celebrated California Solar Initiative (CSI) program, which has helped to turn California into the largest solar market in the country.

Except for a special program for low-income residents, the main portion of the CSI program has served mostly the well-off even though there is no income restrictions and the program’s funding comes from all electricity customers. That’s because solar systems can be as expensive as a new car even after applying the rebate (and even after factoring in a federal incentive for solar). The tanking of the economy in recent years also has made solar a luxury for many people.

Many solar service providers have cropped up in the last few years to offer more financing options, like leases to make solar more affordable. Their customers don’t own the equipment even though the panels sit on their rooftops. Instead, they sign long-term contracts to pay a monthly fee to use the solar electricity. The contracts are supposed to guarantee they will pay less money for solar electricity than they do for the same amount of power from their utilities.

But critics say even these new financing options still tend to serve people who are well-to-do. Guess who are more likely to get financing? An applicant who owns a home and has a large bank balance. And certainly, the preference is to serve people who own single-family homes simply because renters aren’t likely to get their landlords to agree to put solar panels on an apartment building. The same is true for tenants of office buildings. If the solar electricity is used on site, there is the sticky problem of distributing the power equitably among tenants.

The CPUC decision on Thursday kick-starts a 60-day process for the state’s three major utilities to come up with rate plans they will use to pay for solar electricity from multi-tenant properties. The new program should be in place after that unless there is dispute over the rate plans. The utilities will be able to pass on some of the costs of setting up this program to ratepayers, but they will need the CPUC’s approval.

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