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GTM Research recently predicted a revival of small commercial solar projects — and we should all hope that happens. With about 5.6 million commercial buildings in the U.S., nearly 75 percent of them measuring 10,000 square feet or less, we are looking at a massive opportunity to increase renewable energy generation and reduce greenhouse gas emissions from building operations.
Yet without market-savvy incentive programs and a more holistic approach to energy upgrades, it’s going to be difficult to reverse the slide in small commercial solar installations (less than 1 megawatt). I work at a bank that actively seeks to fund small-scale commercial solar projects, but many of those we see just don’t pencil out.
A major factor is the expiration of the 1603 Treasury Program, a stimulus initiative that reimbursed up to 30 percent of the cost of a renewable energy installation, in lieu of tax credits, when it went into service. The program spurred small commercial solar installations because it reduced the equity required to fund development. The reality is that small projects don’t appeal to the tax equity investors who typically fund large-scale commercial solar. And commercial real estate loans, the traditional source of financing for building improvements, don’t make sense, because a solar project isn’t large enough to justify the costs of refinancing the building.
The loss of the Treasury program means small commercial solar developers with minimal equity to put into projects are seeking long-term debt financing based on projected energy savings, with no tangible collateral — and that is a very tough underwriting situation unlikely to yield many loans.
Practical measures would provide relief
A couple of practical improvements could make financing at least marginally easier right away. One is standardized documentation, which would greatly reduce transaction costs for small projects. The technical aspects of small commercial projects are similar, but if you look at contracts for such projects, they typically use unique language authored by individual legal firms. That makes these deals more difficult to evaluate and complex to process, reducing financing opportunities. Another improvement would be to provide a more accessible, comprehensive information source on the incentives that still exist. We see underuse of USDA, SBA and California guaranty and incentive programs, because finding and understanding them is a daunting challenge to small-scale developers.
Meaningful expansion of small-scale commercial solar, however, may require a change in approach. By combining an entire suite of energy efficiency measures with solar generation, we could optimize both the building energy profile and the financing for it. As an example of how this would work, our financing for Metrus Energy’s $5.8 million energy upgrade at Kuakini Medical Center in Honolulu included a new central cooling and heating plant, lighting upgrades, and energy management and control systems. The hospital signed an efficiency services agreement (similar to a PPA) that pays Metrus a percentage of the savings each month until the end of the ESA term, and the bank’s risk was mitigated through a bond and insurance.
That project didn’t include solar — but it could have. Bundling solar installation with energy efficiency measures to create a full building energy upgrade would allow the short payback period of upfits such as LED lighting to balance a solar system’s longer payback period. It might even open the door to a larger commercial real estate refinancing, and, depending on the incentives involved, the project might have appeal for tax equity investors.
What kind of incentive would spur such projects? At a minimum, California and other states should follow the lead of Massachusetts and New York and create incentive programs targeted specifically at increasing small commercial solar installations. Even better, public policy should look at the big picture and consider commercial building energy as a whole, providing incentives for long-term thinking rather than short-term returns. We see too many requests for projects that fund only the lighting upgrades and other quick-payback items, leaving the potential for major building energy upgrades and alternative energy production, like solar power, unfulfilled. An incentive structure that takes a holistic approach to energy upgrades could go a long way toward changing this calculus.
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Bill Peterson is chief credit officer at New Resource Bank in San Francisco.
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The forecasts often provided useful information for the coming few months, but had more limited accuracy and value in forecasting beyond that.
Hawaii’s solar industry is in a precarious situation.
As regulators and the state’s utility company prepare to negotiate a sweeping reform plan to support more distributed energy, solar installers are finding it harder than ever to get permits for residential solar projects from the utility — causing thousands of people to lose their jobs or move their companies out of the industry.
According to the Hawaii Solar Energy Industries Association, around 3,000 people have moved out of the sector in the last year alone. That corresponds with a 50 percent drop in permits issued after Hawaiian Electric Company (HECO) initiated a strict approval process last September for solar systems connected to the grid.
The process has kept thousands of customers on a waiting list for a year or more, drying up the pipeline for solar installers and frustrating homeowners who see HECO as trying to thwart competition.
HECO says it is not deliberately trying to hurt the solar industry. Rather, the utility is seeing a growing number of circuits exceeding 100 percent of minimum daytime load during the daytime in residential areas. On the Big Island, HECO says that 10 percent of circuits had reached unstable levels as of February of this year.
“This is a difficult technical issue, and we’re not aware of another utility in the world that has addressed it. There’s no model for us to follow, no resource for us to tap into. We’re really creating new frontiers on this,” said Jay Ignacio, president of the HECO subsidiary HELCO, earlier this year.
As the queue of approvals stacks up, installations have slowed. According to projections from GTM Research, Hawaii will see a 22 percent year-over-year drop in installations this year, from 83 megawatts in 2013 to 65 megawatts in 2014. Next year, the market will likely fall to under 50 megawatts.
That reverses a trend from 2008 to 2012, when the rooftop solar industry doubled installations every year.
“Many installers are rolling back their sales capacity by 50 percent,” said Cory Honeyman, a solar analyst with GTM Research.
With very high concentrations of solar PV compared to other states, HECO is at the forefront of understanding how much the grid can really handle. And although regulators recognize the unique challenges the utility is facing on some islands, HECO has not found many public allies in its efforts to temper solar growth.
At a hearing last week, legislators lashed out at the utility for not preparing the grid for a surge in solar systems.
“You should have known two years ago that it was going to go beyond what you can take,” said one state senator at a briefing with HECO, as reported by the Star Advertiser.
Regulators sympathetic to the technical and cost-shifting concerns of HECO have also rebuked the utility for its long-term plan to handle solar and other distributed resources. In May, HECO submitted an integrated resource plan that regulators deemed “fundamentally flawed” in its modeling of solar, storage and demand response. They gave the utility four months to come up with a “utility of the future” blueprint to phase out older, expensive power plants and prepare the grid for a steady increase in customer-side distributed generation.
HECO finally released its new plan in late August, which, if approved, would speed up short-term approval of residential solar systems while reforming net metering and creating integration standards over the coming years.
Under HECO’s vision, solar installations would triple by 2030. Between now and 2016, customers would be offered full net metering rates. The utility would also increase the threshold for PV on many circuits from 120 percent to 150 percent — potentially eliminating much of the backlog of installations waiting for approval. And a new technical standard for advanced inverters would be created in order to provide reactive power, two-way communications and help integrate on-site storage.
Beyond that, the proposed reforms get more controversial, at least for solar installers. In 2017, HECO would start charging all customers a monthly fee of $50 to $61 for grid costs, while also adding an additional $12 to $16 fee for customers selling solar electricity back into the grid through net metering. Solar customers would also be eligible for a feed-in tariff based on wholesale rates, which would range from $0.16 to $0.20.
HECO argues the rate changes are necessary to prevent solar customers from shifting fixed operational costs onto those who rely fully on the grid. According to the utility’s filing, the current annual cost shift is $38.5 million. The solar industry worries that additional fees could cut savings for customers by 50 percent.
“The plan leans net positive for grid management changes, but net negative for Hawaiian installers looking for the status quo on how solar is valued,” said GTM’s Honeyman.
With solar installations in continued decline and regulators putting pressure on HECO, it’s becoming clear that the status quo is not working for either Hawaiian utilities or the state’s solar industry.
The plan now goes through an official regulatory approval process, which will likely result in a compromise between the competing stakeholders. Even if it doesn’t appease installers worried about change, the final plan will unquestionably be better than the current stalemate. But it’s still unclear how many of the 3,000 jobs shed in Hawaii’s solar industry it will be able to bring back.
It turns out that utilities aren’t just being paranoid. Solar power really is out to get them.
According to a new report from researchers at the Lawrence Berkeley National Lab, utilities and their shareholders could see substantial declines in revenues as solar penetrations increase — assuming they don’t seize the solar opportunity themselves.
The study modeled two prototypical power companies, one a vertically integrated utility in the Southwest U.S., the other a wires-only utility in the Northeast that uses power purchased from third-party generators. The former could be compared to Arizona Public Service, and the latter is analogous to National Grid.
Unlike the many studies that compare the costs and benefits of solar for customers and utilities, the study focused exclusively on calculating the revenue and rate impacts of distributed PV.
The study included a number of scenarios wherein distributed solar ramped up to between 2.5 percent and 10 percent over ten years. Only Hawaii has a penetration level higher than 2.5 percent.
At the lowest level, the study found that distributed PV resulted in about a 4 percent reduction in shareholder earnings for each of the two utilities. In the highest scenario of 10 percent penetration in ten years, shareholder earnings might be reduced by anywhere from 5 percent to 13 percent for the Southwestern utility and by 6 percent to 41 percent for the Northeastern utility, depending on a host of assumptions and options.
Solar cuts into utility revenues in two ways, the authors say. First, it reduces utility power sales more than it reduces costs, leading to a “revenue erosion effect.” Second, especially for regulated utilities, it reduces their need for future capital investments, thereby cutting future earnings from returns on equity.
The impacts on average retail electricity rates, however, were considerably smaller. There was virtually no rate increase in the lower-penetration solar scenarios, and rate increases only rose to about 2.5 percent in the highest PV penetration scenarios. This finding is an average across all customers, and does not measure cost-shifting between PV and non-PV customers or between any other customer classes.
A key variable in these results is an assumption about how valuable PV is to the power system as a whole. Regulators will have to assign a capacity value to solar and give a value to avoided transmission and distribution costs. While the actual dollar values in the study were very sensitive to the assumptions chosen, they did point in one interesting direction: assigning a high value for distributed PV results in lower ratepayer impacts, but higher shareholder impacts.
In other words, if solar is worth more for the grid, that’s good for consumers and bad for shareholders.
“This is not commonly appreciated,” said co-author Galen Barbose. “The more infrastructure PV defers, the worse off the infrastructure investors are.”
The study also tested other variables, which may reaffirm current regulator and utility fears. Decoupling utility profits from electricity sales, as California and other states have done, addresses short-term revenue impacts, but does not address the loss of future capital investments.
Low load growth is bad for utility finances; combining that with solar is a double hit. In an extreme scenario for the Northeastern utility, shareholder losses were 41 percent due to a combination of low load growth and 10 percent PV penetration. “Energy-efficiency technologies have the same kind of impacts on revenues,” Barbose pointed out.
When regulators take years to adjust rates, that delay can increase losses. Barbose said this problem is especially acute now, in a time of rapid change.
Lastly, the study points out that when customers pay low fixed charges, the loss of electron sales from self-generation cuts into revenues — the reason why the Edison Electric Institute and numerous utilities around the country are pushing to increase fixed charges.
So what can be done?
The regulatory response to the growth of distributed solar will be where these issues are resolved.
Regulators could make changes to utility rate design and ratemaking processes, adopt mechanisms that allow utilities to recoup revenues lost due to distributed PV, or let utilities earn profits on distributed PV, among other strategies.
“In many cases, they involve important tradeoffs — either between utility ratepayers and shareholders or among competing policy objectives,” said Andrew Mills, a report co-author.
The researchers looked at a number of options for balancing the financial picture, such as increasing fixed charges for consumers, paying utilities for lost revenues, and giving performance-based incentives to shareholders. In short, these options mean putting more money in utility pockets by taking it out of consumer pockets.
Another option is to let utilities take the renewable energy credits (RECs) resulting from customer-owned PV, in order to count them against their RPS obligations. Not only might some consider this a “regulatory taking,” it would also lead to solar homeowners no longer being able to legally claim they are producing renewable power. The Federal Trade Commission has made it clear that if RECs are sold, the producer can no longer make claims that their power is renewable.
Perhaps the least onerous option, the authors suggest, is to let utilities invest in or finance distributed solar themselves, thereby earning back what they would otherwise be losing to customers.
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