Trends in Financing Residential Rooftop Solar Power
The solar industry and the use of residential solar power have grown dramatically in recent years. In fact, in the U.S. alone, a new solar installation is completed every two and a half minutes. Moreover, growth in the residential solar sector is now outpacing other forms of solar installations, due in large part to an increase in the availability of third-party financing. Today, third-party-owned residential installations account for more than 50 percent of new residential solar capacity in California, Arizona, Colorado, and Massachusetts, while market share for third-party ownership in several other states (Connecticut, Delaware, Maryland, New Jersey, New York, Oregon, Texas, Vermont, and Washington) is increasing rapidly to the point that the residential solar-financing market is forecasted to rise to $5.7 billion in 2016 from $1.3 billion in 2012.
So, how does this all work? Using the "third-party-owned" model, developers purchase, lease, install, and maintain rooftop systems. Customers then pay a low, fixed energy rate through a 20-year purchase agreement. Homeowners are therefore able to avoid the high cost of purchasing a system outright. While traditionally lenders would not assume the risk of making loans to solar developers based on individual long-term homeowner debt that is not secured by the underlying real estate, it became clear that homeowners meeting certain credit criteria were a good long-term risk, particularly when payments were tied to powering their homes. In order to make this arrangement financeable, solar developers retain ownership of the systems, lease the systems to homeowners, pool the leased systems, and then sell them to commercial banks in tranches ranging anywhere from $20 million to $700 million.
While initially the market for financing third-party-owned systems was very narrow—sourcing financing from clean-power funds such as those established by Clean Power Finance, which has placed more than $1 billion in solar financing—the market for financing residential rooftop leases is growing at a steady clip and should continue to increase in 2015. Entrants into the financing market include Morgan Stanley, Goldman Sachs, US Bank, JP Morgan and Google, to name a few.
Moreover, it seems that all of the residential solar players are taking advantage of the available financing opportunities. Sunrun, the largest dedicated residential solar company in the U.S., along with Investec, recently announced the close of $195 million of senior credit facilities to support the growth of Sunrun's residential solar business. Presumably Sunrun will use this credit facility to assist in financing rooftop installations that arise out of its partnership with Sungevity. It appears that Sungevity will acquire customers and Sunrun will finance the rooftop installations and own the photovoltaic ("PV") system.
NRG Energy, Inc., through its NRG Residential Solar Systems subsidiary, recently closed an up to $200 million financing with MySolar, funded by Morgan Stanley, where NRG will source customers, install, operate, and maintain leased residential systems, and then sell the systems to MySolar.
Finally, SolarCity, which owns one-third of the U.S. residential solar power market, recently launched its solar loan product, MyPower, which is designed to finance residential solar ownership directly with the homeowner.
Given the lowered costs of solar power, the increase in financing opportunities for residential solar power, and the continually evolving landscape of those financing options, we expect the use of residential solar power to continue to increase significantly through 2015. The real test will be how residential solar power installations (and the financing of those systems) are affected when the 30 percent investment tax credit on those systems expires at the end of 2016.
The Solar Energy Compensation Debate Continues in 2015
The ongoing advance of distributed photovoltaic ("PV") solar power generation in the U.S. continues to stoke debate regarding how residential PV customers should be compensated for feeding power back into the grid.
Historically, net energy metering ("NEM") was the rate structure pursuant to which such customers have been paid. In the 43 states with NEM rate designs, the energy produced by a customer's PV system each month, measured on a kilowatt hour ("kWh") basis, is subtracted from the energy consumed by the customer for that month, and then the customer in turn pays the utility for the net amount of power. If the amount of power generated by a customer for a given month exceeds the amount of power consumed then, depending on the jurisdiction, the customer receives for such excess power either a volumetric bill credit for energy use determined at the full retail rate, a cash payment determined at the full retail rate or, less commonly, a cash payment determined upon some lower "avoided cost" rate.
In those states that have adopted an NEM rate structure and that otherwise have a strong solar resource, it is indisputable that the NEM rate design has spurred the adoption of residential distributed PV solar systems. It is likewise the case, particularly in those jurisdictions that either credit or pay the customer the full retail rate for excess electricity generated, that investor-owned electric utilities and solar developers have disputed whether the NEM rate structure is appropriate.
Specifically, utility companies argue that while they typically recover most of their costs through volumetric charges per kWh of energy delivered across their networks, most distribution network costs arise from fixed investments in wires, transformers, and other equipment sized to meet peak demands. Utilities maintain that because of the mismatch between the mostly variable energy charges and mostly fixed transmission and distribution costs, an NEM rate structure that provides full retail-rate payments to PV customers threatens the utility's ability to recover rates for such transmission and distribution costs. To counter that threat, utilities contend that they must seek to raise the retail rate for all customers which in turn effectively shifts grid system costs from customers who can afford solar PV systems to those who cannot.
Advocates of NEM rate structures that compensate solar customers at the full retail rate contend that systemic retail-rate compensation already covers fixed grid reliability costs and, additionally, that the growing number of PV solar systems in any given service territory permit the utility to avoid environmental, generation, and transmission and distribution loss costs. These NEM design supporters, led by many of the large independent residential solar installers across the country, believe that the NEM structure is essential to the third-party-ownership business model they have successfully developed and implemented. In their view, the effective combination of federal tax credits, plummeting solar installation costs, third-party financing, and NEM rate design have supported unprecedented U.S. solar growth over the last few years.
As state legislatures, public utility commissions, and municipalities attempt to address this tension, a number of potential—albeit hotly contested—alternatives to full retail-rate NEM structures have begun to emerge.
In April 2014, Minnesota approved a value of solar tariff ("VOST") compensation methodology. The VOST, which the Minnesota Legislature had directed the state's department of commerce to develop, is based in large part on an NEM rate design alternative pioneered in 2006 by Austin Energy and Clean Power Research, a Texas municipal utility. Pursuant to the VOST methodology, solar PV customers in Minnesota are billed for their energy use at the incumbent utility's full retail rate, but given a credit against that bill for energy produced by their PV systems. The credit is calculated at the fixed VOST rate.
In theory, the Minnesota VOST more accurately values how much solar power is worth to the utility, its ratepayers, society, and the environment, by taking into account certain avoided system costs (e.g., fuel, fixed and variable operations and maintenance, generation, reserve, transmission and distribution capacity, environmental, etc.) afforded to the grid by a customer's installation of a residential solar PV system. To date, the VOST—which is being challenged in respect to its income tax implications for PV system owners, its effect on one's eligibility for the federal investment tax credit, and its potential chilling effect on third-party ownership financing alternatives—has yet to be adopted by any utility which can choose between the VOST and NEM for its solar PV customers.
More recently, in November 2014, the Wisconsin Public Service Commission ("PSC") voted 2 to 1 to permit We Energy to charge all residential customers in its service territory a $16.00 monthly fixed fee (up from $9.00) plus a volumetric fee of $0.1349 per kWh (down from only $0.139). Solar customers will also have to pay $3.80 per kilowatt per month and will only get $0.03 per kWh for excess energy provided to the grid each month (down from $0.14). Additionally, the PSC's approved change in NEM design shifts the program from annual netting to monthly netting.
The decision in Wisconsin, if unchanged, will likely eliminate any possibility of residential solar power ever becoming economical in the state. In light of there being only about 600 residential PV customers in Wisconsin today, its impact on the current market is negligible. That said, for the residential solar industry generally, the Wisconsin decision provides utilities with an alternative tool for fighting allocating costs in other states.
In addition to the solar compensation models in Minnesota, Wisconsin, and Arizona, the NEM rate structure is being revisited in California, Massachusetts, Colorado, Hawaii, and a host of other states. Suffice it to say that the debate about compensation for distributed generation PV solar systems will continue in 2015.