RPS Acceleration

January 7th, 2012

The New Jersey solar industry potentially faces a difficult year ahead while it recalibrates after overshooting the ambitious Solar RPS goals set for the 2010-2011 REC trading year. If the Solar RPS is not increased, solar installations in 2011-2012 energy year will likely be significantly fewer than in 2011 due to a significantly reduced market SREC price and increased hesitation among potential solar hosts.

In order to stave off an industry pullback, which inevitably means loss of current jobs and few new hires if any, the Solar RPS should be increased for the 2011-2012 REC trading year. The amount of the increase should be ambitious, but achievable, considering the New Jersey solar industry’s impressive history.

Increasing the Solar RPS, of course, only offers a myopic and temporary solution. It is quite possible that this problem of installing too much solar PV will happen again, and we then find ourselves in the same situation as we are now. The BPU should take this opportunity to not only review the Solar RPS target and escalation rates, but to also reassess SREC market design.

Until the summer of 2011, New Jersey SREC prices had consistently traded higher than any other SREC market. This was good for developers, but bad for utilities and ratepayers (as evident in the 0.090 cents/kWh attributed to the Solar Renewable Credit Ratepayer Impact to both C&I and residential customers). Now that the market has collapsed, developers are struggling, and fulfilling the Solar RPS requirement is markedly cheaper for utilities. Significantly diminished SREC prices do not just impact new installations, but also existing projects (especially smaller projects) that rely on SREC income. We are confident that SREC price guessing game is not favorable to either developers or utilities.

The SREC market is different than other ‘free’ markets in that there is a predetermined, vertical demand curve supply must meet. In this scenario, the ramifications of utilities not meeting requirements, and solar industry overshooting the target are unnecessarily costly. Neither side need be exposed to such risk. An ideal Solar RPS and SREC market would reduce risk to buyers and sellers, while achieving flexible, ambitious Solar RPS goals.

The major difference between the current design and an ideal design is the ability to engage long-term SREC contracts. Long-term SREC contracts not only reduce the risk to developers and utilities; they will also reduce the burden on non-participants and diminish the importance of the SACP. Long-term contracts will allow utilities and developers to settle on a fair SREC price. Utilities benefits include improved Solar RPS compliance cost forecasting as well as reducing the burden on ratepayers since developers will likely be willing to accept a lower SREC payment in exchange for risk reduction. Banks and other solar lending institutions will likely offer more favorable lending rates to projects that sell SRECs under contract than play in the market, therefore decreasing the need for high SREC prices to cover high risk interest rates. Since the Solar Renewable Credit Ratepayer Impact makes up the majority of the cost associated with Solar Energy Policy, and contracted SREC deals will likely bring the price of SRECs down, the 2.5% figure attributed to Solar Energy Policy on the average residential electricity bill will likely decrease as well.

It is also worth asking how new lease accounting rules proposed by FASB and IFRS will impact utilities’ balance sheets with respect to utility developed solar PV. The new rules may make it undesirable for utilities to develop solar PV, and thus require them to play in the SREC market instead of navigating around the SREC market by leasing Solar PV facilities. While this is mere speculation, the new rules could place increased importance on SREC prices, and heightened importance on market stability for utilities.

The other change to market design is the ability to adjust the Solar RPS target based on a number of factors, including the strength of the market, pace of installations and cost to ratepayers. This may seem unfair to utilities however, there is a greater degree of predictability if all parties are aware of the conditions that would warrant an adjustment to the Solar RPS. Adjusting the Solar RPS also does not have such an impact in a market where the majority of SRECs are contracted because utilities have much more certainty of future Solar RPS compliance costs, and there are fewer developers playing in the market with non-contracted SRECs.

Just two small adjustments to the existing Solar RPS and SREC market could solve many of the challenges faced by the industry today. We recommend that the BPU take this opportunity to examine the future of the Solar RPS in addition to making more immediate adjustments needed to keep the industry afloat. We thank you again for the opportunity to voice our concerns.

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