The federal Public Utilities Regulatory Policies Act (PURPA) was passed in 1978 as way to diversify the country’s energy portfolio and allow renewable energy to compete with fossil fuels, especially in states with weak or no renewable mandates. It requires electric utilities to purchase the output from cogeneration and small power production qualifying facilities (QFs) up to 80 megawatts (MW) at a cost lower than the utility would incur by supplying the power itself, known as the ‘avoided cost.’ Although PURPA has been almost irrelevant to the wind and solar industries because of the steep cost of the technology, the last decade has represented a major decline in costs and therefore, an increased dependency on this regulation by renewable developers. The cost of solar energy in particular has fallen, with utility-scale PV costing approximately $1.42 per watt for a 100 MW fixed-tilt system in Q1 2016, which represents a 20 percent decrease from 2015 and a 68 percent decrease from 2009, according to the National Renewable Energy Laboratory. This reduction has contributed to the fact that PURPA will be a significant driver of utility solar PV capacity additions in 2017.
North Carolina illustrates this emergence of solar growth through PURPA, but also the risk in exclusively depending upon this regulatory construct. The Solar Energy Industries Association has identified the state as the nation’s second largest solar market behind California, with 3016 MW of installed solar capacity through 2016. Coupled with this increase in PURPA projects, however, comes resistance from utilities. Most recently, Duke Energy sought approval from the North Carolina Public Utilities Commission to amend the PURPA rules, as each state has the ability to implement the PURPA rules accordingly. Duke requested to limit fixed price contracts to solar and other non-hydro projects less than one MW, reduce the term length from fifteen to ten years, and adjust the energy rates every two years. Further, they proposed to use a competitive bidding process instead of fixed price contracts for larger projects. Similarly, the Montana Public Service Commission granted NorthWestern Energy’s request to temporarily suspend guaranteed rates for small solar projects in June of 2016, requiring developers to negotiate power purchase agreements on a case-by-case basis.
Despite efforts by developers to prove the PSC and NorthWestern did not act in a way that is consistent with PURPA’s regulations and ask the Federal Energy Regulatory Commission (FERC) to intervene, FERC declined to launch an enforcement action. With more utilities fighting PURPA, there remains uncertainty over whether investors and renewable developers will still have the long-term assurance needed to finance a project. Despite this hindrance, there are other opportunities for developers to originate long-term contracts without PURPA; competitive bidding processes and bilateral transactions with utilities, cooperatives, and municipalities, as well as corporates, all serve as viable alternatives. GP Energy Management, an outsourced trading and risk management desk, specializes in creating unique project origination plans tailoring them to the project specific location and market. Please contact us to learn more, or to receive a free consultation: email@example.com.
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