PURPA and Solar
Solar developers are again using a 1978 federal law that requires utilities to sign long-term power purchase agreements to secure utility PPAs after years of disuse, but the recent track record of developers trying to use this statute is mixed.
The law, called the Public Utility Regulatory Policies Act or PURPA, requires utilities to buy electricity from renewable energy projects of up to 80 megawatts in size at the “avoided cost” the utility would otherwise spend to purchase or generate the electricity itself.
PURPA is expected to overtake state renewable portfolio standards as the biggest driver for utility-scale PPAs in 2017 due to falling solar electricity prices.
Solar electricity can now be delivered at less than utility avoided costs in such states as North Carolina, Georgia, Utah and Oregon.
Any developer planning to use PURPA should analyze first how likely it is to end up battling with the utility before the state public utility commission and, if so, with what likelihood of success.
Potentially Useful Tool
For more than 10 years, renewable energy developers have relied on renewable portfolio standards, or RPS, created under state laws as the primary way to get a utility to enter into a long-term PPA that can support project financing. Twenty-nine states and the District of Columbia have RPS standards.
However, as most of the state utilities in RPS states have signed contracts to fulfill their RPS requirements for the near term, renewable power developers have turned to a long-existing, but infrequently used, federal utility law in an effort to find a long-term market for their electricity output: PURPA.
PURPA was the landmark federal law passed in 1978 to encourage the development of small renewable energy and cogeneration facilities, known as qualifying facilities, or QFs. PURPA directed the Federal Energy Regulatory Commission to issue rules requiring each utility to offer to purchase the output from QFs, and to purchase the output at its avoided cost.
The avoided cost is set at the time that the QF establishes a legally enforceable obligation by the utility to buy electricity from a project.
A unique feature of PURPA is that it is up to the individual state public utility commissions, rather than FERC, to implement the FERC rules under PURPA.
In the 1980s, almost all renewable energy was developed as a result of long-term contracts that utilities entered into under PURPA, with most projects developed in states with commissions that established or approved the highest avoided costs for their utilities. Starting in the late 1980s, with avoided costs falling due to the drop in natural gas prices following gas deregulation and growing surpluses of generating capacity in many regions, QF contracts dwindled.
New projects began to be developed by independent power producers that did not meet the PURPA standards for QF status. Aided by the Energy Policy Act of 1992, which created an exemption from regulation for wholesale-only generators (called exempt wholesale generators or EWGs) independent power projects that were not QFs began to negotiate and sign long-term PPAs with utilities to supply electricity from conventional power plants. This was a period when growing power demands ate into the utility’s excess capacity.
At the start of the millennium, several states tired of waiting for the federal government to create a federal renewable energy standard, and they began to implement their own renewable portfolio standards. Avoided cost pricing at the time was too low to accommodate the financing needs of renewable power. An RPS requires the state’s regulated utilities to supply a specified percentage of its electricity load from renewable energy. Over time, many states followed suit, with many increasing the percentage of renewable purchase obligations under their RPS programs on a periodic basis.
In states without a state RPS law, absent PURPA, a utility has no obligation to sign a long-term contract for the output from independent renewable projects.
In the last couple of years, particularly as wind and solar projects have become less expensive to build, developers in states without RPS standards, and in states whose utilities already have enough renewable energy to meet near-term RPS requirements, began to press utilities to buy their output under PURPA rules.
A few states also have separate solar mandates within their RPS programs that require a certain percentage of the renewable electricity the utility is required to deliver must come from solar. Some of these programs require solar projects to be QFs under PURPA to qualify, and require the state’s utilities to purchase the solar output at its avoided cost, using the PURPA standards for their cost determinations.
In North Carolina, policies under PURPA have led to tariffs that permitted more than 1,000 megawatts of small solar projects up to five megawatts to enter into long-term contracts at fixed tariff rates and for larger solar projects to obtain contracts with somewhat shorter terms and at negotiated avoided cost rates. Because of the success of these projects, solar developers have continued to propose solar projects in the state, leading Duke Energy recently to file an application with the North Carolina utility commission to limit eligibility for fixed-tariff solar pricing to projects that are one megawatt or less in size — down from five megawatts — and to reduce the term of the long-term contracts and to require large QFs to use a competitive bidding process in place of negotiated avoided cost rates. Duke also proposed that PPAs provide for an adjustment every two years in the QF tariff energy rates. A number of developers have filed a complaint against Duke at the state commission, objecting to Duke’s new negotiating position to limit contract terms to five years for QFs larger than five megawatts.
In addition, North Carolina utilities and many other utilities across the country with PURPA obligations have their own plans to build solar projects and include their facilities in rate base so that they can recover the cost plus a return through their retail utility rates, without the same price limitations, term limitations or financing constraints that would apply to QF projects and without offering to purchase the output from them. Two recent examples include MidAmerican in Iowa and Xcel Energy utility affiliates in the north central states, that have big plans to add hundreds of megawatts of utility-owned wind generation in rate base.
PURPA gives FERC the ability to grant waivers from the mandatory purchase obligation to utilities that operate in workably competitive markets, including regional transmission organizations like the PJM system in the mid-Atlantic and rust belt states, the New York independent system operator or NYISO, the New England independent system operation or ISO-NE, the California independent system operator, or CAISO, and the Midcontinent independent system operator, or MISO. FERC has said it will waive the purchase obligation in such markets for projects that are above 20 megawatts in size. Most of the utilities that operate in these markets have sought and obtained waivers from FERC from the mandatory purchase obligation from PURPA for such projects.
Because nearly all the southeastern states and several states in the upper northwest have not formed sufficiently competitive regional markets, FERC has not granted waivers for utilities in these areas. These areas also have historically been the most resistant to signing QF contracts.
The states have considerable latitude in how they implement PURPA within their borders. They determine on their own or merely approve a regulated utility’s determination of its avoided cost. They can determine eligibility for and the duration of any long-term contracts.
Absent support from the state commission, a solar developer would have to appeal an adverse state commission decision to a state court of appeals or ask FERC for relief from how the state commission is implementing PURPA. If a QF petitions FERC to enforce PURPA against a state commission, and FERC does not initiate an enforcement action within 90 days, then the QF is permitted to “stand in the shoes” of FERC and file a complaint against the state commission in federal court. In the history of the statute, FERC has only sought enforcement against a state commission on PURPA implementation once, and ultimately dropped that challenge. In reviewing a petition from a QF that it believes is meritorious, FERC’s typical practice has been to declare that it will not initiate an enforcement action, but then go on to explain why it believes that the state’s implementation of PURPA is inconsistent with the federal rules.
PURPA also applies to unregulated utilities like municipal utilities and electric cooperatives. However, since these entities are not subject to state commission regulation, a QF that has a dispute over a long-term contract cannot go to the state commission for resolution of the issues. Rather, the QF would have to file a PURPA complaint in the proper state court or go to FERC to seek an enforcement action against the unregulated utility.
Some state commissions defer to FERC for interpretation of the PURPA rules, and some do not.
The states most notable for declining to accept FERC’s PURPA interpretations are Texas and Idaho. Their utility commissions rejected FERC’s view that certain QFs entered into legally enforceable PPAs, and the highest appellate courts in both states affirmed those state commission determinations.
In the last couple years, utilities in Idaho, Utah, Wyoming and Montana began signing up long-term PPAs with small and large wind and solar projects of up to the 80 megawatts in size at avoided cost rates. (A project larger than 80 megawatts does not qualify as a QF and, therefore, cannot use PURPA as a means to obtain a utility PPA.)
However, the utilities in these states are now taking steps at their state commissions to try to put an end to, or severely limit, their purchase obligations under PURPA. Most of the utilities in these states are seeking, and in some cases obtaining, state commission approval to reduce to size cap for availability of standard rates and to obtain shorter contract durations.
For example, the Montana commission recently agreed to a request by Northwestern Energy for an “emergency” limit of standard avoided cost rates to solar projects under one megawatt in size, from a previous three-megawatt limit, and the Idaho commission recently agreed to limit fixed avoided rates and term length to two years for QF projects.
While the Utah and Wyoming commissions rejected attempts by the regulated utilities to reduce the contract length to two years or revise avoided cost methodology, Wyoming did not actually resolve the dispute over contract length and avoided costs, preferring to encourage parties to resolve the issues in an informal manner. This informal approach had not led to any resolution for over a year.
In the meantime, utilities in the four states have been continually reducing their avoided cost rates, making contracts less attractive to potential solar developers.
Most states in the southeastern United States do not have renewable portfolio standards. These include Florida, Georgia, Alabama, Mississippi, Louisiana, Arkansas and Tennessee.
In those states, the only legal basis to compel purchases has been the federal statute, PURPA. But the law has rarely led to utility scale solar purchases by utilities.
QF contracts in some of these states are being signed with solar projects under voluntary solicitations for limited amounts of solar capacity that are initiated by the utilities themselves. The pricing is based on a PURPA avoided cost methodology approved by the state commission, and the projects are required to be certified as QFs under PURPA. For example, Georgia Power has conducted several voluntary solar programs to acquire solar power in the last couple years, and the PPAs have been for long duration and at avoided costs determined under a methodology long approved by the Georgia commission for QF pricing.
These programs have involved quickly announced and implemented solicitations with a specified cap on total solar megawatts. The total amount of solar generation acquired in these programs has not been substantial.
Despite being the sunshine state, Florida has a meager amount of solar capacity. None of the utilities has an incentive to offer prices to QFs that will permit the financing of independent solar power, and the utilities have demonstrated a remarkable ability over the years to construct their own generation to add to rate base even in the context of competitive solicitations. Florida Power and Light has already built several solar plants recently to put in rate base, and it has several more under construction in its service area. Absent any prodding from the Florida Public Service Commission, there is unlikely to be a significant upswing in independent solar power production under long term agreements.
At the prodding of Congress, FERC held a technical conference on its PURPA rules in the summer 2016, inviting speakers and written commenters to reexamine the scope of its rules on the utility mandatory purchase obligation and the determination of avoided costs.
In particular, FERC sought and received comments about five issues. They are whether to retain a mandatory purchase obligation for utilities in competitive organized markets for projects up to 20 megawatts, whether to limit curtailment of QF power, whether to wade into assessments of current avoided cost methodologies by the state commissions, what the standard should be for a legally enforceable obligation that triggers a utility’s avoided cost purchase obligation, and whether to reconsider a rule that permits developers to divide up what would otherwise be a project larger than 80 megawatts into smaller projects to qualify as separate QFs in cases where the generating equipment is more than one mile apart.
Berkshire Hathaway, on behalf of its subsidiaries PacifiCorp and NVE Energy, argued that the recently created energy imbalance market, or EIM, in the western United States, in which the utilities participate, is a sufficiently competitive market to warrant waiver of the mandatory purchase obligation. The EIM market provides economic energy interchange among the utilities in CAISO and interconnected utilities outside California. Other commenters strongly disagreed.
On the whole, the investor-owned utilities did not take a strong position on the existing FERC rules, perhaps due to their experience with existing RPS requirements and the fact that the state commissions have considerable discretion in addressing PURPA implementation issues. In September, following the technical conference, FERC asked for additional comments on these subjects.
At this writing, FERC has only two seated commissioners out of the five commissioner positions, and it takes three to make a quorum. Until another commissioner is confirmed by the US Senate, FERC is unable to adopt any new rules in this area should it decide to do so. Even with a quorum, it would take a few months for the new commissioners to get up to speed on these and many other pending FERC matters. There is no legal requirement for FERC to revisit its rules.
It should be noted that there are other potential sources of long-term PPAs outside of a state or federal mandate. Corporations and municipalities have been signing PPAs with renewable energy projects, originally in order to reduce their carbon footprints, but increasingly due to the fact that renewable power prices have become competitive with market prices in general.
PURPA and its implementation paved the way for competitive wholesale markets that are now thriving in the United States. There are still opportunities for solar projects to use PURPA to get long-term PPAs at financeable prices outside state RPS processes, but there are headwinds in many states at the level of the state utility commissions.