PURPA @ 40 - Remarks at NARUC’s 2017 Winter Meeting
The electric utility industry now refers to the 25 or so years after World War II as its “Golden Age.” Demand was increasing by nearly 10 percent per year, and the costs of generation were actually decreasing. The industry continued to capture economies of scale, with plants reaching the gigawatt scale. For a number of reasons, by the 1970s the industry shifted from a decreasing to increasing cost industry. Without getting into the details, the result was that utilities wildly overestimated demand and underestimated costs of new generation and fuel. Consumers’ rates increased and expected demand failed to materialize.
Amory Lovins and others hypothesized at the time that a spiral of increasing costs and decreasing demand could lead to financial crisis for a utility. He used the term Spiral of Impossibility, not death spiral, but the idea is the same.
These developments led to debate at many commissions about retail rate design. When PURPA was making its way through Congress, it was commonly referred to as the rate reform bill. Titles I and III of PURPA describe ratemaking standards for electric and gas utilities that state commissions had to consider. In these titles, Congress declared its purpose was to encourage “equitable rates.” Title II does not contain that goal.
The Supreme Court said that Title II was “designed to encourage the development” of QFs. While Title II requires that rates paid by utilities to QFs be just and reasonable the Supreme Court explicitly rejected utilities’ argument that this required the rate to be set at the lowest possible reasonable rate.
Rather, FERC’s implementing regulations set QF rates to full avoided cost. Given the upward trajectory of generation costs when PURPA was passed, FERC was aware that this was an advantageous rate for QFs. In upholding FERC’s rule, the Supreme Court wrote that although FERC recognized the rule would not directly provide any savings to consumers, FERC reasonably deemed it more important that the full avoided cost rate would provide a significant incentive for the development of QFs, and that ratepayers and the nation will benefit from the decreased reliance on fossil fuels.
So that’s the idea behind Title II — encourage QF development to reduce the use of fossil fuels. Another benefit of QFs was that they came in much smaller increments than the gigawatt-scale plants that industry was constructing. The must-buy requirement was necessary because, as the Supreme Court put it, utilities were “reluctant to purchase power from non-traditional facilities.” That’s probably an understatement.
Following FERC’s full avoided cost rule, state implementation of PURPA was uneven. By 1985, at least 10 states required rates higher than full avoided cost. FERC explicitly allowed for these higher rates in the preamble to its regulations. New York required utilities to offer 6 cent per kWh rate, some utilities estimated this was twice their avoided costs. The rate was upheld by NY courts, on the theory that PURPA only limited what FERC could require, and states were free to go above avoided cost.
A few other examples: Virginia added a 15% bonus to avoided cost to account for “intangible benefits” that would accrue from a vibrant QF industry. Connecticut similarly accounted for “unquantifiable benefits.” New Jersey added 10% to the PJM pool price to account for cost savings to society. Pennsylvania opted for front-loaded capacity payments that provided for above avoided cost rates in the early years.
Richard Munson’s 1984 book The Power Makers reports that avoided cost ranged from 1.2 cents in Nebraska, to more than eight cents in Vermont.
Where the utility had excess generating capacity, some states did not award QFs capacity payments. While other states did on the theory that all utilities have capacity additions planned at some point in the future.
Congressional hearings held in the 1980s and FERC dockets from that time period are full of utility complaints about PURPA being too successful.
EEI summarized that by the mid-1980s, less than a decade after Congress passed PURPA there was “legitimate concern and much anecdotal evidence that some utilities were (1) paying too much for QF energy and capacity, and/or (2) buying too much of it.”
The facts on the ground varied across the country, but the industry was sending out mixed messages. On the one hand, EEI and many utilities were arguing that energy from QFs was not needed, and on the other hand the Chairman of EEI testified before Congress in 1985 that the nation “must be prepared to meet large increases in electric demand” and that “capacity is being added more slowly than demand is growing.”
FERC Commissioner Stalon acknowledged in a 1988 concurrence that where QFs had not taken off, a major reason was “continued utility recalcitrance and accompanying lack of enthusiasm by some state commissions for QF power.”
In that order FERC changed its position on avoided cost and now concluded that full avoided cost was a ceiling and states may not set rates any higher. FERC would later specify that all avoidable costs may be included and added later that a state may account for a utility’s procurement requirements. As an example, if a state chooses, it can set avoided cost rates for RPS-eligible QFs based on a utility’s cost of meeting its RPS requirements.
FERC has never explicitly codified any of this. In March 1988, one month before the order in which is changed position on avoided costs, FERC proposed new rules that would have codified this restriction in FERC regulations, and would have also eliminated a QF’s option to take a rate based on “avoided costs calculated at the time the obligation is incurred.” This provision in FERC’s regulations remains a source of controversy today. QFs argue — and FERC agrees — that it means that QFs must have the option of a long-term fixed price contract.
NARUC opposed that proposed rulemaking. It passed a resolution in 1988 urging FERC to terminate the proceeding, fearing that more proscriptive avoided cost rules would infringe on state authority. FERC never finalized those rules and it has not modified the avoided cost regulation since. In fact, PURPA itself gives FERC authority to revise its regulations only when FERC determines that revisions are necessary to encourage QF development.
Courts have placed few limits on state authority over avoided cost rates.
Several cases hold that a PUC may not reconsider its prior approval of a contract between a QF and a utility or to change the rates in a signed contract.
In 2016, a federal district court in Massachusetts held that the state commission’s rule setting the avoided cost rate to the ISO-NE spot price was invalid. According to the court, under FERC’s rules a QF must have the option to receive the avoided costs “calculated at the time of delivery” — which could be the ISO price — or “calculated at the time the obligation is incurred.” By providing only the spot market rate, the state eliminated a QF’s ability to choose the latter pricing option. The court cited FERC orders for the proposition that fixed price contracts further title II’s purposes.
Two months later FERC issued a declaratory order about a similar Connecticut regulation reiterating that while the state must recognize a QF’s right to a fixed-price contract, states have considerable flexibility in setting avoided cost rates.
FERC also stated that “Given the need for certainty with regard to return on investment,” coupled with Congress’ directive that the Commission “encourage” QFs,a legally enforceable obligation should be long enough to allow QFs reasonable opportunities to attract capital from potential investors. FERC has never specified that duration.
Notwithstanding the specific complaint about FERC’s one mile rule, today’s complaints about PURPA are nothing new and echo the complaints made 30 years ago when PURPA was initially implemented.
PURPA implementation has always been uneven across the country. My own view is that despite challenges, the statute’s requirements are still relevant today.
Title II of PURPA was largely overlooked in Congressional debates. At the time, few predicted that title II would ultimately play an important role in paving the way for today’s wholesale generation markets.
In 2005, Congress allowed FERC to exempt utilities from the must-buy requirement where QFs could access open markets. PURPA began as a nationwide pilot project that opened the closed utility system to competition. Its success in demonstrating that generation could be a competitive industry ultimately led Congress to limits its reach.
But Congress in 2005 did not address the animating purpose of PURPA Title II, which was to reduce fossil fuel use.
Meanwhile, Congress since 1992 has supported renewable energy by passing and reauthorizing tax credits 10 times. By 2005, when Congress amended PURPA, about 20 states had passed renewable portfolio standards. Congress certainly could have allowed for exemptions based on state requirements or some metric of renewable energy generation or fossil fuel use. Or it could have limited PURPA when it extended tax credits for renewable energy. But it did not.
Again, implementation has always been uneven, and utility complaints about PURPA are nothing new. Where a utility claims that it has an abundance of QF energy, I suggest that it’s worth investigating how the utility’s actions may have contributed.
A recent Lawrence Berkeley National Lab study of twelve western utilities’ IRPs from 2003 to 2007 found that energy consumption growth was overestimated by all but one utility and eight overestimated peak demand growth. Moreover, for most utilities, more recent IRPs continued to overestimate demand growth, even in the presence of much slowed actual growth.
The report also states that utilities’ acquisition of supply resources seem to generally follow the original planning, regardless of the short and medium term performance of load forecasts and of actual energy sales and peak demand. To what extent did utilities’ inaccurate load forecasts, failure to correct for those errors, and lack of foresight about the development of renewable technologies contribute to an abundance of QF energy? Should the utility be held accountable for these mistakes, and how can regulators do so while also protecting ratepayers? These are obviously not easy questions to answer but I suggest they are questions worth asking.
