For most of the past two decades, state-level renewable energy mandates, such as California’s 50% by 2030 target, were the biggest driver of utility-scale solar in the United States. Developers put increasingly large projects online, knowing that power purchase agreements with utilities and corporate off-takers would be backed by renewable energy credits, which utilities were mandated to buy, and which often provided compelling returns.
However, in 2017 a power sector law from the 1970s is expected to be a bigger driver than renewable portfolio standard (RPS) policies for the deployment of large-scale solar in the United States. The Public Utility Regulatory Power Act (PURPA) requires that utilities buy power from renewable energy and cogeneration facilities under long-term contracts, if they are able to do so at a cost under which the utilities are expected to otherwise buy power, called “avoided cost.”
PURPA has become a significant force for utility-scale solar over the last few years, and the availability of these long-term contracts has propelled North Carolina to become the second-largest solar market after California in 2014 and 2015, as well as Utah, which was the second-largest market in 2016.
However, this is not without push-back. Utilities have convinced state regulators to modify PURPA implementation in several states, and are working hard to change the policy in the biggest markets, including North Carolina. These utilities say that they are overpaying for solar under PURPA, and being forced to buy power that they don’t need. Dig a little deeper into these arguments, and there are uncomfortable realities for everyone involved.
Back to the 1970s
In order to understand what PURPA does and does not do, and why it exists, it is important to understand the context under which the law was originally passed. U.S. electricity prices fell throughout the 1960s, but took an upward turn in the 1970s, and even adjusted for significant inflation rose by one third from 1969 to 1978.
This was in part due to the oil crisis in 1973, when OPEC producers limited the supply of oil, leading to a spike in prices and global shortages. This had effects on electricity supply, as the United States got 16% of its power from oil (compared to around 1% today) and 14% from gas in 1978, and was heavily dependent upon imports. For industries that relied on petroleum for heat, power, and of course transportation, the effect was even sharper.
Across the world, the oil crisis highlighted the need to reduce dependence on liquid fossil fuels, and has been cited as a major factor in the development of wind energy in Denmark, Spain, and other early adopters.
U.S. President Jimmy Carter pushed for the passage of PURPA in 1978 as part of a sweeping energy reform, which was designed to increase both conservation and heat and power cogeneration, as part of an effort to move to greater energy independence. In addition to these goals, PURPA began to break utility monopolies on the generation of electricity, by forcing them to buy power from a newly created class of independent power producers (IPPs), if these generators could produce electricity for less than the utilities. This can be seen as the beginning of a process of liberalization (termed “deregulation”) of the U.S. electric power sector which was never fully completed.
And while PURPA was initially useful for gas IPPs, it did little for solar or wind in the first 35 years of its existence. The up-front costs of building a solar plant were simply too high for such projects to be able to sell electricity at “avoided cost,” even without a fuel cost. However, in the last few years the dramatic fall in cost for utility-scale solar has enabled developers to beat avoided cost in an increasing number of states.
It is noteworthy that PURPA has led to the dramatic growth of solar markets in states that either do not have RPS policies or have unambitious targets. A prime example is North Carolina, which calls for investor-owned utilities to source only 12.5% of their electricity from renewables by 2021. In North Carolina, the majority of solar that has come online has been through PURPA contracts, and in Utah roughly half the capacity installed to date is under PURPA.
It is also important to note that while PURPA is a federal law, many of the details are set at the state level, including the methodology for avoided cost. This means that PURPA can vary widely from state to state. “There is no standard across the nation as to how to set an avoided cost rate,” notes Benjamin Inskeep, analyst at EQ Research.
The state that put PURPA on the map is North Carolina, as the first state in the U.S. South to become a leading national market. According to GTM Research, over 2.2 GW of solar has been built in North Carolina under PURPA, and the state has another 2.3 GW of projects in the pipeline.
Many of the projects that have been built to date are 5 MW in capacity – or groups of 5 MW projects, the upper limit of what can quality for a standard contract under North Carolina’s PURPA rules. GTM Research describes this as “cookie-cutter” development, most of which is in the service area of the state’s largest utility, Duke Energy.
This boom has enabled the growth of local developers and construction contractors including Strata Solar and FLS Energy, a subsidiary of Cypress Creek Renewables. And while PURPA has enabled a steady flow of solar projects even after the sunset of a state tax credit, the law has not been without controversy. For the last few years Duke has been asking state regulators to make significant changes to implementation of the law.
Duke’s requests have included limiting the size of projects that qualify for standard contracts, shortening contract lengths, and allowing for renegotiation of prices for contracts already awarded. In January 2016, the utility shortened contract lengths for larger projects to five years. However, despite repeated requests, state regulators have rejected the bulk of Duke’s proposals.
Following the PURPA boom in North Carolina, developers sought out contracts in states in the Mountain West which had little experience with large-scale solar. Utah, Idaho, and Montana all have rich solar resources and cheap land. They also have relatively small populations and limited need for electricity.
PURPA has been the leading factor in the boom in utility-scale solar in Utah, a boom which demonstrates how quickly markets can grow. In two years, the state went from the 22nd largest to the second largest solar market in the United States, and 99% of the solar built in Utah has come online since the beginning of 2015.
GTM Research says that, in contrast to North Carolina, solar developers in Utah were building larger projects and negotiating with utilities. “Developers in Utah were using PURPA as the jumping off point for bilateral negotiations,” GTM Research Solar Analyst Colin Smith told pv magazine.
Developers have been less successful in Idaho and Montana. After seeing a pipeline of several hundred megawatts grow in the space of a few months, Idaho regulators stopped developers in their tracks in the summer of 2015, by slashing contract lengths to only two years. As a result, only 221 MW of solar has been built in the state to date, although GTM Research identifies a pipeline of another 140 MW.
Montana was an even greater prize, as developers were able to access avoided cost rates at $67/MWh in the territory of Northwestern Energy, a much higher figure than has been available in other states. However, regulators suspended PURPA implementation last June, to allow the utility to go back to the drawing board and rewrite these rates.
The Vote Solar Initiative and Earthjustice appealed to federal regulators, however these in turn sent the issue back to Montana, and a legal battle is ongoing. At the time of the appeal, the Managing Director of Vote Solar’s regulatory team Ed Smeloff stated that the Montana Public Service Commission had no legal basis to suspend PURPA. “You can’t just arbitrarily suspend a qualifying facilities tariff,” argued Smeloff.
As a result, Montana has built only 4 MW under PURPA, but another 350 MW of projects are under development, including over 100 MW which Cypress Creek had applied for and which are currently in regulatory Limbo.
The argument for dismantling PURPA
Utilities have repeatedly argued that being saddled with long-term contracts under PURPA is not in the best interests of ratepayers, who they argue could be getting a better deal in wholesale power markets. Duke Energy has provided a number for this, saying that it is overpaying by around $1 billion on $2.9 billion worth of PURPA contracts which were signed over the last few years, not including another 1.1 GW of projects which have yet to come online but have locked in higher rates.
The reason for this is rapidly changing electricity price forecasts. A few years ago, Duke’s avoided cost rates were around $55/MWh, however its 2016 rates are set at $35 – $37/MWh, as wholesale prices and future expectations tumbled.
Duke’s approach is hotly debated. “If you extend that logic to say that there should be no long-term contracts, that undermines the natural gas hedging that they have done in the past,” says Strata SVP of Strategy and Government Affairs Brian O’Hara. “It is treating solar differently than you would treat a Duke-owned asset.”
There is also the issue of extra capacity being brought on at a time of flat to negative growth in U.S. power demand. “A lot of utilities are pushing to not allow avoided cost, as they say they don’t need more capacity going forward,” notes EQ Research’s Benjamin Inskeep.
For states with small populations in the Mountain West this may be a particularly strong issue, as it is inherently politically difficult to get a state to force its utilities to sign long-term contracts for power that may be exported to larger states.
Monopolies and contracts
Duke and other utilities also argue that they are experiencing technical difficulties due to the large volumes of solar being brought online. And while adding gigawatts of solar or wind to a grid certainly requires changes, it is important to note that North Carolina got only 3.1% of its electricity from solar in 2016 – less than one third the portion in California.
“With very few exceptions, there really isn’t a situation of oversupply that is creating technical problems – it is really an economic issue for the utilities,” states Vote Solar’s Ed Smeloff. “They are seeing less opportunity for their own units.”
Smeloff argues that when you take apart their objections, utilities are ultimately attempting to maintain control. “It is a question of maximizing their advantages, wanting to dominate the market by discriminating against competitors,” he explains.
GTM Research notes that utilities are not against renewable energy per se, and agrees that utilities want more say in deployment. “[Utilities] are against renewables that don’t align with their goals and their needs, and that is really the crux of why there has been so much push-back against PURPA,” states GTM Research’s Colin Smith.
But whatever the motivation, utilities are seeking to modify PURPA implementation in ways that will ultimately hit the solar industry. “Contract lengths are really important for developers,” states Inskeep of EQ Research. “That’s where utilities are going after PURPA at the state level – looking to reduce contract lengths from 15 – 20 years to 2 – 5 years.”
Such long-term contracts provide the key component of investor certainty. While there have been moves to shorter-term contracts in the private market, the one experience of a merchant solar plant in North America – First Solar’s Barilla project in Texas – did not go well. First Solar recently reported a significant write-down on the project due to heavy losses.
If technical concerns are overblown, economic concerns are real. The electric power industry is undergoing a transformation both in the United States and globally, with cheap renewable energy and, in the U.S., cheap gas bringing the cost of wholesale power to new lows.
This is particularly true for regions that have a lot of solar. California has been reporting recurring negative mid-day prices for the last few years, particularly in the spring. And as more solar and wind are added, the price continues to go down. As such, utilities have a valid concern that this year’s forecast, or last year’s, may not accurately reflect power prices in the future.
This is a boon for consumers, and promises a future of cheap, abundant power. But it also makes for difficult business models. As evidence of this, NRG CEO Mauricio Gutierrez recently stated in a quarterly results call that the IPP business model is “obsolete and unable to create value over the long term.”
There is an inherent conflict here. The business models of solar developers are dependent upon long-term contracts, and at this time utilities have good reason to not want to sign them.
As the cost of solar continues its historical falls, PURPA is spreading to more states. In contrast to Montana and Idaho, GTM Research says that Oregon shows a less controversial path forward for PURPA markets which is based more on negotiated contracts than standard offers, similar to Utah.
GTM Research also notes that with a large number of PURPA projects in the territories of all three of Oregon’s large utilities, there has been less pressure on a single actor. And while utility company PacifiCorp did attempt to get PURPA contract lengths shortened in the state, regulators rejected this in March.
Unlike North Carolina or states in the Mountain West, Oregon has a 50% by 2045 renewable energy target, and PURPA can be a way for utilities to meet their requirements. “There has been better dialogue and communication between the utilities and the developers to make sure that this transition is smooth,” notes GTM Research’s Smith.
Another state worth watching is South Carolina, which recently saw changes to tax abatements which have paved the way for more solar. GTM Research estimates that there is a pipeline of over 1 GW of PURPA projects in both Oregon and South Carolina, the majority of which are viable.
Finally, there is at least one state where regulators appear eager to grow a solar market through the use of PURPA. Vote Solar is currently advising Michigan regulators on how to structure implementation of the law, with the goal of creating a standard offer for projects of 5 MW and smaller.
Despite this potential, most observers see the impact of PURPA declining in the coming years. While GTM Research’s Colin Smith says that he sees the possibility of “sporadic developments” in other states beyond the historic strongholds, “It is doubtful that we will ever see another PURPA market like North Carolina, Utah, or Oregon ever pop up again.”
EQ Research says that it expects the calculations of payment levels for PURPA to change in key states. “It is eventually going to lead to a place where they are going to change the avoided cost methodology,” predicts Benjamin Inskeep.
For now, all eyes are on North Carolina, where in April regulators heard testimony regarding Duke’s proposed revisions to implementation, including a shortening of contracts, a limiting of fixed price contracts to projects under 1 MW, and a move to an auction system for larger projects. With 1.1 GW of projects already qualified under avoided cost tariffs, Duke argues that something has to give.
“I think everyone believes the current system needs changing,” Duke Energy Communications Manager Randy Wheeless told pv magazine.
And while some changes seem inevitable, what future forms the policy will take is far from certain. The ultimate details will be very important for both the solar industry and utilities, in a conflict that will play out in up to 51 individual venues.
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