Solar more expensive than necessary?

What role does a 1978 law called PURPA have in 2020? That’s at the heart of a complicated rule-making case in Colorado

by Allen Best

Not all paths will take Colorado toward its rapid economy-wide decarbonization goals with the same efficiency. That’s the primary message of Michael Milligan, a consultant who recently retired as principal researcher at the National Renewable Energy Laboratory.

Michael Milligan

Milligan in November published a paper, which is posted on the website of Renewables for Colorado. He is identified as a senior advisor for grid integration with the organization.

Joshua Epel, former chairman of the Colorado Public Utilities Commission, is identified as a senior advisor for policy. Also on the team is Jim Carpenter, a long-time political operative in Colorado associated with Democratic politicians. The director is Mary Hanley, who has held communication posts with The Wilderness Society and in the Clinton administration.

The stated purpose on the group’s website is to provide “energy expertise to policy leaders and the public on implementing state carbon reduction mandates and making the transition to 100% clean energy.”

Funding for the group has not been identified.

Milligan’s paper makes the case that procurement of new renewable energy must be based on a competitive bidding process regardless of the size of the facility.

“Every 100 megawatts of grid generation—whether it is a single development of 100 MW or dispersed across 20 or more sites—should be held to the same interconnection requirements, reliability standards, performance expectations and cost requirements,” he writes. “To do otherwise subjects ratepayers to a lower level of reliability at higher cost.”

Renewable energy acquired non-competitively, he says, will increase consumer rates needlessly and crowd out more efficient solutions.

Colorado has a goal of reducing carbon emission from its economy 90% by mid-century. The assumed logic for achieving this is through rapid decarbonization of its electrical supply. Most coal plants will come down during the next decade.

But the natural gas fleet is on the line, too. New facilities are unlikely, as was demonstrated by Colorado Springs. It is retiring its two coal plants in 2023 and 2030 without building additional gas generation (except temporary units at the Drake unit).

“Replacing Colorado’s remaining coal and natural gas-fired facilities will likely require expanding the electricity transmissions system to integrate and balance multiple new sources of energy,” says Milligan.

“The clear solution is to require all renewable providers to competitively bid for the purchase of their power,” he writes in the paper.

The elephant in Milligan’s paper is the effort by sPower, a Salt Lake City-based company that in 2018 submitted to the Colorado PUC a proposal to build 18 small solar power facilities across Colorado. Individually, they would produce about 80 megawatts. Combined, they would have had the capacity to generate 1,400 megawatts of power.

The state’s two investor-owned utilities, Xcel Energy and Black Hills, would have been forced to buy the power at “qualified facility” rates under terms of a 1978 law called Public Utilities Regulatory Policy Act, or PURPA. The goal of the 1978 law was to provide access to small renewable energy providers, known also as qualified facilities, or QFs, to compete with fossil fuel-generated electricity.

Utility Dive, in a 2018 story (States, greens face off over PURPA implementation at FERC), further explained that Congress in 2005 amended PURPA as part of the Energy Policy Act to account for the growth of wholesale power markets.

This is already a messy storyline, and it gets worse. There’s also court action (unresolved) and an appeal to the Federal Energy Regulatory Commission.

Meanwhile, there’s a PUC decision in 2018 that speaks of the “complex and interrelated provisions” in rules governing procurement of electric generating resources. In that decision, 18R-0492E, the PUC struck “clearly contradictory language” in its Rule 3902(c) that relates to qualifying facilities. But the written decision also made clear that the PUC intended to return to the matter in a forthcoming comprehensive rule-making.

That time has come. Meanwhile, we have Epel, who was chairman of the PUC from 2011 to 2017, talking up reform. In an essay published by Utility Dive in November 2019, the same time as Milligan’s paper was published, Epel wrote that “PURPA contains a number of outdated concepts that are contrary and indeed impeding the effort to decarbonize the electric utility sector. Unlike 40 years ago, QFs are not replacing fossil fuels; they are blocking the growth of renewable energy projects necessary to replace fossil fuels.

Epel went on to write that “the “most abusive manipulation of PURPA is the use by QFs (funded in many instances by hedge funds) to force utilities into lengthy ‘must-take’ contracts, including provisions that compel payment for renewable energy above fair market prices and lock that above-market rate in for years or decades to come.”

He cited Colorado as a state that has largely avoided utilities being forced to pay too much for solar and wind power. Not so Idaho Power or PaciCorp. “The solution to the problem is adopting a Colorado-type planning and competitive bidding process, not forced use of QFs.”

This takes us to the current rule-making, as the PUC commissioners had contemplated in their 2018 decision. The PUC is hearing arguments in this case, 19R-0096E, on many aspects of what rules it should use when evaluating proposals by the regulated utilities. Some have called it the mother-of-all-rule-making.

For example, a 2019 law ruled that the PUC must integrated the social cost of carbon, currently $47 per ton of emissions, into its reviews. Should that include transmission, too. (Xcel Energy says no, Western Resource Advocates says yes.).

This stuff gets wonky beyond belief but is ultimately an integral part of the story of how does Colorado achieve its deep decarbonization goals during the next three decades.

sPower Development Co.—don’t you wish companies would avoid getting cutesy with their spellings?—filed comments with the PUC in late April that insists once again that federal rules apply here, not the predilection of the PUC—and the proposed rule 3903 (a) violates the federal law:

“The FERC’s regulations also give the QF – not the utility, and not the Commission – the right to determine whether it will sell its energy and capacity on an “as available” basis or “pursuant to a legally enforceable obligation.” A QF cannot exercise this right, which arises from federal law, if it must first compete in a bidding process. As the Commission is aware, Public Service and Black Hills have refused to purchase any energy and capacity from QFs, such as sPower’s QFs, unless such QFs have participated in or won a competitive bidding process. Such refusal is directly at odds with PURPA’s must-buy obligation and FERC’s implementing regulations, and the Commission should avoid taking a similarly unlawful approach.”

This is from the July 8, 2020, issue of Big Pivots. Sign up here to get free copies.

Ready for a breather? Let’s review Milligan’s more-than-25-years of experience in power systems and wind and solar power integration. In a telephone interview during March, he affirmed his views in the paper that Colorado has been a national leader in the energy transition.

In the early 1990s, when he began working in the field, little wind generation existed in Colorado, or for that matter, much of anywhere other than California. California had something like 2,000 megawatts of wind generation in the late 1990s. Solar was mostly confined to solar thermal generation.

But in all cases there were concerns about capacity value. In other words, each megawatt of wind or solar needed a megawatt of fossil generation, as backup.

Colorado’s first wind farm of note was Colorado Green, located south of Lamar, in the state’s southeastern corner. It was proposed in the late 1990s and developed with a 162-megawatt capacity by Iberdola, the Spanish company. Production began in 2003. Xcel Energy was the purchaser. Milligan was there for the dedication in May 2004.

It’s a different world now in terms of renewable generation and penetration. Wind capacity reached 100 gigawatts in 2019 in the United States. That’s roughly 50 times the capacity since Milligan began working in the field in the early 1990s. The American Wind Energy Association reports wind provides 17% of total U.S. electrical production.

Wind was already responsible for 17% of power generation in Colorado by 2016, according to the Colorado Energy Office. It’s greater now since the giant, 600-megawatt Rush Creek wind farm began production in October 2018. More yet is coming.

Solar lags, but has been rapidly gaining. The Solar Energy Industries Association

reports that 3.24% of Colorado’s electricity came from solar as of 2019. But with prices having fallen 385% over the last 5 years, Colorado could add 3,049 megawatts during the next 5 years.

Xcel Energy, says Milligan, was one of the first utilities to realize advanced controls at wind turbines. The key time was at night, when wind production revved up, but Xcel did not want to shut down its coal-burning units completely, as it takes 18 hours to ramp them up. Xcel, and others, figured out how to decrease wind production enough to avoid completely ramping down the plants. With that greater ability, the utility has been able to ramp up renewables to close to 80% of total production at times.

“The learning curve has yielded some pretty interesting things. Twenty years ago, we weren’t thinking out about trying to control wind turbine output, but now we can do it and do it pretty well,” he says.

Looking forward, Milligan says he’s not sure just what the energy mix will end up being. What will be important in determining those resources will be their flexibility.

“I think utilities and wholesale power markets are sort of grappling with about how to have this flexibility. If something provides value, how should it be paid for,” he points out. One component of flexibility is demand management.

Another question going forward will be the placement of energy storage. It’s not necessarily best to tie the storage device directly to the wind and solar dispatches, because a system operator, whether Xcel or some other utility, may have a bigger view of how to use that battery. Then there is the additional complication of juggling both big and small solar. On the other hand, investors may want to see renewables and storage packed into one venture.

On the matter of smaller solar, though, Milligan warns of problems. “Preferential pricing creates incentives to ‘game’ the system,” he says.

He points to a proposal from sPower to add 1,400 megawatts of new solar power via 18 separate facilities producing less than 80 megawatts of power each. Each of them, he says will be located just far enough apart to qualify for above-market pricing.

“If small-scale renewable power is more costly than large facilities, then the price of electricity will increase as reliability declines,” he writes.

“Special carve-outs for small-scale providers will make it more difficult for the state to reach its clean energy goals. In addition to needlessly raising costs for consumers, new infrastructure may be required to integrate these small, disparate facilities reliably and cost-effectively if they are not located where the need is greatest; multiple small facilities could determine grid economics. Small facilities are not subject to the rigorous reliability rules that must be followed by large projects. And because they are not visible or controllable from a system operator, many small-scale facilities may well undermine grid reliability.”

Using data from Xcel and sPower to calculate the extra cost for one year of 500 megawatts of small-scale solar, Milligan came up with $54 million and more than $1 billion over the life of the facilities for 500 megawatts of small-scale capacity.”

Using the same mathematics, he comes up with $3 billion over 20 years for extra costs for 1,400-megawatt of small-scale capacity.

Read Milligan’s study here.

For the various filings in the mother-of-all-rule-making cases, including that of sPower, goes to the PUC website and search for 19R-0096E.

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