Utilities Push Back as Old Law Triggers New Fight Against SolarBy , , and
Utilities from Idaho to North Carolina push back against Purpa
Purpa forces utilities to buy clean power if it’s cheap enough
A federal law dating to 1978 has opened up a new front in the solar wars.
The Public Utility Regulatory Policies Act, or Purpa, was enacted after the OPEC oil embargo to help bring new participants into the U.S. power industry. It forces utilities to buy electricity from companies that can beat the utility on the cost of new plants. The goal then: Boost the emerging natural gas industry as a viable option to fuel oil and coal.
Almost four decades later, with the price of photovoltaic panels plunging 79 percent since 2009, it’s the solar industry that’s flooding utilities with Purpa proposals, and utilities are pushing back. They say the law is outdated and forces them to buy more electricity than they need. Developers contend the utilities have lobbied regulators to change state rules, effectively blocking Purpa. The dispute, fought on both the state and federal levels, is another sign of the historic showdown with national economic and environmental repercussions.
“We drove down the prices faster than anyone thought because of competition, then Purpa came into play,” said Adam Foodman, chief operating officer of O2 Energies, a Cornelius, North Carolina-based solar developer. “Utilities lifted their head and said ‘Oh Lord, this is an issue.’ ”
Utilities including Duke Energy Corp. and a unit of Warren Buffett’s Berkshire Hathaway Inc. have successfully lobbied state regulators to revise local Purpa policies, either pushing down the price that has to be met to put the law into effect, or shortening the length of new contracts. Clean-energy developers have elevated the dispute to federal regulators in Washington, who took up a review in June.
O2 has nine solar farms in operation or development in North Carolina, with almost 133 megawatts of capacity. The company alleges Duke is dragging its feet connecting solar projects to the grid and has imposed reliability tests that discriminate against renewable energy, according to a complaint with state regulators in October to force the utility to comply with Purpa. Duke must file a response by Dec. 5.
Duke won’t connect projects that don’t pass a “stiffness” test to ensure the grid can reliably handle the power, said Chief Executive Officer Lynn Good. The test was introduced in June and has led to a backlog of interconnection requests.
“One of the challenges we have with Purpa in North Carolina is the number of projects that are in the queue, not all of which will be built,” Good said in an interview. “Purpa is an ongoing discussion on what makes the most sense.”
That’s a typical position for utilities, said Jerry Bloom, an attorney at Winston & Strawn in Los Angeles.
“Thirty-eight years later, utilities still don’t willingly buy renewable power,” he said. “If you want to address environmental quality and climate-change, then it has to be through regulations like Purpa.”
Developers invoked the law to sell 3.75 gigawatts of solar capacity to utilities in regulated states from 2009 to 2015, about 52 percent of all big solar projects in those regions, according to Bloomberg New Energy Finance. There’s another 4.18 gigawatts of big solar projects that have filed for interconnection through 2019 under Purpa, accounting for 82 percent of all power plants, with any fuel, seeking to use Purpa.
“It’s one of the cornerstones of federal energy policy,” said Christopher Mansour, vice president of government affairs at the Washington-based Solar Energy Industries Association. “Purpa has been an incredibly important driver of clean energy. It put the onus on utilities to say ‘no’ to a project.”
All that Purpa solar is weighing on utilities. Under the law, state regulators set a price based on the estimated cost to a utility to build a new power plant. Developers that can beat that price with eligible projects can request a contract to sell power to the utility. The idea is that competition will lead to new sources of energy and lower rates.
In Montana, utilities must buy power under Purpa if it’s offered for less than $66 a megawatt-hour. The average price of electricity from U.S. solar farms has fallen below $50 this year, and there have been 97 interconnection requests from solar developers since early 2015.
NorthWestern Corp., a Sioux Falls, South Dakota-based utility, asked regulators to “suspend” that price, suggesting that $30 was “a more accurate reflection” of the company’s cost to build its own power plants, according to an-emailed response from Butch Larcombe, a spokesman.
Because Purpa contracts typically run for decades, Northwestern “didn’t want to lock our customers into long-term contracts at rates that we contend were far too high,” he said. The state agreed in June and is expected to set a new price early next year.
In the meantime, Purpa deals have ground to a halt. While regulators said developers and utilities are free to negotiate rates on their own, “we haven’t seen much activity on that front,” Larcombe said.
“The scales are definitely tipping in favor of utilities,” said Kyle Harrison, an analyst at Bloomberg New Energy Finance in New York. “The law is a little bit outdated, and that’s why changes need to be made.”
FLS Energy Inc., an Asheville, North Carolina-based renewables developer, complained to the Federal Energy Regulatory Commission in October that the decision is stifling solar projects. The company is developing 14 solar farms in Montana, each with 3 megawatts of capacity, and they are now on hold.
A spokesman for FERC declined to comment. The federal commission may prove to be more favorable to utilities after Donald Trump takes office. Trump, an outspoken advocate for industry, has two posts to fill on the commission, giving him the ability to shape the agency.
In Idaho, regulators agreed in August to shorten Purpa contracts to two years, from the standard 20-year deals that had long been the standard. Idaho Power Co. made the request in February, saying the duration locked in high rates that are passed on to ratepayers, and Berkshire Hathaway Energy’s PacifiCorp unit later joined the case.
Both companies were facing a solar surplus. Idaho Power had pending requests to connect 1,326 megawatts of solar farms, as of August, more than the utility’s minimum demand load in 2014 of 1,073 megawatts. PacifiCorp had 465 megawatts of Purpa contracts or requests in the state, about 108 percent of its average retail load in Idaho.
“The continued creation of 20-year term contracts placed undue risk on our customers at a time when the company has sufficient resources to meet customer needs,” Brad Bowlin, a spokesman for Idaho Power, said by e-mail. A Berkshire Hathaway spokeswoman declined to comment.
Solar developers say the new contracts are so short it will be difficult to line up financing for proposed projects.
Purpa “may have been a sleepy little thing,” said Matthew McGovern, CEO of Cypress Creek Renewables. The Santa Monica, California-based developer agreed in November to acquire FLS. “Now, with the cost of installation falling where it is today, solar works in so many markets -- and why you’re seeing it bubble up.”