Arizona regulators are looking at changing decades-old rules requiring utilities to buy power from certain renewable energy facilities, amid a simmering dispute between utilities including Tucson Electric Power Co. and developers of solar-energy plants.
At least one regulator says Arizona stands to lose hundreds of millions of dollars worth of solar energy projects unless the state makes the rules more favorable to project developers by requiring long-term power purchase contracts.
But TEP and Arizona Public Service Co., the state’s largest power company, say the proposed changes could force ratepayers to pay more than needed for power in the future.
At issue are state rules adopted in 1981 to conform with the federal Public Utility Regulatory Policies Act of 1978, or PURPA, which requires a utility to buy power from certain smaller renewable-energy projects called qualifying facilities when their prices are less than the utility’s "avoided cost" — the cost a utility buying power from a PURPA-qualified project would otherwise pay to generate or buy power from other sources.
The PURPA rules didn’t have much effect for years, as prices for solar and wind energy stayed well above most utilities’ avoided power costs — especially in Arizona where coal-fired generation kept costs low.
But with utility-scale solar and wind costs dropping to levels competitive with fossil fuels in recent years, a wave of companies developing PURPA qualifying facilities and seeking mandatory contracts have led to debate over rules in Arizona and several other states.
"As those costs fall, an increasing number of states are becoming relevant to developers, and so they’re looking to use whatever PURPA process exists there to see if they can make these projects pencil out,” said Ben Inskeep, senior analyst for North Carolina-based EQ Research.
In recent years, states including Idaho, Michigan, Montana and North Carolina have revisited their PURPA rules, shortening mandatory contract lengths and lowering avoided cost rates at the urging of utilities who in some cases said they didn’t need the extra power.
Arizona’s PURPA rules provide a procedure for qualifying facilities up to the PURPA size limit of 80 megawatts to sell their power to TEP and other utilities, but they don’t require mandatory contract lengths or dictate avoided costs.
Since 2016, Tucson Electric Power Co., sister rural utility UniSource Energy Services and Arizona Public Service Co., the state’s biggest power company, have filed requests to clarify the state’s PURPA rules to allow them to restrict initial power purchase contracts to two years and renegotiate them to update their avoided costs, to avoid overpaying for power.
But developers of renewables projects have cried foul, contending that power-purchase contracts of at least 15 years are needed to make projects economically viable.
Corporation Commission member Andy Tobin has proposed requiring a minimum contract length of 15 years on PURPA contracts in Arizona, contending that at least $500 million worth of solar projects are on hold because project developers can’t get long-term contracts from APS or TEP.
In December, the ACC voted to hold hearings on proposed PURPA rules changes, and an administrative law judge set hearings to begin in November.
But Tobin led a stakeholder workshop on the PURPA issues in March and has pushed to have the matter decided without formal hearings.
The issue may come to a head as soon as this week, when it is on the Corporation Commission agenda for discussion and a possible vote at its monthly open meeting Tuesday and Wednesday.
But TEP has asked for full, evidentiary hearings on the PURPA issue, which would push any decision by the regulators well into next year.
Joe Barrios, a spokesman for TEP and UES, said the shorter PURPA contracts are needed to prevent the utilities and ratepayers from overpaying for power as renewable-energy costs continue to drop.
“The concern is, customers will end up paying more for power than they necessarily need to, because they will be locked into that price,” Barrios said.
TEP made national industry news in 2017 when it signed a contract for solar power from a 100-megawatt solar farm planned south of Tucson by NextEra Energy for less than 3 cents per kilowatt hour, with added storage for 1.5 cents per kWh. Barrios noted that the company will reach a gigawatt of renewable energy resources with the planned addition of a 247MW wind farm in New Mexico by 2021.
Based on its avoided costs, which include generation from all sources, TEP offers solar qualifying facilities rate ranging from about 2.5 to 2.1 cents per kWh, depending on the type of installation and season.
Barrios said TEP and UES, which serve Santa Cruz and Mohave counties, have yet to take power under a PURPA contract, though a 46-megawatt solar farm built last year in UES territory started out as a PURPA qualifying facility.
He said the utilities also are concerned about being required to take power from an “inflexible resource” like solar farms — which generate power only when the sun shines — or being forced to buy too much power.
TEP wants its renewable-energy projects to be part of its long-range, “integrated resource planning,” which includes generation additions as well as planned power-purchase agreements often bid out competitively.
“Let’s have a thorough, thoughtful discussion about the issue so that we’re not required to start taking power that we haven’t prepared for, haven’t planned for,” Barrios said. “For us, it’s a reliability concern, for the customer, it’s a cost issue, because for us the cost part of it is a straight pass-through.”
Colin Smith, senior solar analyst for the research firm Wood Mackenzie Power & Renewables, said PURPA has been effective at expanding solar in some areas, but the utilities have some valid concerns.
“It certainly can drive a ton of solar, but you can have way too much solar entering the interconnection queue for a particular utility than you want,” Smith said. “If you have more capacity than there is demand, you still have to pay for it, so it can actually cause ratepayers to pay more than they should.”
IGNORING THE LAW?
But renewable-energy developers say long-term contracts are needed to make PURPA renewable plants economically viable, and that TEP and APS are breaking federal law by limiting PURPA contracts to two years.
Court Rich, a Phoenix attorney representing Idaho-based solar developer Clenera LLC, said in filings that TEP, UES and APS have been ignoring the law by offering unreasonable, two-year contracts to qualifying facilities.
“There are somewhere in the neighborhood of 500 megawatts of projects that are going to go forward or not, depending on whether the utilities are required to comply with federal law and the state policy or if they’re allowed to insist on terms that they know make these things not happen,” Rich said, noting that Clenera has prospective projects in both TEP and APS territories.
Rich said TEP and APS are pushing for lengthy hearings on the PURPA issues to push a decision into next year, when a federal tax credit for renewable-energy projects will begin to phase out and make many projects uneconomical.
He cited a recent case in Montana, where a federal judge ruled that regulators intentionally cut PURPA minimum contract lengths and rates to suppress solar development and ordered the state’s Public Service Commission to set new rates and restore contract lengths to 25 years.
TEP benefits from limiting PURPA contracts, because it wants to build its own solar farms, he added.
“It’s not a cost issue, it’s just a matter of the utility wanting to control it, or own it,” Rich said, adding that TEP and APS typically sign long-term contracts lasting 20 to 25 years for non-PURPA renewable energy projects.
The Solar Energy Industries Association in filings with the ACC stressed the importance of long-term power purchase contracts and suggested the utility panel adopt an interim policy now, to capture currently proposed PURPA projects, and decide on permanent rules later.
North Carolina became the poster state for PURPA project development after adopting a standard 15-year contract for qualifying facilities under 5MW in size. As a result, the Tar Heel state has about 60 percent of all PURPA projects across the U.S.
But in 2017, North Carolina passed legislation limiting PURPA qualified facilities to 1MW and smaller and cut minimum contract lengths to 10 years from 15, while shifting larger PURPA projects to a competitive bid process.
Under the new law, Smith said, Duke Energy has been able to comply with PURPA while competitively bidding larger projects, which he called a “middle ground” approach that could work in other states.
EQ Research’s Inskeep said PURPA project developers have complained that utilities have refused to negotiate contracts or delayed approval.
“Developers are trying to move the projects along quickly, especially to take qualify for the tax credit, and utilities have an incentive to keep the process as slow and as arduous as possible, because this is essentially their only form of competition when it comes to generation,” he said.
Meanwhile, the FERC is currently reviewing PURPA policies, and a bill recently introduced in Congress would amend PURPA to exempt utilities from having to buy energy from PURPA facilities if their customers don’t need the extra power.