by Emma Foehringer Merchant
December 16, 2019

It’s been a bit of a rough year for PURPA, the 1978 federal law designed to foster renewables development. 

South Carolina reduced its PURPA rates, the Federal Energy Regulatory Commission proposed significant changes to implementing the law, which could curtail development, and a settlement in Michigan cleared the way for hundreds of megawatts of PURPA projects, but at lower rates than they received in the past. 

That makes a decision last week out of the Arizona Corporation Commission, the body that regulates state utilities, even more significant. Commissioners rejected a request from utility Arizona Public Service to set the length of PURPA contracts at just two years. These very brief terms limit the number of projects that can secure financing, according to solar analysts, advocates and the Arizona commission itself. 

“This ruling by Arizona’s utility commission seems to be an almost lone example of PURPA going in a direction that is more favorable for solar developers,” said Colin Smith, a senior solar analyst at Wood Mackenzie Power & Renewables. 

As solar and other PURPA-qualifying renewables have become more ubiquitous, numerous utilities have moved to minimize the law’s influence. Overall, U.S. utilities have worked to exert more control over renewables development by limiting PURPA project sizes, rates and contract durations. They’ve often been successful. 

Though PURPA’s relevance for solar development has waned — it has only led to significant deployment levels in a few states, such as North Carolina — Arizona’s decision suggests PURPA’s not dead yet. 

Arizona’s decision 

Before APS’ 2016 application, Arizona did not have a set contract length for PURPA projects. The utility said its request was meant to cope with the “ever-changing market conditions” associated with buying renewable energy. APS told GTM that the commission's decision "will reduce our flexibility to respond to changes in technology and energy markets."   

PURPA requires utilities to pay “avoided costs” to renewables facilities that qualify under the law. But many of those rates were set years ago, meaning that current solar prices can significantly undercut them. To get around paying elevated prices, utilities have sought to change the way they’re calculated or reduce contract durations, meaning rates can be reassessed more frequently.  

“It is one thing to pay an avoided cost forecasted over two years,” wrote APS in its filing. “It is an entirely different thing to pay that avoided cost forecasted over 20 years.”

Developers argue that short contracts don’t provide enough cashflow certainty to secure financing on a project. In their analysis of APS’ application, state regulators agreed. They found that financing requires a contract term of at least 15 years.

The minimum 18-year term they established in December provides support for PURPA at a time when its influence appears to be dwindling at the national level. The commission also said rates would be set based on long-term avoided cost, using methodology established by regulators. 

“This commission recognizes the value and necessity of increased investment in renewable energy resources in Arizona,” the commission states in its decision, arguing the 18-year term upholds the statute to encourage renewables that is laid out in PURPA.   

This year, Washington state also defined longer contracts for PURPA facilities, at 12 years. But those successes for the solar industry have become something of a rarity in the context of PURPA. 

The lingering policy debate 

Arizona's and Washington’s support for PURPA, for instance, contrasts with the recent notice of proposed rulemaking (NOPR) from the Federal Energy Regulatory Commission on the law’s implementation. In October, FERC argued that the modern energy landscape has so changed from the time of PURPA’s passage that the law's support for renewables and energy competition has become increasingly irrelevant. 

In a lengthy document, FERC proposed decreasing the size of PURPA’s qualifying facilities and changing the calculation of their rates to offer utility’s more flexibility. The changes match many of the tweaks utilities have sought at the state level.   

“The national level changes are also, generally speaking, indicative of the state-level changes we’ve seen. It’s all movement into giving more power to utilities,” said Smith. 

While FERC’s suggestions are stripped of any politics, many renewables advocates saw the possible changes as a rebuke of the law.

“A policy debate about the continuing relevance of PURPA — which, make no mistake, is what this NOPR is really about — is an issue for Congress to resolve,” wrote Commissioner Richard Glick, a Democrat on the commission who dissented on the proposals. “Resolving these sorts of questions by regulatory edict rather than congressional legislation is neither a durable nor desirable approach for developing energy policy.”  

The Natural Resources Defense Council, the Sierra Club, Vote Solar and other environmental groups agreed in joint comments submitted early this month on FERC’s proposal. Though they conceded that PURPA requires reform, the groups challenged FERC on the direction that reform would take under its proposals. 

“More robust safeguards are needed...to enable QF development in the many regions of the country that have still, decades later, failed to realize PURPA’s core objective,” the groups wrote.  

The Public Service Commission of the District of Columbia, in its comments, asked for “deference to state public utility commissions to adjudicate certain disputes” around PURPA facilities. Comments from sPower, a Utah-based owner and operator of renewables, suggested that varying rates paid to facilities over the course of a contract — as FERC proposed — “would make it impossible to obtain financing.” 

Edison Electric Institute, a trade group representing U.S. investor-owned utilities, however, supports FERC’s proposals. “As state and federal policies increasingly require the use of renewable energy and technology costs decline, the move toward the increased use of these resources will only continue to grow,” the group wrote. “The proposals in the NOPR appropriately recognize these changes.” 

The comments generally fall along the lines already dividing PURPA conflicts. Renewables developers want fewer restrictions; utilities want more. 

For now, it remains unclear when FERC might finalize its proposed rulemaking, or if it even will. 

“By issuing the NOPR, neither I nor any of my colleagues have decided whether to change the Commission’s regulations, and we will not do so until after reviewing the record developed in response to the NOPR,” wrote FERC chairman Neil Chatterjee after all the comments were received. 

Arguments that PURPA doesn’t currently play a significant role in renewables development aren’t unfounded; to date PURPA has only spurred 6.2 gigawatts' worth of projects, compared to the nearly 39 gigawatts now operating, according to WoodMac data. But even as terms shorten for power-purchase agreements, WoodMac's Smith notes that PURPA contracts can provide assurance to project developers that they’ll be able to secure a revenue stream after their PPA expires. 

Although utilities such as APS have driven most solar development in Arizona, that application of PURPA means the law could maintain its relevance, especially given the nod of support from regulators in the state.