By Robert Mullin

ANCHORAGE, Alaska — A nearly 40-year-old federal law enacted to spur competition in the power industry is badly outdated and in need of reforms to reflect the current markets, critics of the law said during a panel at the annual Western Conference of Public Service Commissioners last week.

“I kind of feel like I was invited to lunch only to find out that I am the lunch,” joked Jan Smutny-Jones, CEO of the Independent Energy Producers Association, and the lone defender of the Public Utility Regulatory Policies Act on the panel.

The discussion was moderated by Idaho regulator Kristine Raper, whose commission has been an outspoken opponent of PURPA because of its impact on Idaho Power, which has faced mandatory purchase obligations equal to half its load. (See FERC Conference Debates PURPA Costs, Purchase Obligations.)

Before setting out his case against PURPA, Jonathan Weisgall, vice president of government relations at Berkshire Hathaway Energy, provided a brief history of the act.

Congress passed PURPA in 1978 in response to the mid-70s energy crisis, Weisgall pointed out. The law was designed to promote energy conservation and increased use of domestic energy resources, including cogeneration and renewables. It mandated that all electric utilities — including municipals and cooperatives — purchase electricity from “qualifying facilities” at the utility’s “avoided cost.” QFs were defined as cogenerating plants and small power producers — under 80 MW.

The Case Against PURPA

But the energy sector has “changed completely” in the 40 years since PURPA’s passage, according to Weisgall, and the law — including FERC’s regulations implementing it — have not kept up.

He recounted a litany of complaints over the law: Utilities are required to buy power that is neither necessary nor cheap, and they have no control over where QF projects are integrated into the system. PURPA contracts can be lengthy and are not subject to the same resource planning and cost scrutiny as other utility decisions, undermining state integrated resource planning and processes. QFs are not subject to the same curtailment procedures as other generators, yielding an unfair advantage.

“And, lastly, since QFs are not subject to resource planning … significant additions of unplanned renewable QFs can cause reliability issues if they don’t provide planned-for ancillary services,” Weisgall said. “So PURPA is simply outdated.”

Former FERC Commissioner Philip Moeller, now a senior vice president with Edison Electric Institute, concurred with Weisgall, calling PURPA “a relic of another era” and saying the country’s generation fleet has achieved the diversity envisioned by the act.

In 1978, Moeller pointed out, the U.S. produced more than 16% of its electricity from oil. “Now it’s down to 1%. The resource mix has changed dramatically.”

1992 Energy Policy Act

Both Moeller and Weisgall pointed to the 1992 Energy Policy Act as being the driver in transforming the market for generation in recent decades.

“FERC’s requirement of open access to transmission and standardized interconnection rules and procedures for smaller facilities have removed structural barriers to entry and opened up opportunities for new entrants, including QFs, to supply wholesale energy to distant markets whether a utility is a member of an RTO or not,” Weisgall contended.

“We now have better markets. We didn’t have RTOs then, or an EIM,” Moeller said, referring to the CAISO-run Western Energy Imbalance Market.

“Talking about EIM as a competitive alternative — QFs don’t participate in that market,” Smutny-Jones countered. “The reality is that I seriously doubt that there’s any utility in the West that would come to [a utility commission] and say, ‘Don’t worry about it, I’m going to cover the cost of my power plant in the EIM market.’ This isn’t going to happen.”

Smutny-Jones, whose organization represents independent power marketers and generators in California, agreed that “PURPA has been with us for a while.” Like other energy rules, it could be “fine-tuned from time to time.”

“But I think it has usefulness, I think it will continue to have usefulness to push where we don’t have some competitive pressure on vertically integrated utilities,” he said.

Moeller pointed to another reason to roll back PURPA’s purchase obligations: the success of energy efficiency measures.

“We have flat to declining load growth in electricity, something that was unfathomable for decades and decades and decades,” he said. “Modern reality comes down to … in many cases, utilities are required to buy power they just don’t need in a flat or declining demand situation.”

On top of that, Moeller argued, utilities are often paying above-market prices.

“When you add to the cost of power and customers have to pick that up, it has a reverse impact [on efficiency]. Take a look at the Northwest: The No. 1 resource for the Northwest Power Pool for 25 years has been efficiency. That is their first choice,” he said.

Smutny-Jones questioned the premise that declining load should be cited as a reason to roll back PURPA.

“If I heard my colleagues correctly, you should all be seeing [integrated resource plans] coming before you that show no new builds ever in the West. I don’t think that’s true,” he said. “I don’t pretend to have read the IRPs in 13 western states, but I guess that there will be a significant amount of build-out of different kinds of generation over the next 10 years or so, and that should be subject to pressure from PURPA.”

‘More Tools, not more Constraints’

Weisgall laid out a series of recommended changes.

Among them: Congress should modify the purchase obligation to clarify that states that utilize IRPs have the authority to decide whether their utilities are obligated to purchase from QFs. In addition, Congress should reduce the size of QFs to “well below” 80 MW and modify FERC’s “1-mile rule” in order to prevent suppliers from disaggregating their projects “to essentially game the system.”

The 80-MW threshold applies to all generating facilities at the “same site” — which FERC has defined as all facilities within 1 mile of the facility seeking QF status. Weisgall said Congress should redefine “comparable markets” to relieve utilities participating in voluntary auction-based and energy imbalance markets from the mandatory purchase obligation.

Weisgall also thinks state commissions should exercise more discretion on the length of PURPA contracts and avoided-cost calculations to ensure those costs are no higher than competitive wholesale market prices — citing LMPs and auctions as potential proxies.

“States need more tools, not more constraints,” he said.

Smutny-Jones acknowledged that his state of California made some mistakes early on in its adoption of PURPA when it set avoided costs based on oil at about $100 a barrel.

“We learned from that,” he said, adding that in the early 1990s California created a system in which utilities put out a hypothetical generating resource that suppliers could bid against.

“And it was hugely successful,” Smutny-Jones said. “The prices were significantly lower than what the utilities had suggested they would be.”

“There’s a lot of power in the states to try to modify PURPA in ways that can work for you,” he said, addressing regulators in the audience.

Smutny-Jones noted that the avoided-cost formulation falls to state regulators.

“So you can either count on the market to give you that number and have people compete against each other, or you can try to come up with a complicated formula,” he said. “I would have to caution you about that latter [option] because you’ll get it wrong,” he said.

Why ‘Avoided’ Costs?

Weisgall said Smutny-Jones had raised “an interesting point of history.”

“Why did PURPA use the term ‘avoided costs?’ Because there were no market prices. There were no markets as such, so that was the formula, and today of course there are market prices, but we have still have to worry about what avoided cost means, which has kept generations of lawyers employed.”

Weisgall posed a question about states that allow third-party suppliers “complete access” to the transmission system.

“Why do they need PURPA if you’ve got a solar farm and it’s a great one and its [cost is] below what the utility could build? We’re already seeing with our NV Energy utility in Nevada that we are losing some major customers — casinos — where they are finding third-party providers. Well why do we need PURPA under those circumstances?”

Smutny-Jones acknowledged that PURPA is no longer an issue in California because the state’s aggressive renewable portfolio standard has created a strong market for third-party generation. “My phone hasn’t rung off the hook about PURPA for a very, very long time because people have other places to go with their resources,” he said.

Moeller wrapped up the discussion with a call to arms directed at his former agency rather than the state commissioners in attendance.

“I don’t think I’m overstating a full-blown crisis when a utility in Idaho that’s guaranteed [to be] long power until at least 2035 is being required to buy at the cost of … $3.1 billion over the next the next 20 years … for power they don’t need.

“That’s pretty serious. So I think a newly rebooted FERC will have to address this.”