By Rich Heidorn Jr.

WASHINGTON — The Energy Bar Association’s Mid-Year Energy Forum last week rekindled long-running debates over FERC Order 1000, state-federal jurisdiction, utility rate structures and the Public Utility Regulatory Policies Act. And this year, there was a relatively new issue of contention: grid resilience.

Here’s the highlights of what we heard.

Resilience Debate Comes to EBA

Kim Smaczniak, an attorney for Earthjustice, debated attorney William Scherman over whether the retirement of coal and nuclear generation is undermining the grid’s resilience.

“Is there a resilience crisis in the bulk power system? The answer is no,” Smaczniak said. “There is no data that has demonstrated a crisis on the bulk power system today.”

She contended the grid’s biggest resilience threat is climate change, citing National Oceanic and Atmospheric Administration data that seven of the 10 costliest storms in U.S. history occurred in the last 10 years. “That’s not going away,” she said. “That’s climate change.”

Scherman, a former FERC general counsel who now represents natural gas pipelines and utilities such as FirstEnergy at Gibson, Dunn & Crutcher, said policymakers must practice the “electric utility version of the Hippocratic Oath” in ensuring reliable service above all else.

“We are losing fuel-secure, diverse generation in the country every day, and nothing is being done about it because the mantra is ‘That is the will of the market. We should allow the markets to operate.’ … I sure hope these damn markets are right, because when we finally get to the point of figuring out that they’re not, it will be too late to do anything about it.”

Scherman praised FERC’s ruling declaring PJM’s capacity market not just and reasonable because of price suppression from subsidized renewables and nuclear power. (See FERC Orders PJM Capacity Market Revamp.)

But he said the commission should also have required changes to the RTO’s ancillary services and energy markets because they are interrelated — and that other regions should do similar examinations.

“We have to have a full, comprehensive and holistic review of whether these markets are continuing to work,” he said.

Candice Castaneda, a legal and regulatory counsel for NERC, also sparred with Scherman over his contention that reliability is different from resilience.

“Resilience is an inherent characteristic of reliability. … Resilience is a time-based component of reliability,” she said.

“I know of no NERC standard that assesses and defines resiliency standards,” Scherman responded.

Another Plea for PURPA Reform

Idaho Public Utilities Commissioner Kristine Raper and Adam Benshoff, executive director of regulatory affairs for the Edison Electric Institute, called on FERC to address above-market costs and gaming by qualifying facilities under PURPA. FERC in May said it would review how it enforces the 1978 law. (See FERC Sets PURPA Review; Powelson Targets 1-Mile Rule.)

Benshoff said customers of PacifiCorp and Duke Energy both paid more than $1 billion in above-market costs over the last 10 years.

He said FERC should reduce the 20-MW limit on QFs in organized markets and change the burden of proof, which is currently on challengers to QF self-certifications. “We’re not advocating for a specific number. … Something less than 20, something higher than zero probably makes sense right now given open access, given the sophistication of the folks that are participating in this process.”

Raper said that although half of Idaho Power’s generation mix is hydro, it must curtail that energy during the shoulder months when its peak is 1,300 MW or less. “They have more PURPA [resources] on the system than that. And this is must-purchase energy. … You’re not utilizing hydro, which is a virtually free resource, and you’re paying anywhere between $30 and $200[/MWh] for PURPA generators. It totally blows away the resource stack and the whole theory of running the least-cost resource. … It’s not fair to ratepayers.”

She said FERC’s 1-mile rule is a “red herring” because QF developers are also disaggregating projects to drop below the PURPA limit by registering them as multiple limited liability companies.

She said FERC should allow states more discretion in blocking such gambits by allowing them to treat as a single project those sharing owners, interconnection agreements, facilities, contractors and financing.

In a separate panel, Amanda Rome, Xcel Energy’s managing attorney for federal and state regulatory policy, touted Colorado regulators’ policy, which frees utilities from must-purchase requirements for PURPA projects larger than 100 kW unless the project wins a competitive solicitation. The policy is the subject of a federal court challenge.

The most recent PURPA applications, filed last month, sought prices as high as $34/MWh for wind and $63/MWh for solar, she said. In contrast, Public Service Company of Colorado’s most recent all-source solicitation produced 350 renewable bids with median prices of $19.30/MWh for wind and $30.96/MWh for solar.

The solicitation will give the utility a total of more than 5,000 MW of renewables, “and 70% of those are projects that could qualify as QF,” she said.

Collaboration Sought on State-Federal Issues

FERC General Counsel James Danly had some advice for his colleagues: Don’t count on the Supreme Court’s Hughes v. Talen ruling for jurisdictional challenges to state energy policies.

The 2016 ruling rejected Maryland regulators’ attempt to subsidize a combined cycle plant, saying it interfered with FERC’s jurisdiction. But the court also said its ruling should not be interpreted as preventing states from supporting generation resources through measures “untethered to a generator’s wholesale market participation.”

“A lot of people enjoy hanging their hat on Hughes. Hughes shouldn’t be read for much more than it really states,” Danly said, echoing an interpretation former General Counsel Max Minzner shared with EBA attendees in 2016. (See Court’s Reticence Frustrates Energy Bar.)

Former FERC Commissioner Colette Honorable, now a partner with Reed Smith, noted states’ increasing activism on energy policy. “It’s not just New York and California anymore,” she said.

In Washington state, for example, voters will be asked Nov. 6 whether they support imposing a $15/metric ton charge on carbon emissions by large emitters such as refineries, power generators, and oil and gas producers.

Honorable said she is not optimistic that federal policymakers will adopt carbon pricing. “I’m really a positive person, but I will say I don’t see it on the horizon any time soon,” she said. “We desperately need it.”

She agreed with MISO General Counsel Andre Porter on the need for collaboration among states, RTOs and federal officials. With the threat of year-round forest fires in the West and cyberattacks on utilities, “it’s a new day. It requires our collective thinking,” she said.

Porter said issues as important as reliability, resource adequacy and market efficiency should not be decided in the courts through adversarial processes. “I think there’s a more collaborative, and likely better, way to go about addressing these issues,” he said, citing MISO’s “abundantly transparent” stakeholder process and its work with FERC and the Organization of MISO States.

He cited as an example jurisdiction over sales for resale on the distribution grid. “I’ve often heard people say, ‘Who wins in this debate over federal and state jurisdiction?’ I actually hope no one wins. … It’s not a competition. … The focus through all this has to be continued collaboration to ensure we’ve got a reliable, efficient and adequate grid.”