by Julia Pyper
March 24, 2017

There is no shortage of energy policy news coming out of Washington, D.C. these days. One of the most recent headline-grabbers was President Trump’s proposed budget that would slash funding for climate and clean energy programs.

If approved in its current form (which experts say is highly unlikely), the budget plan would have a direct effect on states by cutting energy management programs and university lab research, among other things.

Trump’s recent decision to review Obama-era fuel economy standards could also have implications for California and other states looking to implement zero-emission vehicle mandates, although the administration hasn’t formally acted to block these programs -- yet. 

But that's not all of the news coming out of Washington, D.C. that could affect state-level energy policy (which is what this column is all about). So for this latest installment of the State Bulletin, I'm going to share energy policy insights and updates from the National Association of Regulatory Utility Commissioners' winter meeting and the Energy Storage Association's policy summit, which both took place in the U.S. capital last month.

This column specifically addresses efforts to promote nuclear energy, views on the Public Utility Regulatory Policies Act (PURPA), the resignation of Norman Bay, and how California is leading the way on energy storage. Not all of these entries address a specific state, but their outcomes could have an impact on several states.

Pushing the nuclear option

The future of nuclear power in the U.S. is an issue that touches all levels of government. There are problems with new power plants going way over budget, new technologies struggling to commercialize, and existing nuclear plants getting old and proving to be expensive, and controversial, to keep operational. Utilities that own nuclear power plants, such as Exelon, have been pushing for state support to keep the plants from shuttering.

Nuclear energy stakeholders at the National Association of Regulatory Utility Commissioners (NARUC) winter meeting discussed how they are now looking for preferential treatment through wholesale power markets (as I recently reported), which means convincing the Federal Energy Regulatory Commission (FERC) to approve some kind of program that values the low-carbon and reliable power that nuclear plants produce.

Exelon CEO Chris Crane said that he’s looking for clarity from the Trump administration, which is responsible for appointing three new members to FERC. He also noted that the Nuclear Regulatory Commission (NRC) is currently assembling a record of how nuclear assets have performed over decades of regulation and how they have evolved in terms of safety and reliability. “They’re stepping back and looking the burden reduction that [nuclear] can perform,” said Crane. These findings are expected to inform regulatory and legislative discussions as the industry looks to revitalize itself. 

Crane added that organizations like NARUC, the Edison Electric Institute and the American Gas Association should work together “wherever we can to come up with principles on what we want the future to look like, and to help legislators, on both sides of aisle, understand why this is good for consumers and the country and commerce. I think that’s going to be critical.” Crane didn’t go into detail on what he wants the future to look like, but it’s likely that he wants to see reliable baseload resources, like natural gas and nuclear, favored in policymaking.

Time to revisit PURPA?

The Public Utility Regulatory Policies Act (PURPA) was enacted in 1978 to encourage energy conservation and support domestic renewable energy sources, in response to an energy crisis. Today, the decades-old law is driving the deployment of utility-scale solar in states across the country.

PURPA requires utilities to purchase energy produced by Qualified Facilities (QFs) that a utility can develop at an equivalent or lower cost than a traditional power plant -- which is otherwise known as the utility’s avoided cost. Due to the rapid cost decline for renewables, PURPA is expected to be the No. 1 driver of utility-scale solar in 2017. And now utilities are pushing back against the flood of qualified projects.

At the NARUC winter meeting last month, FERC Chairman Cheryl LaFleur was asked for her thoughts on the PURPA controversy. “I think it would probably be a time when Congress could look at PURPA again and make changes,” she said. When the law was created, the “tiny little renewable energy industry” was doing deals with “the big bad utility industry,” she said. But today, the renewables sector is robust, and there are several other drivers of renewable energy generation, LaFleur said.

LaFleur isn’t the only one who thinks PURPA is due for a review. Exelon CEO Chris Crane mentioned that the law creates “restrictions...on being able to provide services to our customers.” Utilities in states such as North Carolina, Oregon, Utah and Montana are also pushing back against the way PURPA is structured.

Irene Kowalczyk, speaking on behalf of Industrial Energy Consumers of America (IECA), said that for manufacturers, “PURPA is as important today as it was in 1978,” but that renewables no longer need PURPA protection. Wind and solar still receive tax credits and are encouraged through RPS targets and through utilities' integrated resource planning. Combined heat and power rarely has those types of advantages, Kowalczyk said.

IECA supports “establishing different treatment under PURPA for industrial CHP and waste-heat recovery QFs that are not in the primary business of selling power,” she said.

While changing PURPA is a Washington, D.C. issue, states do have the ability to adjust their avoided-cost calculations to ensure that the rates for QFs are appropriate, said Lawrence Greenfield, associate general counsel in FERC’s Office of the General Counsel’s energy markets division. “A state commission can always redo an avoided-cost rate and come up with new one,” he said. “That’s where states have tremendous discretion.”

When it comes to whether or not Congress should change the law, FERC is largely agnostic, Greenfield added. “If Congress were to change PURPA…in a narrow way, we would do that,” he said. “If they were to change PURPA wholesale, then we would change our regulation wholesale.”

“Whatever the hell Congress tells us to do, that’s what we’re going to do, for better or worse,” he said.

Keeping FERC at Bay

The Federal Energy Regulatory Commission (FERC) has a pivotal role to play in shaping state-level clean energy markets in the coming years, and not only with respect to nuclear. One of the most closely watched rulemakings is on allowing energy storage and distributed energy resource aggregators to participate in wholesale markets.

Last year, FERC approved California’s request to open the wholesale market up to distributed energy resources (DERs). At the NARUC meeting, Acting FERC Chairman Cheryl LaFleur said she will be closely watching how the process unfolds in the California market, which already has four DER aggregators signed up, “in order to decide how far to go” with the FERC-level decision.

There isn’t much else FERC can do at the moment, since the five-member panel lost its quorum following the resignation of Norman Bay on February 3. FERC is now waiting for President Trump to appoint three other commissioners before decision-making can resume.

Bay spoke at the Energy Storage Association’s policy summit last month, where he urged the future commission to maintain “a very important tradition at FERC; a tradition of bipartisanship in the way the commission addresses energy issues.”

FERC issued 1,300 orders in 2016 and there were only 20 dissents, which means there was a 98 percent unanimity rate, he said.

“There are not political differences that separate members of the commission. I think there’s broad agreement on certain key principles,” said Bay. “That is the importance of markets and competition, and enabling innovation, and recognizing the value of infrastructure and the importance of reliability. All of those shared understandings make a very big difference in the way members of the commission think about energy policy issues, even if they’re from different parties.”

These might seem like strange comments from Bay, who left FERC after meeting with the Trump transition team. “Based on that conversation, it was very clear that I could not commit to staying on if I were removed as chairman," he said. He added that there’s a tradition at FERC for the former chairman to leave, so when LaFleur was appointed to the role, Bay decided it was time to go.

His departure is frustrating for supporters of DERs and energy storage since Bay was a champion for incorporating these technologies into wholesale markets, whereas Trump’s newly appointed commissioners might not be as supportive. One of the biggest debates (similar to FERC’s order on demand response) could be over federal versus state rights to regulate energy markets.

“In my view, with respect to DERs, if you allow them to participate in wholesale markets, that allows that resource to optimize its value,” said Bay. “So it’s my hope that states view this policy initiative as an opportunity, not as a threat to their jurisdiction.”

“Clearly, a quorum is needed to issue a final rule, so everything will depend upon restoring the quorum and whether or not new members of the commission are supportive of the [Notice of Proposed Rulemaking],” Bay added.

Right. And so we wait.

How the (energy storage) sausage is made

While speaking at the Energy Storage Association’s policy conference last month, CPUC Commissioner Carla Peterman told the story of how California’s 1.325-gigawatt energy storage mandate came to be, and how it continues to evolve.

“We looked at what we’d been doing already,” with respect to energy storage pilot programs, technology scaling and how the successful California Solar Initiative (CSI) program was created, “and we got to a number around 1 gigawatt,” said Peterman.

“Then, I thought, let’s make it bigger than 1 gigawatt, because if we get a lot of pushback, we’ll come back to 1 gigawatt,” said Peterman. “Let's put out a number and see if it sticks, and eventually it did. So sometimes, that’s how the sausage is made. You use the best analytics that you can, but ultimately you put out [an idea] and if no one laughs at you…you might as well move forward.”

The CPUC took other steps to ensure the mandate was flexible, she said. For instance, the commission allowed utilities to own up to 50 percent of the storage they deploy across different domains, including customer-sited projects. The CPUC also allowed for shifting up to 80 percent of the target to different locations, because it was impossible to determine when forming the mandate in 2013 where storage would be needed in 2020, Peterman noted.

So far, the CPUC has completed the request for offers process for 2014 and approved contracts for the procurement of 88 megawatts of energy storage. Projects include lithium-ion batteries, zinc-air batteries and flywheels. The 2016 RFO process is currently underway, and shows a diversity of project types, said Peterman. There are utility-owned and third-party-owned projects. There are transmission, distribution and customer-sited projects. And there are projects for load following, ancillary services, bill management on customer side, substation deferral and load shifting.

The interest in customer-sited projects “has frankly been a surprise,” said Peterman. Growth in this area has been supported in large part by the Self-Generation Incentive Program. Last year, the state legislature boosted SGIP funding by $249 million over three years. On March 6, the CPUC issued a proposed decision on some changes to SGIP, including a proposal to boost energy storage funding from 75 percent to 85 percent of the overall SGIP budget. Initial comments on the proposed decision are due by March 26, and reply comments are due by March 31.

The number of behind-the-meter projects is also expected to increase going forward thanks to AB 2868, which directs California’s investor-owned utilities to own and operate up to 500 megawatts of energy storage at the distribution level or on the customer side of the meter.

While making strong progress, the CPUC, working in collaboration with hundreds of energy storage stakeholders, has identified several barriers to greater storage deployment. Those barriers include quantifying the revenue potential; opportunities for contracting and revenue potential; things that add cost like regulations, standards and metering; and things that add time, like interconnection. In addition to working on these issues, the CPUC is working with the California ISO on defining multiple-use applications for energy storage.

“These benefit streams require the opportunity to use your asset for different services at different times,” said Peterman. “So there are some questions there about which purposes take primacy. If the utility needs it, but the customer also wants that, how do you write that into the contract?”

The CPUC has already held workshops on this topic in conjunction with CAISO and will be presenting a joint report soon, Peterman said.

At the same time, the commission continues to refine and evaluate California's current energy storage framework and policies, in response to AB 2514.

As the Golden State moves forward with the deployment of energy storage projects, Peterman advised her fellow commissioners to get a handle on the storage market "soon." Whether or not a target is in place, the technology is coming to market.

“It’s just smart business to think about it as part of your asset class,” said Peterman.

“How quickly do I think other states need to move?” she added. “Very quickly.”