TEANECK, N.J. — Joe Fiordaliso, president of New Jersey’s Board of Public Utilities, is not alone in his concerns about the state’s perceived lack of influence at PJM.
State Assemblyman John Burzichelli (D) told attendees at Infocast’s Offshore Wind Implementation Summit last week that he too has concerns.
“I have issues with PJM,” he said. “I’m talking about procedurally. I’m not sure they always have New Jersey issues in mind. We’re going to want a larger voice in what takes place” at PJM.
Burzichelli moved on to other energy-related topics in his featured address. But he elaborated further in an interview, saying he supports Fiordaliso’s demands for increased recognition from the RTO’s staff.
“There’s no question that they are polite and listen, but … they don’t really don’t recognize the state of New Jersey as an entity,” he said. “The short answer is I think it should change. I have a lot of faith in the leadership at the BPU. I would be supportive of the president’s lead in this.”
He suggested that state representatives should get a vote on stakeholder issues because “my observation is that [the interests of] those utilities that are based in New Jersey and New Jersey’s public interests at times are a little different.”
Fiordaliso Cites Progress
Reached on Monday, Fiordaliso said he wouldn’t respond to Burzichelli’s comments because he hadn’t yet spoken with the legislator. But he disputed an Aug. 31 report by Morning Consult that his threat to leave PJM is off the table.
“I wouldn’t say we’ve buried the hatchet. We’re moving the right direction. I think everything is on the table. Right now, I think that has eased a bit. We’re engaging in more dialogue,” he said. “I think PJM is trying to take a step in a positive direction. I think I’m starting to see a turnaround.”
On Burzichelli’s suggestion to seek voting rights at PJM, Fiordaliso acknowledged that would require states being able to become PJM members, which he said “is certainly worth looking into.”
“I think voices are heard when you do have a vote, but I’d like to look into it and see how beneficial it would be to New Jersey. … I don’t expect to win every battle, but as long as there’s an honest exchange of ideas, we can forge a relationship here.”
He said PJM showed it’s “willing to exchange ideas with us” in its comments on the Independent Power Producers of New York’s FERC complaint requesting NYISO prohibit installed capacity withdrawals from PJM into New York City across merchant transmission lines (EL18-189).
In its comments, PJM explained that curtailments necessary for reliability would happen concurrently between the merchant facilities and PJM load on a pro rata basis. This supported comments made in the docket by the BPU, along with the New Jersey Division of Rate Counsel and the Public Power Association of New Jersey. They said NYISO couldn’t consider the merchant facilities as capacity resources because they had recently reduced their PJM transmission withdrawal rights from firm to non-firm.
In fact, it was the docket in which the transmission facilities sought to downgrade their transmission rights that initially prompted Fiordaliso’s threat to leave PJM. The move left Public Service Electric and Gas to pay for most of the Bergen Linden Corridor upgrades that were designed to help facilitate “wheeling” power through northern New Jersey to New York City.
Offshore Wind
Burzichelli said his concern with PJM began with what he felt was a lack of support from the RTO in the state’s attempts to develop offshore wind during Gov. Chris Christie’s administration. The state was looking for guarantees of regional cost allocation for developing the infrastructure that would bring offshore wind generation to the RTO, but “we lost [Christie’s] attention” before anything could be built, he said. Fiordaliso’s “concerns and mine are the same; they just happen to be a separate topic,” Burzichelli said.
He also took issue with what he believed was PJM’s “failing” that required the state to act to save its nuclear plants. “As painful and as expensive as it turned out to be” to subsidize the plants, which are in his district, he “felt very strongly that it was in the public interest … because they’re reliable.”
“It’s sort of an insurance policy that has a price tag to it,” he said, predicting natural gas prices will rise once the regional glut of supply is reduced.
“It will creep. It’s just a question of when,” he said.
Burzichelli said he faults PJM rather than the nuclear owners because the owners were providing for their own interests. PJM should have revised its market rules because the power from the plants gets distributed throughout the RTO, he said.
“I have a comfort level in this case that [plant co-owner Public Service Enterprise Group] is sensitive toward ratepayers. They are also sensitive toward stockholders,” he said. “I think some of the stabilization should have been borne by a wider [RTO-wide ratepayer] base, but PJM did not step up at a pace that was satisfactory to the business model of the utility, so we acted.”
AUSTIN, Texas — Infocast’s Texas Renewable Energy Summit attracted developers, potential off-takers and other industry insiders to the state’s capital Sept. 5-7 for discussions on the uncertainties and risks of the renewable energy market. Panel discussions focused on the continued growth of wind energy and the coming wave of solar energy, the transmission facilities needed to accommodate renewables, and the market’s ability to incorporate them.
The summit’s clear consensus? Solar power is a better play now than wind energy in Texas. ERCOT, which manages about 90% of the state’s grid, projects it will add 3 GW of solar capacity by 2020 and 20.2 GW of utility-scale solar by 2031, double the additions expected from wind.
The state still leads all others in installed wind capacity with nearly 22.6 GW, according to the U.S. Department of Energy. However, the 2.3 GW of capacity Texas added in 2017 was below the 3.6 GW installed in 2015 or the 2.6 GW added in 2016.
Asked why the state presents such an inviting market for solar, Shalini Ramanathan, vice president of origination for RES Americas, repeated the question. “Why Texas?” she asked. “Because it’s hot and flat.”
And there’s so much open space in Texas, said Paul Turner, who sites solar developments for Hecate Energy as vice president of business development.
“If I see a pump jack, I go 3 miles away. I see a wind farm, I go 3 miles away,” he said. “At this point, there are so many options, I just avoid [other infrastructure].”
“It just feels like it’s time. Solar has a lot of headroom to grow,” Ramanathan said, pointing to dropping prices for solar panels and rising natural gas prices. “The challenge is getting off-takers. A lot of the utilities have already bought a lot of wind and solar, but the munis and co-ops are still interested. Corporate off-takers are great. We’ve seen a lot of interest in Texas that directly corresponds to the prices.”
Turner referenced a recent ExxonMobil offer to purchase up to 250 MW of solar and wind energy in Texas.
“Our industry is like lemmings. If ExxonMobil starts doing it, other companies are going to do it as well,” he said. “They don’t want to be left behind. Their shareholders are going to ask, ‘Why aren’t we doing it? Why aren’t we putting it on the cover of the proverbial annual report?’
“The genie’s out of the bottle,” Turner said.
ENGIE Solar North America Managing Director Marc-Alain Behar said potential buyers from El Paso, which is outside ERCOT’s market, have been “pretty stunned” by the low prices they’ve seen for solar.
“If you can make it here, you can make it in a lot of places,” Behar said.
Developers Still High on Texas’ Wind Resources
Wind developers agreed that there is still room for projects in Texas, saying as much as 5 GW of capacity may be built before the federal tax credits expire in 2019.
“It seems there are a plethora of projects, but good projects will get built,” said Matt Jacobs, who is responsible for Tradewind Energy’s portfolio siting. “We’re really excited about the ERCOT market. From a national perspective, ERCOT is a market we see as attractive as any market in the U.S.”
Jacobs lauded the ease of navigating ERCOT’s interconnection queue, while others pointed to falling prices of the technology and shorter construction timelines in Texas than in other RTOs. That makes it easier for developers to put up with transmission congestion and curtailments, particularly in the Panhandle.
“We have well over a decade or more of experience working in this market. There’s always opportunities, but there’s always some headwinds,” EDF Renewables’ Caroline Mead said. “Today, it’s really about the economics. The economics speak volumes. The pricing of wind is so compelling … that’s the main driver at this point.”
Tri Global Energy President Tom Carbone agreed, pointing to renewable energy’s ever-increasing share of ERCOT’s fuel mix. “When [you] have 17% of the load being served by renewables, that says something,” he said.
“We’re at a point now where there’s a value proposition for these sources of generation,” Recurrent Energy’s Jacob Steubing said. “We’re not being driven here in Texas by carbon goals or renewable goals. Economics are driving the buyers. This is probably the only room where a lot of folks consider low prices a bad thing. The general public doesn’t see that as a problem.”
Philip Moore, vice president of development for Lincoln Clean Energy, said ERCOT’s market is unique, a place “where ideas are tested out and challenged,” despite a natural resistance to change. Longer blades, larger turbines and other technological advancements have lowered prices, improved efficiency and opened new areas to wind development, he said.
“With a 40% drop in CapEx, you can go closer to where demand is … but it’s not without its challenges. We’re starting to see new encroachment issues,” Moore said, referring to military aviation training routes and organized political opposition. “We have to be better at explaining the investment benefits of a lot of capital coming to rural areas — and slightly less rural areas — and what the tradeoff is. We need to do a better job, because technology allows us to go to more places.”
Texas’ electric cooperatives are finding their business models are changing. Where once they sold meter boxes and security lights to their members, they are now meeting customer demand for high-speed Internet service and adding wind and solar to their portfolios, Bandera Electric Cooperative CEO Bill Hetherington said.
Bandera is the second largest certified Tesla Powerwall installer in the state. It is promoting the results of a Bloomberg New Energy Finance (BNEF) study that found lithium-ion storage batteries prices have dropped by 80% in the past eight years and projects a $548 billion investment in energy storage by 2050.
“The cost is important, but a small percentage of our customers want to support renewables and buy Tesla Powerwalls,” Hetherington said. “We’ve retooled ourselves and focused on our renewable subsidiaries.”
Bandera serves more than 27,000 members in its footprint northwest of San Antonio. “Our service territory is pretty rural. There are areas where it would actually be cheaper to put in a microgrid rather than pay the cost of extending a service line,” Hetherington said.
He said that the co-op’s work with microgrids caught the National Rural Electric Cooperative Association’s attention, and it selected Bandera for a project to create microgrids in Liberia and Uganda.
Hetherington said 662 million Africans don’t have access to electricity, but that the continent also presents the second fastest growing economy in the world. “Investing in the future pays dividends for our customers and our members,” he said.
The state’s more than 75 electric cooperatives are still cognizant of their members’ concerns and wants, Hetherington and his fellow panelists said.
“Our membership looks at the bottom line. They don’t want to pay a premium to feel good. They want to do it because it makes economic sense,” Golden Spread Electric Cooperative COO J. Jolly Hayden said. “Some members have done community solar on their own. We have a 1-MW model that gives them a pretty good price. We’re also looking at a larger project, but the members haven’t signed off on it.”
“We’re small enough and flexible enough to make changes, from a commodity-based entity to a service-based company that is connected to its customers,” Hetherington said, adding he never thought he would have 1,800 Internet customers. “The technology has changed. What doesn’t change is the support our members expect from us.”
Economic Realities Driving Municipal Supply Decisions
Denton Municipal Electric General Manager George Morrow, a newcomer to the Texas market after years in California, said the city’s recent announcement that it intends to become the state’s second 100% renewable-powered municipality was driven by the market’s realities.
As part of the Texas Municipal Power Agency, the city owns the coal-fired Gibbons Creek plant, a 35-year-old, 454-MW unit that has provided more than half of its generation for a decade. The plant, which environmentalists would like to see permanently retired, will return to seasonal mothballs in October.
Morrow said in looking for replacement energy, he was surprised by the prices he was seeing for renewables. “‘Wow, look at what you’re offering us!’” Morrow recalled. “It just made sense. We were kind of in a sweet spot. Not everybody can be 100% renewable. The system can’t survive.”
John Bonnin, who manages CPS Energy’s supply and market operations, recalled his own experience with request-for-proposal prices in trying to secure power for San Antonio. He likened the situation to one of the final scenes in the 1987 film “Predator,” when the titular alien hunter removes its helmet.
“‘You are one ugly…’” Bonnin said, stopping short of parroting Arnold Schwarzenegger’s entire line. “That’s kind of what it was like year after year, because the [RFP] prices kept going up. There was no thought of solar energy at the time, because people were talking about $250, $300/MWh prices.
“So fast forward a few years. What is our plan now? We have older coal plants ready to retire, so how do you replace that capacity on peak? Wind and solar can give you some peak, but you’re not paying an out of market price for that [any longer]. The big change in our company is we’re not doing this because it’s a mandate, we’re doing this because it’s economic.”
“We were chasing environmental goals before. We were chasing goals, but we were trying to minimize the price effect,” Austin Energy’s Khalil Shalabi said. “That’s changed with recent pricing we’ve seen. We’ve gone more into a mode of risk mitigation. How do [prices] fare under different regulatory paradigms? … We can’t predict the future, but we can look at the risks and quantify those for our customers.”
Jim Briggs, the utilities manager for Georgetown, the other 100% renewable Texas city, said regulatory considerations played a role in the city’s decision to go green when it ended a coal-heavy supply contract in 2012.
“My recommendation to the [City] Council and [utility] board was that renewables needed to be a portion of our energy mix,” he said. “We don’t know what’s coming out of Washington for renewable standards, but I can tell you that, in 30 to 40 years of doing this, they have never been reduced. … You can expect greenhouse gas legislation is going to continue. It might subside during one administration, but it’s going to be back again.”
ERCOT’s Reserve Margin not Expected to Grow
Several panelists agreed ERCOT may have been lucky to escape the summer heat with a reserve margin of only 11%. They pointed out the generators performed when called on, and though the system exceeded its previous peak-demand record 14 times during July, it also benefited from cooler-than-normal weather in June and August.
“Maybe it was some combination of market performance by ERCOT and luck,” said Kathleen Spees, a principal with The Brattle Group. “The wind performed, and the traditional generators showed up. We had some scarcity pricing, but it wasn’t [that] extreme. We skated through a summer that could have been very bad in terms of reliability, but very good for the money. Did we just get lucky? Was that the market working as intended? Or are we at a very low reserve margin, and the prices just didn’t get high?”
“We feel like everything worked out as intended,” said Erika Bierschbach, Austin Energy’s manager of market operations. “The market is vibrant. With regard to most concerns before the summer started, there is still risk in the market.”
ERCOT’s Dave Maggio was quick to point out the grid operator didn’t have to declare any emergencies during the summer and saw a lack of scarcity pricing.
“A big part of the story is going to be the resource performance. We got a lot of support from generation resources and transmission resources. When supply was tight, we didn’t have resources offline,” Maggio said. “The upshot was, we took less out-of-market actions, which is what everyone prefers.”
“From the ERCOT perspective, part of the success we had was effective communications with everyone,” said Pete Warnken, the ISO’s manager of resource adequacy. “The expectation is, as we continue to have lower reserve margins, the market and ERCOT and all the participants need to continue that discussion. We always focus on the summer peak, but fall and winter is coming up, and lowered reserve margins affect that as well.”
Spees called ERCOT’s summer performance with tight reserve margins “one roll of the dice.”
“I don’t think we would get lucky that often,” she said. “One big outage, or the wind doesn’t show up during peak load, or something a little closer to 2011’s [record-breaking hot] weather … if we see a similar reserve margin next year, we could see something very different.”
But don’t expect ERCOT’s market prices to remain depressed for the rest of 2018, BNEF Power Market Analyst Joshua Danial said.
“Some of the least healthy units run when spark spreads are negative, under arcane contracts where their power is guaranteed to have an off-taker,” said Danial, who expects more fossil retirements in the near future. “When those contracts fall off, there’ll be a lot of reconsidering whether to keep them running or not.”
Manan Ahuja, senior director of North America power analytics for S&P Global Platts, said he expects to see reserve margins of 12 to 13% by 2022.
“The supply increase is tracking pretty closely to the load increase,” he said, pointing to an ERCOT interconnection queue that numbers more than 19 GW of projects with signed agreements. “There are small gas projects in the queue, about 4 GW of wind that could come online in 2019. … We expect to see reserve margins that are pretty similar [to 11%] next year.”
TEANECK, N.J. — Although states are competing to be next in the water to develop the East Coast’s offshore wind, industry participants agreed last week that coordination and collaboration will be key for long-term success.
Stakeholders in the fledgling industry met last week at Infocast’s Offshore Wind Implementation Summit to discuss the gamut of issues, from workforce development and environmental concerns to grid interconnection and financial considerations.
While state officials have described themselves as in a competition to follow up on Rhode Island’s 30-MW Block Island project — the East Coast’s first OSW farm — speakers said states would be wiser to instead combine and conquer.
“I hope we can kind of get away from this concept of ‘one state’s going to be the winner in this race to build offshore wind.’ I think if we do it right, all states will benefit, and there’s a great benefit to coordinating ocean planning,” said Kit Kennedy, a senior director in the Natural Resources Defense Council’s Climate & Clean Energy Program. “In many ways, it’s up to the states to work together on ocean planning. We’re looking to you to be the leaders of this field right now because there’s a vacuum at the federal level.”
Brian Sabina, senior vice president of economic transformation for the New Jersey Economic Development Authority, predicted that as the industry grows, it will see beyond state-level competition to measure itself against international players.
“When you start to take that lens, regional cooperation becomes a lot easier,” he said.
“It is kind of competitive … but we really do believe the regional approach makes sense,” said Paul Baldauf, an assistant commissioner of the New Jersey Department of Environmental Protection. “If you look at some of the wind maps from Maine down to Carolina, it doesn’t necessarily matter where that lease is. Multiple states can benefit from it; they all need to have input.”
Coordination is also preferable for finer details, speakers said. Ross Gould, energy sector program manager for the Workforce Development Institute, pointed out that many politicians and union bosses will need to expend political capital to overcome obstacles, and that will likely require promising jobs.
“Now we’re left with the tough question that we have all these promises in all these states, but there’s only a finite amount of jobs,” he said. Collaboration will be key, he said, “to help figure out who can do what and where these jobs can go so that as many people as possible are able to go back and say, ‘I fulfilled my promises.’”
Permitting and oversight will also benefit from collaboration to avoid wasting money on collecting unnecessary data and being able to differentiate between “real” and “perceived” risk, said Mary Boatman, environmental studies chief at the federal Bureau of Ocean Energy Management’s Office of Renewable Energy Programs.
Collaboration will also help ensure that all methods, technologies and data collected are “scientifically defensible” under scrutiny at permitting meetings, said Vince Guida, a research fisheries biologist for the National Oceanic and Atmospheric Administration’s Northeast Fisheries Science Center in Sandy Hook, N.J.
Markian Melnyk, president of Atlantic Grid Development, advocated coordination of offshore transmission facilities rather than allowing generators to build their own private lines back to shore. Such coordination, a keystone of his company’s Atlantic Wind Connection project, would organize the offshore network into an extension of the onshore transmission grid to prevent lines crisscrossing on the seafloor and other unforeseen impacts that create conflicts with other industries, such as commercial offshore fishing.
“So at the moment, some of these tensions with commercial fishermen seem very fraught, but as we go, and as actual projects are built, I think we’re going to see that they can be planned, built and communicated in [ways] which are consistent with commercial fishing, and that’s going to be very positive,” Kennedy said.
Curtis Fisher, executive director for the National Wildlife Federation’s Northeast Regional Center, pointed out that the developers of the Block Island project are proud to say they lost money in delaying their project when a whale was sighted in the area.
“If you can parse out things that benefit the entire region versus things that might be specific to certain states, you can leverage those resources and really come up with a plan and be able to get there a lot quicker than you could as individual states,” Baldauf said.
He confirmed the observations of several project developers that the industry appears to be finally taking off after years of promising announcements that never went anywhere.
“Truly, this is the first time that things are really moving. [Developers are] coming in, asking environmental questions, trying to get an idea of what they’re going to have to comply with. They’re telling us what their plans are. If they’re further along, some of them have set up offices in N.J. They’re looking [for] places where they possibly could store equipment, manufacture equipment, so we’re moving. And that’s very positive. To be quite honest, once the two leases were [announced] in 2014, it’s been kind of glacial,” he said, referring to leases that were awarded in 2015 to RES America Developments and US Wind. “We haven’t moved that quickly, but now things are starting to move. And I think that’s up and down the East Coast.”
MISO last week said it is reviewing stakeholder proposals to improve load forecasts and plan hourly energy delivery on its evolving system, rather than obtaining more forecasts from a Purdue University group.
Executive Director of System Planning Aubrey Johnson said CEO John Bear this summer asked to hold off on committing to continued use of the Purdue State Utility Forecasting Group’s independent load forecast so the RTO could collect alternative proposals for load forecasting from stakeholders.
“He asked us to step back and think about what we’re trying to accomplish,” Johnson said during a special Sept. 7 load forecasting workshop.
In the face of stakeholder criticism, MISO in June abandoned a proposal to have its 140-plus load-serving entities annually assemble four distinct 20-year load forecasts to align with each Transmission Expansion Plan. (See MISO Nixes LSE Load Forecast Plan.) However, stakeholders are now asking for more discussion about MISO’s alternative plan to order four versions of the Purdue forecast, each tailored to one of the futures used to inform MTEP.
MISO said it still plans to pursue four 20-year versions of Purdue’s forecast beginning with the 2020 MTEP, but now it says it wants the university to include monthly forecasts specific to each of the MTEP futures. The RTO is also looking into having third parties supply load shape information on behind-the-meter generation, electric vehicles, energy efficiency, demand response and distributed energy resources.
But MISO said it has been receiving alternative forecasting proposals from stakeholders since last month. Johnson said the RTO is currently working on ways to evaluate the proposals against one another and invited stakeholders to submit more through this week.
MISO now plans to make an announcement on a new load forecasting approach at the November Planning Advisory Committee meeting after holding two more workshops with stakeholders, Johnson said.
“What we’re attempting to do is start a conversation about … why” the forecast needs to change, Johnson said of the workshops.
‘All Hours’
MISO currently plans energy supply around a yearly peak hour on the hottest summer day in its forecasting, though RTO leadership has repeatedly said there is increasing evidence that peak risk occurs throughout the year in all seasons.
“All hours matter in this conversation. In the past … it’s been one peak hour, one dispatch,” said Director of Policy Studies J.T. Smith. “There are a lot of hours and generation mixes that are not being looked at.”
| MISO
Smith said MISO’s current load modeling relies only on historical load shape data, but even MISO’s air conditioning load shape will shift in part because of smart thermostats and hotter days.
MISO adviser Ling Hua said consumption patterns are changing from that of a “sit-down restaurant where the lunch and dinner rushes can be anticipated” to that of a neighborhood bakery.
“In the neighborhood bakery, people walk in and walk out at any time,” Hua said.
“There are risks in the planning environment that we’re not capturing today,” Smith said. “We’re seeing a very baseload-heavy environment turn into something not so baseload-heavy.” In the future, MISO may need to plan transmission for a more localized system, Smith said.
Monthly Forecasts
Hua said MISO hopes to have a 20-year forecast comprising monthly load peak demand and energy forecasts for a “more complete picture of the footprint.” She said the RTO needs more information, including energy efficiency, electric vehicle and load data from non-planning resources such as DR, DER and storage. “Those are really the disruptive technologies right now.”
But she also cautioned MISO not to overburden LSEs with data collection.
Some stakeholders continued to question why MISO needed such a detailed load forecast.
Indiana Utility Regulatory Commission staffer Dave Johnston pointed out that load forecasters failed to foresee the Great Recession that sunk load growth from about 2% to about 0.5% and the shale gas revolution that made natural gas so popular as a fuel source.
“I just throw those out as how different the load forecast can be,” Johnston said. “The need for transmission projects is low because we’re in this low growth era. … Do you have an idea of demand growth … 10 years in the future?”
Smith conceded the impossibility of predicting some trends but said that shouldn’t deter MISO from adopting a more comprehensive approach. He said it may end up that load growth becomes decoupled from economic growth.
“I’m not saying I’m going to be exactly right in my forecast. What I’m looking for is a breakdown of the information,” Smith said.
Alternatives
One stakeholder group has already offered an alternative to MISO’s forecasting proposal.
Members of the Coalition of Utilities with an Obligation to Serve in MISO (CUOS), an ad hoc group of MISO utilities and regulators that has been meeting since 2014, support providing one 20-year baseload forecast that includes monthly non-coincident peak forecasts and monthly energy forecasts. The LSEs’ forecasts would only be used in the MTEP “business as usual” future scenario.
Representing the group, WPPI Energy’s Valy Goepfrich said LSEs could pull from their forecasts and submit separate data on demand served by demand resources, energy efficiency planning resources and behind-the-meter planning resources. She added that, under the CUOS proposal, LSEs would not provide data on demand served by non-planning resources or energy efficiency programs.
Goepfrich stressed that LSE data is integral to whatever forecasting method MISO settles on.
“The LSEs have the best access to their data. That data is proprietary,” Goepfrich said.
Gov. Jerry Brown on Monday signed legislation requiring California to get 100% of its power from renewable and other zero-carbon resources by 2045. He also issued an executive order for the state to achieve carbon neutrality by the same year.
Brown’s actions came as he readied to host a global climate summit in San Francisco and further positioned himself as a policy counterweight to President Trump, who is seeking to withdraw from the Paris Agreement on climate change and undo EPA’s Clean Power Plan.
California Gov. Jerry Brown signed SB 100, a bill that requires the state to have a 100% carbon-free electricity grid by 2045. | Governor’s office
“California is committed to doing whatever is necessary to meet the existential threat of climate change,” Brown said in his signing message for SB 100. “This bill, and others I will sign this week, help us go in that direction. But have no illusions, California and the rest of the world have miles to go before we achieve zero-carbon emissions.”
In addition to requiring investor-owned utilities, publicly owned utilities and community choice aggregators to obtain 100% of their energy from renewables by 2045, the new law sets milestones along the way: 40-44% by 2024; 45-52% by 2027; and 50-60% by 2030. (See Calif. Clean Energy Measure Goes to Governor.)
When the law takes effect in January, California will join Hawaii as the second state to declare its intent to rely entirely on renewable resources such as wind, solar and hydropower.
Brown, meanwhile, will take center stage at the Global Climate Action Summit, with its main events happening Sept. 12-14 at San Francisco’s Moscone Center.
The summit will feature civic and industry leaders from around the world discussing topics such as investments in clean energy, the switch to electric vehicles and the health of the planet’s oceans. Portions of the event will stream live on YouTube, Facebook and Twitter.
The summit and SB 100 are part of Brown’s larger push to deal with climate change as he gets ready to leave office at the end of this year.
In his signing message for SB 100, for instance, Brown reiterated his support for a Western RTO. A bill to begin the process of transforming CAISO into an RTO faltered in the State Senate this year. Similar efforts to create an organized market in the West failed in the two prior years as well. (See related story, Western RTO Proponents Vow To Keep Trying.)
“We must join our neighbors in a power system that integrates utilities across the West,” Brown said in the signing message. “A regionalized electric grid would enhance California’s low-carbon grid by allowing us to share renewable resources with our neighboring states, while reducing costs and increasing resiliency of our grid.”
FERC on Thursday sidestepped yet another dispute between Public Service Electric and Gas and Consolidated Edison, saying a fight over the fate of their shared transmission lines between New Jersey and New York should be resolved in federal court.
The dispute — over two underwater transmission lines compromised by a pier collapse — is evidence of the continuing bad blood over Con Ed’s April 2017 termination of the “wheel” it used to move power from upstate New York to New York City via northern New Jersey.
The damaged B transmission line runs from under the Newport Marina in Jersey City, N.J. (foreground) through Manhattan (background) to Brooklyn. | Newport Associates Development Co.
In May, PSE&G filed a complaint alleging that Con Ed was violating the NYISO Tariff by failing to cooperate in removing dielectric fluid and the transmission cables from the 345-kV B and C lines after B was damaged by a pier collapse in Jersey City, N.J. The lines were built in 1972 and 1980, respectively, to facilitate the former wheeling arrangement.
Federal Court Suit
In June, Con Ed countered by filing suit in U.S. District Court in New Jersey, accusing PSE&G of violating their interconnection agreement by refusing to put the lines back into service.
In a Sept. 6 order dismissing the complaint, FERC said it did not have exclusive jurisdiction over the dispute and declined to assert primary jurisdiction, leaving the matter for the federal court to decide (EL18-143).
The B Line starts at PSE&G’s Hudson Generating Station in Jersey City and terminates at Con Ed’s Farragut Substation in Brooklyn, while the C Line starts in Brooklyn and terminates at PSE&G’s Marion Substation in Jersey City. The transmission lines are housed inside steel pipes encased in concrete.
A 700-foot section of B was damaged in two pier collapses a decade ago, and in 2016 the New Jersey Department of Environmental Protection informed PSE&G that the two lines could be leaking dielectric fluid, an oil used to regulate the temperature inside the steel pipes. The marina owner was sued to remove tons of debris to allow investigation, which showed B to be leaking a gallon of fluid a day. The C Line was de-energized to facilitate the investigation.
Both utilities reported B repaired in August 2017, and they both agree that neither line is leaking now. The U.S. Coast Guard, however, requires the companies to fix the leakage such that dielectric fluid is not seen on the surface of the Hudson River for 15 consecutive days, a requirement they have yet to meet.
‘Pitting Corrosion’
PSE&G said the leak occurred because of “pitting corrosion” after the pier collapse exposed about 700 feet of the steel pipes to river water. Although the initial leak was fixed with the replacement of a 10-foot portion of steel pipe, PSE&G said additional leaks are likely in the unrepaired pipes.
PSE&G asserted that it has authority to unilaterally drain the fluid and remove the transmission cables from its portion of the lines. Con Ed insists its interconnection agreement with PSE&G prohibits it from unilaterally taking the lines out of service; it wants to reintroduce dielectric fluid and re-energize the lines to conduct a test that the Coast Guard proposed.
State and RTO officials lined up on opposite sides of the dispute, with the New Jersey Board of Public Utilities filing comments supporting PSE&G’s complaint, and NYISO and the New York Public Service Commission filing protests opposing it.
NYISO and the PSC said that as interregional transmission facilities, the lines support grid resilience by providing the ISO and PJM with operational flexibility between their service areas. NYISO said its joint operating agreement with PJM allows use of all the phase angle regulators and transmission lines at their border in an emergency.
NYISO also argued that PSE&G’s underlying reason for seeking to remove the lines is that it wants to replace the lines with transmission facilities that will allow it to have more operational control, increasing their commercial value.
PJM said “there is no reliability criteria violation associated with retiring the [B-C lines], even under peak summer conditions,” and that it does not rely on the lines as a part of its black start plan. The RTO also said, however, that if there are resilience benefits “and it is determined to be advantageous to maintain or replace these tie lines,” the utilities should equitably share the cost.
FERC sided with Con Ed in concluding that the B-C interconnection agreements remain effective through 2020.
The commission said it would not assert primary jurisdiction in the dispute because the issue did not raise a policy issue important to its regulatory responsibilities and that “the unique facts and contractual dispute in this case are not broadly applicable to the commission’s policies on interconnection agreements or reliability requirements.”
WASHINGTON — Seeking to persuade a change in FERC policy, the Edison Electric Institute has released a white paper by former Commissioner Suedeen Kelly that proposes raising the hurdles for those challenging transmission owners’ returns on equity.
Kelly, a partner with Jenner & Block who served on the commission from 2003 to 2009, says the commission’s policy of setting ROE complaints for hearing concurrently — or “pancaking” — has increased litigation costs and created uncertainty for TOs.
The iterative filings are a result of FERC’s inability to resolve the cases before the expiration of the 15-month limit on ROE refunds. The pancaked complaints are generally filed shortly after the expiration of the refund period in the earlier, still-pending complaints. (See Playing the ROE Slot Machine.)
“Section 206 of the Federal Power Act mandates a threshold that FERC find that an existing rate is unjust and unreasonable before setting a new rate,” Kelly writes. “By setting complaints for hearing concurrently, without first ensuring that they meet the Section 206 threshold, FERC has created a policy that is not supported by the law, is inconsistent with the intent of Congress, is not workable in practice, and undermines regulatory expectations for a stable and predictable ROE.”
The paper largely repeats arguments Kelly made unsuccessfully in a 2016 EEI protest in the fourth complaint against the New England Transmission Owners (EL16-64).
It cites the “increasing number” of Section 206 complaints FERC has received since 2011. EEI says there were between five to nine complaints filed annually in 2012-2016 and 10 complaints filed in 2017.
FERC declined a request for comment.
In Opinion 531 in June 2014, FERC unanimously adopted a two-step discounted cash flow analysis for determining electric transmission ROEs. Long used for natural gas and oil pipelines, the methodology incorporates long-term growth rates.
The commission then voted 3-1 over its first application of the new formula, tentatively setting the ROE for New England TOs at three-quarters of the top of the “zone of reasonableness,” a departure from the prior practice that used the midpoint in the range. (See FERC Splits over ROE.)
‘Seven Years and Counting’
EEI cites the New England TOs’ case to illustrate its concern over FERC’s procedures.
It resulted from a September 2011 complaint by New England state officials and others that FERC set for hearing seven months later. The administrative law judge proceedings lasted more than a year, resulting in an ALJ initial decision in August 2013.
Opinion 531, almost 11 months later, was followed by a paper hearing that resulted in Opinion 531-A in October 2014, in which the commission decided that gross domestic product is the appropriate long-term growth rate to use in the analysis. In Opinion 531-B in March 2015, the commission rejected rehearing requests, prompting a petition to the D.C. Circuit Court of Appeals, which remanded the case (Emera Maine v. FERC) back to the commission in April 2017.
The court said FERC had failed to establish that the New England TOs’ existing ROE was not just and reasonable before imposing a new one. (See Court Rejects FERC ROE Order for New England.) The case remains pending.
“In sum, the process leading to Opinion No. 531 took over two and a half years,” EEI said. “In the meantime … four subsequent complaints were filed, effectively extending the period under which the New England Transmission Owners’ ROE is subject to litigation to almost seven years (and counting).”
Higher Threshold Sought
Kelly said the commission has been too permissive in setting ROE challenges for hearing.
“Currently, FERC’s practice is to set an ROE complaint for hearing based merely on the presentation of a new discounted cash flow analysis that produces a lower number than the rate on file. This threshold is too low and invites frequent initial and pancaked complaints.”
In response to questions from RTO Insider, Kelly said, “We suggest that where an ROE remains within the zone of reasonableness, a complainant must do more to show that in the particular circumstances of that utility or group of utilities, the evidence shows that the zone of reasonableness is not a reliable indicator of the range of just and reasonable rates. To do otherwise makes the zone of reasonableness almost meaningless as a tool for both the commission and transmission owners and injects significant uncertainty into FERC’s ratemaking processes.”
Attorney David E. Pomper of Spiegel & McDiarmid, who argued the Emera case for Massachusetts, said EEI’s suggestion runs counter to the D.C. Circuit’s affirmation that FERC need not “show that an existing rate is ‘entirely outside the zone of reasonableness’ before it can exercise its Section 206 authority to change that rate.”
“I don’t think they’re going to get the D.C. Circuit to reverse on that,” Pomper said in an interview.
Symmetry
Kelly disagrees with FERC’s reasoning that it must allow the pancaked complaints because Congress intended “symmetry” between the rights of utilities to file for rate increases under FPA Section 205 and the rights of complainants to seek rate cuts under Section 206. “Congress explicitly established different procedures and different burdens of proof” under the two sections, Kelly said.
Section 205 allows a utility to seek new rates at any time, with FERC in what the D.C. Circuit has termed a “passive and reactive role” of determining whether the new rates are just and reasonable. Under Section 206, FERC may change rates on its own motion or in response to a complaint, but only after first finding the existing rate unjust and unreasonable — the requirement the D.C. Circuit said FERC failed to meet in Emera.
“FERC has stretched the intent of Congress by failing to reconcile its justification for allowing pancaked complaints with the legislative history behind the adoption of the 15-month limit on refunds explicitly included in the statute,” Kelly said. “It has also ignored the critical differences in procedures and burdens of proof between FPA Sections 205 and 206.”
Pomper disagreed with Kelly’s interpretation of Congress’ balancing of Sections 205 and 206. “The cost of capital can change rapidly,” Pomper said. While rates have been relatively stable since the inflationary 1970s, “with large federal deficits that might change,” he said.
Kelly argues that in considering whether to set ROE complaints for hearing, FERC should consider how much time has passed since the existing rate was approved and set “a pragmatic time-based threshold within which it will not entertain a new ROE complaint absent extraordinary and compelling circumstances.”
“In the MISO case, complaint No. 2 was filed [and] set for hearing before we had an outcome in complaint No. 1,” said Nina Plaushin, vice president of regulatory, federal affairs and communications for ITC Holdings, in an interview. “So how did FERC determine that that ROE was unjust and unreasonable?”
Chilling Investment?
EEI says the rise in ROE litigation is creating “unpredictability and instability” in returns for transmission assets. Asked for evidence that the uncertainty is making it difficult to raise investment capital, EEI cited only a 2015 report by Wolfe Research, which concluded — based on Opinion 531 and the commission’s rulings on unrelated matters — that “FERC is increasingly out of touch with investors.”
Historical and projected transmission investment (nominal dollars) | EEI
Pomper said there is no evidence TOs are having difficulty raising capital, citing the high level of transmission construction and legal fights over rights of first refusal to build projects. At the annual EEI Financial Conference, “you will see many, many presentations saying ‘look at how much FERC exposure we have,’” Pomper said. “If it was really a negative, you wouldn’t see them touting the investments.”
Plaushin, president of the transmission owner advocacy group WIRES, acknowledged that “it hasn’t been that challenging to get debt.”
“Are people having trouble [raising] equity?” she continued. “I think it’s a very difficult thing to prove or disprove one way or the other.”
There is no doubt, however, that FERC’s ROE determinations can have an impact on utilities’ earnings. In a report following the Emera ruling, Wolfe said an increase of 100 basis points is worth about 3% in earnings per share for Eversource Energy and Avangrid and about 1% for Alliant Energy and Ameren.
Discovery Delays
EEI’s paper contends FERC’s discovery proceedings are causing delays, saying ROE is “a single issue that should not require extensive discovery or lengthy and protracted full trial-type hearings to resolve. FERC has utilized specially designed and narrowly tailored procedures in other, more complex contexts.”
Kelly said FERC should consider shortened discovery and testimony procedures rather than treating ROE hearings like a full rate case. “In a full rate case, the prudence and amount of various cost inputs are determined individually and can require extensive discovery and testimony. Most utilities now have formula rates that predetermine prudence and flow through costs without further review, absent a challenge,” Kelly said.
Pomper responded: “It’s precisely because you’ve got formula rates, where there are only a few stated elements left to be determined by the commission, that we’re now focusing on ROE. It used to be when utilities had stated rates that you’d have few [Section] 206 proceedings because lots of things were changing. Even if cost of capital was going down, other costs were going up.”
As for the length of the proceedings, Pomper says, “I wish it could go faster … but it’s not out of line with how FERC decides all kinds of cases.”
Wrong Problem
Pomper said EEI is “addressing the wrong problem,” saying the real issue is the “range-based” methods used to set ROEs for RTO-wide rates in ISO-NE and MISO, which consider the highest and lowest rates among a utility’s “proxy group.”
“It’s essentially random. It’s completely bogus math and statistics,” Pomper said.
Using the median in all cases would make results “stabler from case to case. You wouldn’t have the reason to come in with a new complaint,” Pomper said. “Fix the method and the procedure would follow.”
Former FERC Chairman Jim Hoecker, now counsel to WIRES, said the group was seeking stability and predictability when it filed its 2013 petition for a policy statement, which led to Opinion 531.
“I know that [then-Chair] Cheryl [LaFleur] struggled really hard in 531 to try and achieve that,” he said in an interview. “But as in all things at the commission, it’s a matter of compromise.”
Plaushin praised Opinion 531 for providing justification for awarding higher ROEs on transmission than states approve for less risky distribution projects. “I don’t want to be negative about the commission because … they made a genuine attempt to work this out,” she said. “Unfortunately, it wasn’t effective the way they wanted it to be and so now [because of the remand] we need a new solution.
“Why we’ve had a delay this long in responding to the remand, I don’t know. It’s been a while.”
Plaushin said although many ROE cases involving individual utilities have been resolved through settlements, that is not practical for the regional ROE cases in MISO and ISO-NE.
“When you’re talking about regional cases with so many utilities involved, it’s very difficult to do a settlement, especially when in some of those cases there are state regulators who are the ones who would have to settle. And, of course, why would they settle for a number that’s higher than what they granted in their own state [for distribution assets]?”
As to those who suggest eliminating pancaked complaints by extending the refund period beyond 15 months, Plaushin said, “I think that we need to be intellectually honest about” what the revised limit should be. “Four complaints — is [that] too long to extend the refund period?
“Obviously the solution to all this is to get these cases adjudicated quicker,” she added. “That would solve a lot of problems for everyone.”
PJM and Monitoring Analytics, its Independent Market Monitor, have agreed on a deal that will extend the Monitor’s contract through 2025 and require the Monitor to submit to an annual independent audit. The agreement was filed for FERC approval Friday (ER18-2402).
In a concurrent filing, the parties also agreed the Monitor will provide to PJM more of the data market participants submit into MIRA, the Monitor’s online database, so participants don’t have to send the data to both the RTO and the Monitor. The additional sharing includes data used in generators’ fuel-cost policies. The filing also requires both parties to inform the other of changes to their systems (ER18-2403).
The new audit requirement “provides for a review intended to ensure that the services being provided to PJM by Monitoring Analytics are being completed consistent with the systems and controls in place for the provision of those services, similar to the reviews PJM conducts of its own systems and controls,” the RTO said in the filing.
The Monitor’s current contract runs through 2019, and stakeholders — particularly state regulators and consumer representatives — have been urging the parties to come to agreement early. (See “IMM Support,” Advocates Push PJM Board for Explanations at Annual Meeting.)
The early agreement also avoids some of the drama of the previous contract, which began in September 2013. As the initial six-year contract, which went into effect on June 30, 2008, neared its expiration, PJM’s Board of Managers announced plans in March 2013 to issue a request for proposals. The Organization of PJM States Inc. joined industrial consumers and cooperatives in protesting the decision, and the parties eventually agreed to an extension. By PJM’s annual meeting in October, a potential crisis had passed. (See Board, OPSI Bury the Hatchet over Monitor Contract.)
FERC on Thursday rejected financial stakeholders’ request for rehearing of its Feb. 20 ruling reducing the number of bidding nodes for virtual transactions (ER18-88-002).
The commission also upheld its rejection of PJM’s proposal to allocate uplift to up-to-congestion transactions (UTCs) as it does to increment offers (INCs) and decrement bids (DECs) (ER18-86).
Virtual Transaction Nodes
The commission said that XO Energy and the Financial Marketers Coalition merely rehashed arguments they had made against the node reduction proposal. (See FERC OKs Slash in Virtual Bidding Nodes for PJM.)
The changes reduce by almost 90% the number of bidding nodes, limiting INCs and DECs to those where either generation, load or interchange transactions are settled, or at trading hubs where forward positions can be taken. They also barred UTCs from zone, extra-high-voltage and individual load nodes. The changes reduced the number of INC/DEC trading nodes from 11,727 to 1,563, and UTC nodes from 418 to 49.
PJM said this trading pattern is “indicative of the low-risk positions that can be extremely lucrative without adding commensurate value to the market,” justifying its proposal to reduce the trading nodes for UTCs. | PJM
FERC did accept PJM’s request to change the effective date for the changes from Jan. 16 to Feb. 22, 2018. PJM said it intended to make the changes prospectively and that in its Dec. 22 response to a deficiency letter the RTO had neglected to change its requested effective date. PJM said the January date would be disruptive to the market, as it would have to remove all virtual transactions at points no longer eligible for bidding and re-execute the day-ahead market.
Commissioner Cheryl LaFleur issued a partial dissent, repeating her assertion that PJM had not justified reducing nodes for UTCs.
“As I stated in my partial dissent, I believe that UTCs provide value to the market and that reduced granularity in their use is a move in the wrong direction,” she said. “I would, however, be open to other solutions more targeted to the specific problems that PJM has identified.”
Uplift for UTCs
PJM complained that in its Jan. 12 rejection of the RTO’s uplift proposal, FERC dismissed the proposal outright, without setting it for hearing, or considering parts of the proposal separately. (See FERC: PJM Uplift Proposal for UTCs Falls Short.)
PJM claimed that, unless its filing was deficient, the commission could only accept the proposal or suspend it for hearing. But FERC said it was under no obligation to set the proposal for hearing. The RTO failed to demonstrate that the proposal would result in just and reasonable rates under Federal Power Act Section 205, the commission reiterated, “as it proposed to treat different financial transactions, with differing characteristics and effects, as if they were the same.”
However, FERC did reverse itself to accept PJM’s proposal to exclude internal bilateral transactions from uplift calculations, which the RTO said the commission should have considered separately. The commission directed PJM to submit a compliance filing in 30 days implementing the change.
PJM can still propose a different way to allocate uplift to UTCs, as FERC had dismissed the proposal without prejudice. “We also note, however, that any such hypothetical, future filing must address the concerns noted above, including the commission’s concern with PJM’s proposal to allocate uplift to a UTC as though it were two separate transactions, an INC and a DEC,” the commission said.
WASHINGTON — Public power representatives reiterated their case against mandatory capacity markets last week, teaming with wind and solar advocates for a one-day conference as a forum for their criticism.
“After spending or committing over $130 billion … in capacity payments in ISO-NE and PJM, I can safely say that almost nobody is happy with the state of those markets, which remain in a state of flux,” Sue Kelly, CEO of the American Public Power Association, told the inaugural Future Power Markets Summit.
“We think it’s time to rethink them. We believe that a resource adequacy regime that’s based on longer-term planning, bilateral contracting [as in MISO and SPP] and increased respect for state and local decision-making and autonomy — with a residual market capacity market for those who feel the need to go there — actually makes more sense,” she said during a lunch keynote at the conference.
Brian Forshaw, who represents public power systems at the New England Power Pool, used almost identical language. “The consensus of stakeholders throughout the [New England] region is that out of all of our market constructs, the energy market is probably the only one that’s working reasonably well,” he said. He acknowledged concerns that the region is “overly reliant” on natural gas.
James Wilson, a consultant who has worked for environmental groups and state consumer advocates in PJM, lamented that the capacity market — intended as “training wheels” to be removed once the markets found their balance — have remained, saying he would prefer an energy-only market.
Jay Morrison, vice president of regulatory issues for the National Rural Electric Cooperative Association (NRECA), compared capacity markets to a different method of conveyance, likening RTOs’ efforts to tweak the markets to attempting to convert a Ford Pinto into a Formula One race car. “It’s the wrong tool,” he said.
Not everyone at the Sept. 5 conference was critical, however. Katie Guerry, vice president of regulatory affairs for demand response aggregator EnerNOC, noted that DR gets virtually all of its revenue from the “availability payment” from capacity markets and very little from energy or ancillary services.
Although PJM’s capacity market “is the subject of a lot of concern and criticism, it is the gold standard when you go into countries around the world,” Guerry said. She noted that Alberta is adopting a capacity market with DR on the supply side, like PJM.
Aside from losing DR revenue, “it would significantly increase our costs to serve if there were no centralized markets at all,” Guerry said. “It would be very prohibitive for us.”
The conference, which attracted about 80 people, came after a summer that observers expected to stress test ERCOT’s energy-only market because of its reduced capacity reserves. In addition to APPA and NRECA, the summit’s sponsors were the American Wind Energy Association, American Council on Renewable Energy, Solar Energy Industries Association, Large Public Power Council and Energy Systems Integration Group, a nonprofit educational association for engineers, researchers, technologists and policymakers.
Texas survived the summer with surprisingly modest prices and no generation shortfalls, thanks to better-than-expected generation performance and an early summer system peak that took advantage of above-normal wind.
The capacity market provides certainty that resources acquired will be available, Garza said. “In ERCOT you don’t get that certainty. And [certainty] comes with some cost: Any of us who have a fixed-price mortgage are paying for that certainty.”
Fallacy of Fungibility
The latest challenge for capacity markets has been the effort to accommodate state preferences for renewable and nuclear generation without suppressing auction prices.
Morrison said state subsidies are only an issue because of the fallacy that capacity is a single fungible product.
“The RTOs do a good job of focusing on short-term reliability and low short-term marginal costs, and that’s great. But we need a lot more than that. We need long-term reliability; long-term price stability; environmentally favorable resources,” he said. “And if the one product that’s available is this fungible capacity product that the RTO has bought because they know better than us and our states, that doesn’t meet our needs.”
In June, FERC ordered PJM to expand its minimum offer price rule (MOPR), which now covers only new natural gas generation. The commission’s 3-2 ruling rejected both PJM’s capacity repricing proposal and the Independent Market Monitor’s MOPR-Ex proposal. (See PJM Unveils Capacity Proposal.)
Wilson was optimistic about the “resource specific” fixed resource requirement (FRR) proposal that he and consultant Rob Gramlich developed on behalf of environmental groups and the D.C. Office of the People’s Counsel.
“With a strong MOPR and this resource-specific FRR, we can have our RPM [Reliability Pricing Model] capacity market that is completely free of the impact of any subsidized resources because [they have] all been pulled out. It’s only the competitive resources [that remain]. And off to the side [are] those policy resources … they’re matched up with a commensurate amount of load, so customers are not paying twice. We’re … potentially getting to a pretty good place if we can make this FRR RS-thing work.”
Attorney Susan Bruce, who represents the PJM Industrial Customer Coalition, was less sanguine. “This is a case where there’s no good answer from my clients’ perspective. [We’re] just trying to find the least bad option,” she said.
She and Guerry expressed concerns over the modified FRR suggested by FERC.
“The FRR alternative, at least as it was put into the stakeholder process, would provide a very easy platform to sort of sink centralized capacity markets,” she said, predicting it would result in a “patchwork quilt of state policies” and a temptation to save uneconomic resources.
Guerry said the FRR alternative “makes us very nervous,” noting bilateral trades “are not transparent” to her company.
“Bilaterals are perfectly transparent to those in the market,” Wilson insisted.
But Devin Hartman, manager of electricity policy at the free market think tank R Street Institute, also was skeptical. He said it’s unworkable to administratively correct for subsidies in a pricing mechanism, calling it “a recipe for unintended consequences.”
“What constitutes a material subsidy?” he asked. “We’re going to have some fun with that — in perpetuity. It’s important to recognize that these markets have always had subsidies. Every resource has some degree of price subsidy. I don’t see how [PJM Monitor] Joe Bowring is going to come up with a screen to price correct for Price-Anderson,” referring to the law limiting liabilities for nuclear plant operators. “Where are you going to draw the line?”
