Pennsylvania-based Coaltrain Energy has agreed to pay $4 million in disgorged profits to resolve a FERC investigation into accusations that the company engaged in market manipulation in the course of its up-to-congestion transaction (UTC) trading in 2010.
In its order approving the stipulation and consent agreement issued Oct. 11, FERC said the company “had engaged in market manipulation by placing UTC trades for the sole or primary purpose of collecting marginal loss surplus allocation (MLSA) payments, rather than to profit from price changes.” Under the agreement, Coaltrain neither admits nor denies the alleged violations (IN16-4).
In a 2016 Order to Show Cause, FERC alleged that in 2010, the company shifted from legitimate UTC trading — in which companies aim to predict the changes in spreads between PJM’s real-time and day-ahead markets — to profiting off PJM’s MLSA alone by minimizing the UTC price spreads and collecting refunds of a portion of the transmission loss charges from PJM. (See FERC: Spy Software Provides Evidence of UTC Scam.)
MLSA is designed to account for the loss of electricity as it is transmitted between its source and sink; traders receive rebates proportionate to megawatts delivered. FERC alleged that Coaltrain made trades between nodes in both directions to simply collect the rebates.
The agreement marks the last of three investigations FERC launched over allegedly manipulative UTC trading in PJM. In each case the commission said traders used risk-free strategies designed to maximize line-loss rebates from MLSA, instead of trying to predict price spreads between the RTO’s day-ahead and real-time markets. (See Trader Agrees to Pay $2.7M in Win for FERC and Powhatan Energy to Declare Bankruptcy.)
FERC also accused Coaltrain of providing “false and misleading statements to [FERC Office of] Enforcement staff about the existence of records created by employee monitoring software.”
That charge stems from investigators learning of employee-monitoring software that captured evidence of trading and messaging, which was provided by a former Coaltrain employee. FERC claims that the company concealed information about the software and did not make access readily available; the company had said in its March 2016 response to the show-cause order that it hadn’t occurred to staff that the software contained information relevant to the investigation. (See Traders Deny FERC Charges; Seek Independent Review.)
In addition to Coaltrain itself, the agreement also lists co-owners Peter Jones and Shawn Sheehan and traders Robert Jones, Jeff Miller and Jack Wells as defendants in the case. In the show-cause order, FERC had previously sought more than $42 million in civil penalties from the company and individual defendants.
The fine is to be split into five disgorgement payments to PJM over the same number of years, which the RTO will distribute to its members in a manner to be approved by the commission. Should the provisions be abided by, the agreement will end a 2016 lawsuit FERC filed against Coaltrain in the U.S. District Court for Southern Ohio.
The agreement notes that while FERC’s investigation into Coaltrain will cease, there could be additional sanctions still to come.
“Coaltrain acknowledges and agrees that this may subject it to additional action under the enforcement provisions of the FPA, which in turn may result in additional sanctions separate and apart from the $4,000,000 restitution payment required to be made by Coaltrain pursuant to this agreement.”
Virginia Gov. Glenn Youngkin (R) is doubling down on his efforts to bring the nation’s first commercial small modular nuclear reactor (SMR) to abandoned coalfields of Southwest Virginia, announcing plans on Friday to provide up to $7 million in state funds to help kickstart the project.
Speaking at an abandoned mine site in the southwest corner of the state, Youngkin announced he would be proposing a $10 million Virginia Power Innovation Fund in his next budget, with half the money dedicated to “our moonshot mission to establish the very first small modular reactor right here in Southwest Virginia within the next 10 years.”
Earlier in the day, the governor and U.S. Rep. Morgan Griffith (R-Va.) announced another $10.6 million in grants from the state’s federally funded Abandoned Mine Land Economic Revitalization (AMLER) program, including another $2 million for the Energy DELTA Lab, an innovation testbed, launched Oct. 4.
The test bed is being developed with $975,000 in previously announced AMLER funds and has been in the works for four years, according to the project’s website, which makes no mention of nuclear as part of its plan for future energy development.
Rather, the website outlines two potential projects. One would seek to draw in data centers, which would be cooled with geothermal technology using “the billions of gallons in water collected in underground mines.” The second, called Project Energizer, would develop modular pumped hydro storage that could be paired with solar or wind projects to provide dispatchable baseload power.
Nuclear power currently provides about 29% of Virginia’s electricity. | EIA
But Youngkin has been keenly focused on the idea of bringing nuclear development to the southwestern part of the state since the release of what he called Friday his “all American, all-of-the-above“ energy plan on Oct. 3. The plan sees Virginia as particularly well positioned to lead SMR development, pointing to nuclear engineering programs at Virginia Commonwealth University and Virginia Tech, and companies such as Huntington Ingalls, which maintains nuclear submarines and aircraft carriers at Norfolk Naval Base. (See Gov. Youngkin Releases 2022 Energy Plan.)
“By marshaling the state and federal resources, we will establish a Virginia nuclear innovation hub that will bring together Virginia’s nuclear stakeholders … universities, corporate interests [and] research dollars to develop new and emerging nuclear technologies for deployment right here in the commonwealth,” Youngkin said Friday. “And we will work with our regional allies to go after more than our fair share.”
He envisioned the hub performing “research on advanced material manufacturing and design; methods to improve reactor lifespans and ensure safe operations; on advanced computation and machine learning; on workforce training; and strategies to improve the nuclear fuel cycle and supply chain, including recycling spent nuclear fuel.”
Alireza Haghighat, director of the Nuclear Science and Engineering Laboratory at Virginia Tech, stressed the integral role of nuclear as clean, baseload power. “Nuclear is a must to continue not only affordable, reliable energy [but] also to achieve what we all look for: zero carbon emissions. … You have to be realistic and just follow the science.”
According to figures from the U.S. Energy Information Administration, Virginia’s two nuclear plants, owned by Dominion Energy (NYSE:D), currently provide 29% of the state’s electric power. Hydropower and non-hydro renewables account for 11%, with fossil fuels — predominantly natural gas — providing the other 60%.
One of the Dominion plants, the Surry nuclear plant, won a 20-year license extension from the Nuclear Regulatory Commission in 2021. The commission is reviewing the utility’s application for a similar extension for its North Anna plant.
Surry nuclear power plant | NRC
Under the 2020 Virginia Clean Economy Act (VCEA), Dominion is required to decarbonize its electricity supplies by 2045, increasing clean power 3% per year through 2030 and 4% per year through 2045. Youngkin’s Energy Plan criticizes the VCEA as mandating the retirement of baseload resources and recommends that it be reauthorized every five years.
Local Criticism
While the small audience at Friday’s event responded enthusiastically, Youngkin’s announcement drew quick criticism from local environmental and community groups.
“The announcement comes as a surprise to many key stakeholders in the region,” according to a press release from Appalachian Voices, a community group that has supported the growth of solar in Southwest Virginia. “No local citizen groups were informed about the governor’s visit — nor have any been invited to participate in the planning of the location and development of the new energy infrastructure.”
“Project development processes that leave out community voices [are] the wrong way to build support for a proposal,” said Rebecca Shelton, director of policy and organizing at the Appalachian Citizens’ Law Center, who was quoted in the release. “Time and again, the way residents learn about a new project is through a press announcement. There is every reason to be skeptical about the benefits of a project when it’s planned behind closed doors.”
While Appalachian Voices supports clean energy and the development of new technologies, Adam Wells, the group’s regional director of community and economic development, called for “a new model of energy production that centers equity, justice and communities. So far, it appears that this [nuclear] effort misses that opportunity — all the more alarming given the well documented social and environmental problems associated with nuclear energy.”
Groups like Appalachian Voices and The Nature Conservancy have been pushing forward on bringing solar development to Southwest Virginia and its abandoned mining sites.
Earlier in the week, Appalachian Voices and other members of the region’s Solar Workgroup cut the ribbon on a new rooftop solar installation at Wise Elementary School, one of 12 schools in Wise and Lee counties the workgroup is helping to go solar. Apprentices from a local community college training program worked on the project, according to a press release.
The Nature Conservancy is also developing 120 MW of utility-scale solar on abandoned mine sites in its Cumberland Forest Project, 253,000 acres of preserved forest land in Southwest Virginia and along the Tennessee-Kentucky border.
The Western Power Pool’s future independent board of directors will include the previous CEO of PJM, a former member of the Western Energy Imbalance Market’s Governing Body and the WPP’s present board chair, among others.
The WPP’s current board of directors last week approved the slate of nominees who will serve on the new independent board once the group’s Western Resource Adequacy Program (WRAP) is approved by FERC. The federal regulator requires organizations under its jurisdiction to maintain independent boards.
“This is an important step in the path toward WRAP implementation,” WPP Treasurer Mary Ann Pease said in a press release Friday. “I look forward to the continued development of a sustainable resource adequacy program, with the incredible benefits it will bring to participants, while ensuring we continue to deliver the benefits and cost savings the Western Power Pool has long provided our members and our region.”
According to the release, the board members were selected after a monthslong “continent-wide” search led by WPP’s 14-member Nominating Committee and assisted by an executive search firm.
“The committee’s stated criteria for candidates included electric industry, regulatory, general management, Western electric system or organized market experience; geographic diversity, so no region was overrepresented; diversity of perspectives, including professional background, gender, ethnicity and life experience; and strong collaboration skills,” WPP said.
Among those chosen to sit on the new board is current WPP board Chair Bill Drummond, who has held that position since 2018. Drummond formerly led the Mid-West Electric Consumers Association and previously served as administrator and deputy administrator of the Bonneville Power Administration.
But perhaps the most well known industry figure on the new board is Andy Ott, former CEO of PJM, the largest RTO in the country. Ott was at the helm of PJM when it kicked off an effort to partner with now-defunct reliability coordinator Peak Reliability to create an organized market that would compete with CAISO’s own efforts to expand into other parts of the West. (See Q&A: PJM’s Ott Still Looking West.)
The PJM-Peak Reliability effort dissolved after CAISO moved to undercut Peak’s core business by offering RC services to Western utilities at lower costs. Peak closed its doors at the end of 2019 after nearly losing nearly all of its customers to competing RCs.
Ott retired from PJM in 2019 amid the fallout from a massive default by a trader in the RTO’s financial transmission rights market. (See PJM CEO Andy Ott to Retire.) He is currently director of technical operations at Tapestry, X Development’s “moonshot” for the electric grid.
WPP’s other independent board members include:
Doug Howe, former chair of the WEIM’s Governing Body and past member of New Mexico’s Public Regulation Commission. Howe is currently a consultant for the West Coast Public Utility Commissions’ Joint Action Framework on Climate Change. He previously led the Global Power consulting group for international consultancy IHS CERA and worked for various utilities.
Michelle Bertolino, who served as director of Roseville Electric Utility in California for 12 years before retiring this year. Bertolino previously worked for the Sacramento Municipal Utility District, San Francisco Public Utilities Commission and KPMG Peat Marwick. She has served as president of the Northwest Public Power Association and the California Municipal Utilities Association, and as chair and commissioner of the Balancing Authority of Northern California and the Transmission Agency of Northern California.
Susan Ackerman, who last year retired as chief energy officer of the Eugene Water & Electric Board in Oregon. Before that Ackerman served as an attorney for BPA, an attorney and regulatory manager for NW Natural, and as a commissioner and chair of the Oregon Public Utilities Commission from 2010 to 2016.
Current board members Pease and Secretary Scott Waples will hold non-voting advisory seats on the new board, which will take effect after FERC approves the WRAP tariff and the program receives commitments from a “requisite” number of participants, WPP said.
“The varied backgrounds and expertise the new board members bring are first class,” Waples said. “The Western region, and the customers who rely on a reliable source of electricity, are in very good hands.”
ISO-NE is narrowing down its options as it moves forward with revamping its process for resource capacity accreditation (RCA).
In a presentation to the NEPOOL Markets Committee last week, ISO-NE officials gave an update on their thinking, which included a firmer decision to work on a marginal reliability measure rather than other options, including an average approach.
The marginal approach, which ISO-NE has been leaning toward from the beginning, sets a resource’s accredited capacity based on the “marginal reliability impact [MRI] of an incremental change in size.” (See ISO-NE Starts its Capacity Accreditation Journey.)
In its latest update, the grid operator said that marginal approaches are the only ones that are truly cost-effective.
Because the average approach, which accredits resources based on their share of their class’s total reliability contribution, does not “yield substitutable accredited capacity, there is always a better way to set FCA [Forward Capacity Auction] awards that result in the same level of reliability at lower cost,” the RTO said in its presentation to the committee.
The marginal approach does put forward substitutable accredited capacity, so “there is not a better way to set FCA awards that result in the same level of reliability at lower costs.”
“As a result, the ISO cannot support a non-marginal approach to accreditation and will pursue an MRI approach as part of the RCA reforms,” said RTO economist Steven Otto.
At the MC meeting last week, the group backed that up with new numbers from an analysis that it commissioned from GE Energy Consulting.
“At high penetrations, average and marginal accreditation have vastly different results for clean energy resources,” the analysis says. In its model, renewables plus batteries under marginal accreditation would get capacity awards of about 2,200 MW less in 2028 and 6,400 less in 2040 compared to average accreditation.
“Socializing over half of the total reliability contributions of clean resources could result in a reduced market signal for reliability in clean resource selection and development,” the group said. It urged ISO-NE to thoroughly examine the tradeoffs between the two approaches and not dismiss the possibility of a hybrid between them.
NRDC also called on the grid operator to look at whether a seasonal capacity auction and capacity accreditation might be worth considering in light of the changes in seasonal peak load in New England.
Also at the MC meeting last week, RENEW Northeast gave a presentation laying out its own set of design principles for capacity accreditation and promising to use them to assess ISO-NE’s proposals down the line.
The California Energy Commission updated its load management standards Wednesday in anticipation of residents owning millions of grid-connected electric vehicles and “smart” appliances that can respond to hourly or sub-hourly price signals from utilities and CAISO.
The regulatory update was the latest move by energy authorities in California to shape load to respond to times of abundant solar power or shortfalls during summer peak demand as the state advances toward its 100% clean energy goal by 2045 while struggling to maintain grid reliability.
“This update is a huge leap into the 21st century, using digital approaches to unlock benefits for consumers by enabling them to automate their electricity use around cheaper rates and changing grid conditions,” CEC lead Commissioner Andrew McAllister said in a statement following the unanimous vote. “Automated load management reduces energy bills, makes better use of abundant renewable energy resources available during the day, and strengthens grid reliability.”
CAISO and the California Governor’s Office have increasingly relied on demand response to head off shortfalls during the past three summers following the rolling blackouts of August 2020. Those efforts have targeted large industrial users and asked ships in port, including Navy vessels, to disconnect from shore power during strained grid conditions.
CAISO barely avoided ordering utilities to shed load in September after the governor’s Office of Emergency Services sent out a text alert to 27 million cell phones warning of imminent blackouts. Within five minutes, the unprecedented alert resulted in a 2,100 MW drop in demand compared to CAISO’s hour-ahead forecast.
Like the CEC, the California Public Utilities Commission (CPUC) is also seeking to use dynamic pricing and demand-side management as a way to manage load. In July, it opened a proceeding aimed at shoring up grid reliability and soaking up more solar electricity by using real-time rates to influence customer demand. (See CPUC Opens ‘Critical’ Demand Flexibility Proceeding.)
The state’s current patchwork of demand response programs, which pay customers to reduce consumption, is insufficient, the CPUC said in a June white paper. The report identified strategies for broadening demand-side efforts, including by introducing dynamic energy prices based on real-time wholesale energy costs and localized marginal costs.
The Energy Commission’s decision instructs the state’s largest investor- and publicly owned utilities to develop retail electricity rates that change at least hourly to reflect wholesale electricity costs and other factors, and to regularly update those rates in a CEC database called the Market Informed Demand Automation Server.
The updated standards take effect April 1, 2023, for IOUs Pacific Gas and Electric, Southern California Edison, San Diego Gas & Electric; publicly owned utilities Los Angeles Department of Water and Power and the Sacramento Municipal Utility District; and large community choice aggregators (CCAs) that deliver more than 700 GWh of electricity annually.
The utilities and CCAs must also “educate customers about time-dependent rates and automation technologies to encourage their use,” the CEC said in the statement, which focused on the potential cost-savings to consumers. Affected devices would include smart thermostats, heat pumps, water heaters and EVs connected to the grid.
“Today’s action is expected to produce $243 million in net benefits over 15 years and could reduce annual peak hour electricity use by 120 GWh, equivalent to powering 20,000 average California homes for a year,” it said.
Combined, the IOUs and POUs affected by the new regulations have about 12.75 million electric customer accounts. Adding in the large CCAs, the CEC’s projected $243 million in net benefits amount to less than $1 per year per customer account over the next 15 years.
ATLANTA — Facility ratings, and the challenge of keeping them up to date, were a recurring theme on the second day of the North American Generator Forum’s Annual Compliance Conference, held at NERC’s headquarters, with multiple presentations on the subject from industry stakeholders.
NERC’s FAC-008-5 reliability standard, which governs facility ratings, was a frequent reference during the day’s discussions. Mike Gabriel, a co-founder of consulting firm Greybeard Compliance Services and NAGF board member who focuses on NERC compliance, walked attendees through the preparation process for an audit of the standard, reminding them that being upfront with any potential instances of noncompliance would be a major plus in the eyes of their regional entities.
“You’re trying to find what the auditors are going to find before they do it. You’ve got to beat them to the punch — give them nothing to mess with you about,” Gabriel said.
Acknowledging that performing a full walkdown of existing equipment can be daunting for even a moderately sized utility, much less a large one, Gabriel said that registered entities must nevertheless be prepared to take a critical look at their facilities and challenge all their assumptions.
“Your existing FAC-008 equipment list — you want to have that, and assume it’s not 100% accurate. If you follow what you already have, you’re not bringing any value to the table,” he said. “Do you have these nameplates already photographed or not? Do you have some other proof? Do you have design documents? Or is it just a reading on a one-line diagram somewhere?”
The reason for this level of detail is not because auditors are obtuse or rulebound, but because experience has taught industry participants — not just NERC — that design documents, no matter how detailed, quickly become irrelevant as parts are replaced through regular maintenance and repairs, Gabriel said. Improper facility ratings have become a frequent source of compliance issues across the ERO Enterprise, with penalties of over $200,000 levied against utilities in multiple regions over the last two years. (See SERC Urges Industry Effort on Facility Ratings.)
Gabriel added that entities should also be prepared to bring in outsiders to get a fresh perspective, warning that even the most conscientious internal review is vulnerable to overlooking crucial details of facilities with which they have spent years.
“Think about how the human mind works. When you drove to the airport to get here … how observant were you [of] all the details along the way, or were you on the phone listening to some music?” he said. “When you walk past your plant, it takes a lot of concentration to … really scrutinize [everything]. [If you have] that second set of eyes that you trust and you gave them free will to say anything … now you’re getting something.”
Along with Gabriel’s audit presentation, Tim Ponseti, SERC Reliability’s vice president of operations, updated attendees on the Facility Ratings Themes and Lessons Learned report that the RE released earlier this year. SERC used data from hundreds of FAC-008 violations since 2017 to identify three major themes associated with facility ratings problems, along with potential mitigation strategies for each issue.
Ponseti said that after the report’s publication in April, SERC offered it to NERC to serve as the basis for an ERO-wide analysis of facility ratings issues, to which the organization readily agreed. That broader report — which Ponseti said had “found a fourth theme that we missed” — is scheduled to be published next week.
The hydrogen revolution energizing green hydrogen advocates and producers in the wake of the Biden administration’s renewables push won’t happen until key players from the fossil fuel and financial sectors buy into the transition, according to a key government official charged with helping to make it happen.
Jigar Shah, a former green entrepreneur and now director of U.S. Department of Energy’s loan program office, offered the prediction Tuesday during a focused conversation at the two-day Hydrogen Americas Summit in Washington, hosted by the DOE and the Sustainable Energy Council, a global business organization. More than 600 attended.
Shah said U.S. heavy industry, including oil refineries, now uses about 10 million tons of hydrogen annually. Nearly all of it is made from methane, a process that produces carbon dioxide. Convincing the refineries to switch to buying green hydrogen would be a promising first step for the cleaner fuel, Shah said.
“The president has been very clear that we need to decarbonize the electricity sector by 2035. And the economy by 2050,” Shah said. “I don’t see a single refinery actually signing a long-term offtake agreement — not one. No one is suggesting that the refineries are going to go out of business next week. I mean, you’re talking about a hybrid system we’re going to live in for a very long time.”
Shah said he hoped the event — and others like it — will spur recognition of the need for long-term “anchor” customers for green hydrogen.
“And they’re not concerned about the volatility of the price of natural gas and hydrogen … because they’ve already picked hydrogen. Hydrogen is already being used [at the rate of] 10 million tons a year in the United States,” he said.
But he said refineries are not signing long-term offtake agreements with upstart green hydrogen producers, in part because the oil industry has been unprofitable in recent years and the long-term financial future of oil refining looks uncertain. Moreover, green hydrogen companies could look risky.
That is a real problem for green hydrogen producers that need solidly committed customers to finance expansion, he explained. They have trouble attracting both private equity investment as well as traditional formal financing because established industries are not ready to buy from them.
Shannon Angielski, a principal with Van Ness Feldman LLP, moderated the panel discussion. She suggested that the difficulty in jumpstarting U.S. green hydrogen production may also be the result of a supply chain problem.
“We’re talking about a big market here, and starting either small or going big, even with the regional hubs, there is a lot of equipment, components and other things that are really needed for that market. There are not a lot of manufacturers today, or they’re very limited and that could limit some of these supplies,” Angielski said.
“How do you look at that from a financing perspective, equity [financing] or otherwise? How do we accelerate that or send that . . . market signal?” she asked panel members.
Shah suggested that building a recognized parts supply system is not as big a problem as the green hydrogen industry itself.
He said the burgeoning industry keeps creating new business models for the use of hydrogen.
“That confuses the crap out of the finance sector because the [models] are all different. The use cases are completely different. They are not actually related to each other,” Shah said.
“Finance people think in terms of risk,” he explained. Their questions will include: “What do the standardized contracts look like? What [responsibility] does each party take on? Do I get protected if the electrolyzer manufacturer gives me a 10-year warranty? …
“Do I get protected … if the leak rates are much higher than expected, and the project is worse than what it was replacing? Is there moral harm? And if the project gets shut down and I don’t get paid back? …
“The last piece of it [investor concerns] are residual value and recovery rates,” he said. “What if the team ends up being completely incompetent, and the project itself is good, but the team can’t operate it. Is there a way to bring in a new team to actually realize that vision?”
New Finance Models Needed
The DOE’s efforts to bring more certainty to the situation include $9.5 billion in funding for governments and industries that can create the concentrated production of hydrogen and its use in a relatively small region. The agency is accepting concept proposals for these hydrogen “hubs” until Nov. 7 and is seeking full applications by April 7, 2023.
Early conversations have been disturbing, Shah revealed. “We do think that [green hydrogen producers] should strive to get offtake agreements, but I do also think that some of what we’re seeing seems slightly fanciful. There are a lot of people getting European offtake agreements with almost nothing happening in the United States,” he said.
Nicole Faucher, CEO of BEAM Group, a large private equity fund focusing on carbon-negative investments, said the problems that green hydrogen companies face “boils down” to outdated financing models.
“We can’t reinvent the future energy of how we’re going to power a better planet using yesterday’s financing models,” she said.
Faucher said current financing models will not work because the expansion of green hydrogen production requires a 20- to 40-year outlook.
“The current market is really set up in terms of venture capital hedge funds for a much shorter timeframe. We need long-term, patient, strategic capital to really move the needle on the clean hydrogen economy,” she said.
Private equity is set up to typically offer 10 years of financing, with possibly two one-year extensions on top of that. “So, you’ve got 12 years of runway there, not really enough time,” Faucher said.
Some private equity groups are now using another investment tool called “continuation funds,” an arrangement in which a second fund buys the debt from the original investor after the first 10 or 12 years.
“One of our anchors is very excited about doing a continuation fund. At that point, you’ve got 20 years. That’s what you need to move the needle on the clean hydrogen economy,” she said.
The Southeast Energy Exchange Market (SEEM) is set to begin operations on Nov. 9 despite an ongoing legal challenge from environmental groups, the market’s membership board said in a filing to FERC last week (ER21-1111, et al.).
In their filing, the members noted that their agreement required the board to establish a commencement date after FERC issued orders accepting all relevant tariff filings by participating transmission providers.
The agreement automatically took effect almost exactly a year ago under Section 205 of the Federal Power Act after FERC — then evenly split between Republicans and Democrats after the departure of Commissioner Neil Chatterjee — was “divided two against two as to the lawfulness of the change.” (See SEEM to Move Ahead, Minus FERC Approval.)
The tariff approvals followed, beginning last November when the commission accepted revisions to the tariffs of four of SEEM’s founding utilities: Duke Energy, Southern Co., Dominion Energy, and LG&E and KU Energy. (See FERC Accepts Key Tariff Revisions to SEEM.) Utilities’ most recent revision came in January when FERC accepted changes to Duke’s tariff (ER21-1115).
SEEM’s founders proposed the market last year, promising to reduce trading friction while promoting the integration of renewable resources through the use of automated trading, elimination of transmission rate pancaking and allowing 15-minute energy transactions. The project has been controversial from the start; many opponents have questioned whether the proposed measures would outperform alternative structures like an RTO, while others warned that the market would allow transmission-owning utilities to exclude competitors from the market and favor their own electricity.
Although SEEM’s members are moving ahead with their operational schedule, the market is still the subject of a challenge in the D.C. Circuit Court of Appeals. A collection of environmental, clean energy and community groups including the Southern Environmental Law Center, the Sierra Club, the Southern Alliance for Clean Energy and the North Carolina Sustainable Energy Association filed an appeal in February of the commission’s decision to allow the market to move forward. (See Environmental Groups Appeal SEEM in DC Circuit.)
The opponents are asking for the court to overturn both the original effective date and FERC’s subsequent tariff approvals, as well as the commission’s rejection of the rehearing requests that the opponents have previously filed for these orders.
SEEM’s members promised in their filing to update FERC “should the commencement date occur after Nov. 9, 2022, for any reason.”
WASHINGTON — The Supreme Court’s ruling barring use of “generation shifting” to reduce greenhouse gas emissions will discourage executive agencies from ambitious rulemakings but is not yet a “nuclear bomb” that will cripple regulation, attorneys told the Energy Bar Association’s Mid-Year Energy Forum Wednesday.
The court ruled June 30 that the EPA failed to provide “clear congressional authorization” for the Clean Power Plan, which would have compelled generation shifting to reduce carbon emissions from coal-fired power plants (West Va. v. EPA). The court cited the “major questions doctrine,” which it said was necessary to address “a particular and recurring problem: agencies asserting highly consequential power beyond what Congress could reasonably be understood to have granted.” (See Supreme Court Rejects EPA Generation Shifting.)
Proposed by the EPA under the Obama administration, the CPP was withdrawn by the Trump administration — replaced by the Affordable Clean Energy (ACE) rule, which was in turn withdrawn by the Biden administration.
Crippling?
Stinson partner Harvey Reiter, who moderated EBA’s morning general session Wednesday, has written that the ruling is “a potential nuclear bomb that can be aimed not merely at a particular rule, but at crippling an agency’s ability to regulate at all.”
Reiter’s fellow panelists had a less apocalyptic view.
Elizabeth “Ellie” Boucher Dawson, counsel with Crowell & Moring, said she didn’t agree with Reiter’s dire prediction.
“Not yet, anyway,” said Boucher Dawson, who wrote an amicus brief on the case for the Edison Electric Institute. “For me, it’s very significant that Justice [Neil] Gorsuch only wrote a concurrence and not the majority opinion.”
Gorsuch pushed for a more extreme interpretation of the major questions doctrine as a limit on congressional delegations of policymaking to agencies. But only Justice Samuel Alito joined his argument.
Aram Gavoor, a lecturer at George Washington University Law School, said the court’s decision “did not substantially change administrative law.
“I think it could, like Ellie described, eventually be something that’s quite serious. But the court will have to press the button again — a few more times — to really reinforce it.”
Matthew Leopold, a partner in Hunton Andrews Kurth, said the ruling set “a speed limit on the regulatory highway that agencies should not exceed without the risk of their rules getting struck down.
“I think it will hold the agencies back, but the regulatory administrative process is alive and well,” he said.
No Limits on ‘Major Questions’?
Although the court’s ruling said the major questions doctrine would only apply in “extraordinary circumstances,” Reiter noted that the court cited it in three rulings in its last term, involving the Food and Drug Administration, the Centers for Disease Control and Prevention and the Occupational Safety and Health Administration. He said the issue also was raised in more than 100 circuit court and district court challenges since 2020.
Aram said the West Virginiaruling resulted in a “mushy” standard that will encourage many litigants to raise it. “Part of this might also be [that] for the court to have gotten the majority for West Virginia v. EPA, maybe it needed to be a little bit broad,” he said, adding that future rulings could result in “the metes and boundaries of what major questions really means.’”
“The nature of lawyers is to raise any argument that might get traction, so I think people will overuse it,” Leopold added. “… But I think that the extent to which it’s raised — and then more importantly, the extent to which courts really lean into it and start utilizing it — has a direct relationship to how much federal agencies … are overreaching their long-held authority or positions.”
Samuel Backfield, legal counsel to FERC Commissioner Mark Christie, said the agency expects to see the argument raised in the future.
“I think that what’s going to happen next is that there’s going to be a process of refinement of the doctrine. … Right now, what we have essentially are indicia; we don’t have a firm test,” he said. “It’s not meaningless that we have this indicia condition instead of a firm test. I mean, I’m sort of reminded of Edmund Burke’s comment that no man can draw a stroke between night and day, and yet darkness and light are reasonably distinguishable.”
Reiter suggested the ruling could prompt “forum shopping” because appeals of most agency decisions go first to one of the 94 district courts rather than a circuit court of appeals, as with FERC challenges.
“I think there’s gonna be a substantial amount of it,” agreed Aram. “… It’s also going to cause a lot of struggling with the circuit courts as to what does this mean for Chevron deference” — which requires courts to defer to a federal agency’s interpretation of an ambiguous law that Congress assigned to the agency to administer.
Boucher Dawson said she was relieved that the court did not “reach back in time” to undo its previous rulings, such as Massachusetts v. EPA, in which it ruled greenhouse gases were air pollutants and could be regulated by EPA under the Clean Air Act.
Reiter questioned whether FERC’s prior rulemakings could be in jeopardy as a result of the narrowing of the Chevron doctrine. He noted the commission cited the Federal Power Act as its authority for regulating demand response, “which wasn’t even a thing in 1935,” when the FPA was enacted. Some commenters raised the major questions doctrine in FERC’s current transmission planning Notice of Proposed Rulemaking (RM21-17), he added.
FERC’s Backfield said the challenges could result in unpredictable outcomes. “There are courts of appeals and panels that would rule differently, I think, on certain of the cases,” he said.
Backfield declined to opine on whether any of the commission’s major rulemakings would survive scrutiny under major questions. “But … other than demand response, they’ve mostly been around for quite a while. And there is at least a rationale that these do go to the fundamental central regulatory duty of the FERC, which is to ensure just and reasonable rates.”
“I don’t think that the Supreme Court — at least the majority of the justices — would coalesce around an opinion that picks on old scabs,” said Gavoor. “I think if we anachronistically applied West Virginia v. EPA to some of these older actions by the agency they’d be at risk. But I don’t think they’re at risk right now. I think recent actions and ones that are in the future are likely to be at risk.”
Impact on Future Regulations
Leopold noted that the Securities and Exchange Commission recently reopened comment on a portion of its proposed greenhouse gas rulemaking, a suggestion that it sees vulnerability to a major questions challenge.
“The SEC has been around since the Depression, and they’ve never really gotten in the environmental game. But they’re all of a sudden saying you have to disclose your climate risks. You have to disclose your greenhouse gas emissions — not just your direct emissions, but your scope one, two, and three [emissions] — including three, and no one even knows how to calculate that,” he said.
Leopold said the ruling has resulted in a “burden shift.”
“If it’s a major question, the burden is now on the agency to say that they have the authority, rather on the petitioner who was challenging the agency rule to say … that that application of their authority was not a reasonable interpretation. So that’s a major change.”
He said the ruling also shifts the burden to Congress, which will be required to demonstrate “political will” to pass new legislation.
Aram said he expects “more incrementalist regulation so as not to cross this tripwire of major questions.
“So, I think it is going to require a change in tactics and strategy. I think it will result in some tension with the White House, because the White House absolutely loves to politicize any sort of policy. … It’s going to have to be much more strategic and cautious. And the [legislation] shops are going to have to be far more engaged.”
Leopold, a former Justice Department attorney, said if he were still advising federal agencies, “I would be telling them very specifically, do not characterize this in the press as ‘major, transformative, earth shattering, we’re going to save the planet’ unless you really do have clear authority to do so.
“Those types of grandiose statements [are] going to raise the hairs on the back of the neck of judges who care about [the] major questions [doctrine].”
What’s Possible in GHG Rules?
With new Clean Air Act amendments unlikely, it’s unclear what GHG regulations EPA could approve that would pass muster. The administration told the court in oral arguments in February that it planned to issue a replacement for the CPP by the end of this year.
Would carbon capture pass the court’s scrutiny, as Justice Kagan suggested in her dissent?
“I think that’s possible because that that would be a technology applied at the source, conceivably, if you had a way to sequester the carbon there or nearby,” said Leopold. “If you’re having to pipe it miles way to another reservoir, that could raise questions.”
Leopold said Kagan, however, ignored the Clean Air Act’s requirement that the “best system of emission reduction” also be “adequately demonstrated.”
“We know from attempts at the Kemper plant in Mississippi that carbon capture and sequestration for coal fired plants still has a lot of hurdles — financial hurdles, in particular.”
ATLANTA — With NERC’s newest cold weather standards having passed their final ballot and ready for submission to the organization’s Board of Trustees, a member of the team that drafted the standards on Wednesday reminded stakeholders that the work of protecting North America’s grid from winter weather has only begun.
The new reliability standards EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations) were submitted to industry stakeholders for their final ballot Sept. 23 and passed Sept. 30, along with their implementation plan. Trustees are expected to approve them at the board’s upcoming meeting in New Orleans, after which they will await acceptance from FERC.
Speaking at the North American Generator Forum’s annual Compliance Conference at NERC’s headquarters, David Lemmons, co-founder of consulting firm Greybeard Compliance Services and head of NAGF’s Cold Weather Working Group, jokingly observed that “it’s going to take a few days” for the standards to take effect. He was referring to the fact that EOP-011-3 will not be enforceable until 18 months after the commission grants its approval, while EOP-012-1 will not fully take effect for more than six years from that point.
Joining Lemmons was Occidental Power Services’ Venona Greaff, who outlined some of the changes that utilities can expect in EOP-012-1 and EOP-011-3. Greaff served on the standard drafting teams for both Project 2021-07, which drafted the new standards, and its predecessor Project 2019-06, which created three cold weather standards approved by FERC last year. (See FERC Approves Cold Weather Standards.)
The latest project was initiated in response to NERC and FERC’s joint inquiry into the winter storms of February 2021 that knocked thousands of megawatts of capacity offline in Texas and left households across the state without power for days. (See FERC, NERC Release Final Texas Storm Report.) Recommendations from the report include requiring generator owners (GOs) and operators (GOPs) to build or retrofit generating units to operate to specific ambient temperatures and weather, and to perform annual training on winterization plans.
The two standards passed last month comprise Phase 1 of the overall cold weather strategy and were developed under an accelerated schedule in hopes of getting them before FERC sooner. (See NERC Standards Committee Fast Tracks Cold Weather Project.) Now that their development is finished, the organization plans to move to Phase 2, which will address more recommendations from the report such as specifying the role of GOs and GOPs, as well as balancing authorities, in determining generator capacity, along with requirements protecting natural gas infrastructure from load shedding. NERC currently hopes to finish this stage by next year.
Although the SDT did not add these elements to its remit in order to avoid delaying completion, the members did take “some steps in Phase 1 to address some of the things that we’re going to have to address in Phase 2,” Greaff said. In particular, she noted the FERC-NERC report’s recommendation that GOs “identify cold-weather critical components and systems for each generating unit.” Greaff said the team decided to go ahead and create specific definitions of relevant terms so that “when we get to Phase 2, we [will] already have a foundation layer” to build on.
