One of the largest power plants in Illinois has been running without proper permits since it went into service, the Sierra Club contends in a lawsuit filed Thursday.
As a major source of emissions, the Prairie State Energy Campus needs a Title V permit under the federal Clean Air Act, the environmental advocacy organization said, but has held only a Prevention of Significant Deterioration (PSD) permit since it went online in 2012.
The operator, Prairie State Generating Company, countered that the 1,600-MW plant is operating legally with the PSD issued by state regulators and called the Sierra Club’s lawsuit a politically motivated attempt to sidestep state regulations.
Under Illinois’ landmark 2021 Climate and Equitable Jobs Act, privately owned coal-fired power plants must shut down by 2030 but publicly owned plants such as Prairie State can run until 2045.
Megan Wachspress, the Sierra Club staff attorney who filed the lawsuit, said the action seeks a declaration that the plant cannot operate without a Title V permit.
Permit History
The Prairie State Energy Campus in Marissa, in southern Illinois, is owned by nine public power utilities and rural electric cooperatives. Coal mined on site is pulverized to powder and burned to run two 800-MW units that send electricity to customers in eight states.
It boasts of setting a new standard for clean coal production and of investing $1 billion in emissions controls.
The U.S. EPA’s ECHO database lists 2021 emissions of 8.2 million pounds of nitrogen oxides and 21.1 million pounds of sulfur dioxide. Both substances are potentially damaging to human health and the environment.
By state and federal statute, Wachspress said, these numbers make the facility a major source of pollutants and require it to hold a Title V Permit.
The Sierra Club’s lawsuit indicates Prairie State applied for such a permit — which is called a Clean Air Act Permit Program (CAAPP) in Illinois — in January 2010, updated the application in May 2011, and applied again in July 2020.
Neither of those applications was approved, Sierra Club writes.
Illinois regulators did issue a Construction Permit/PSD approval to Prairie State on March 30, 2012, Sierra Club said, but that’s not enough because the plant is a major emitter, and under state law Illinois’ failure to act on the CAAPP application constitutes a constructive denial.
Asked by NetZero Insider about the legality of Prairie State operating for a decade with a PSD, the EPA’s district office deferred to the Illinois Environmental Protection Agency, which declined comment.
Enforcement Sought
Wachspress could only speculate on how this went on for so long.
“This is such a fundamental requirement you just assume it’s being done,” she told NetZero Insider Thursday. “It’s disappointing that the Illinois EPA didn’t act on it.”
She said Prairie State has been on the Sierra Club’s radar for a while because of its huge output of harmful substances. The U.S. EPA’s Greenhouse Gas Reporting Program shows it to be by far the largest single source of CO2 emissions in Illinois in 2021, at 12.5 MMT.
There have also been a series of violations cited by the state and federal EPAs, Wachspress said.
After Prairie State was cited for exceeding federal limits on mercury emissions in 2021, Sierra Club began digging and discovered the lack of a CAAPP permit.
Sierra Club announced the lawsuit Wednesday. It was filed Thursday in U.S. District Court, southern Illinois.
Prairie State declined comment on the legal action itself but commented at length on the allegations at its root.
Vice President Alyssa Harre said via email that Prairie State “is operating legally under a Prevention of Significant Deterioration permit from the Illinois Environmental Protection Agency. To comply with this permit, Prairie State installed and has maintained more than $1 billion in state-of-the-art emissions control technology and continuous emissions monitoring system.
“This action by the Sierra Club’s California-based Environmental Law Program is a politically motivated attempt to circumvent the Illinois regulatory process, the consequences of which will bring instability to our electric grid to the detriment of the consumers we serve.
“Prairie State remains committed to working with the IEPA to maintain compliance with environmental regulations and will not let this lawsuit distract from our mission of providing value to the communities served through the continued production of reliable and affordable power, all while providing jobs and maintaining economic prosperity for hardworking men and women across downstate Illinois.”
The lawsuit is a citizen enforcement action, an attempt to force compliance with regulations that can be filed 60 days after the complainant gives notice of alleged violations to the parties involved.
Sierra Club said it gave such notice more than two months ago to EPA, IEPA and Prairie State.
Only Prairie State is named as a defendant in the lawsuit, which asks the court to:
declare that Prairie State is violating the Clean Air Act and Illinois air regulations;
enjoin Prairie State from operating the power plant until it obtains a CAAPP permit and is in compliance with the Clean Air Act;
impose of civil penalties, and designate $100,000 for mitigating public health and environmental projects;
CLEARWATER BEACH, Fla. — As this week’s meeting of NERC’s Reliability and Security Technical Committee (RSTC) wrapped up in Florida, Vice Chair Rich Hydzik invoked the movie “Moneyball”to explain his committee’s place in the “data-driven world” of electric reliability.
“There’s a scene in that movie where [baseball manager] Billy Beane wants to draft somebody the scouts have never heard of, and they … have another pick they want. He says the numbers don’t back that up, and their answer is that he has the intangibles; you can’t measure the intangibles,” Hydzik said. “I think this meeting kind of highlights the intangibles that complement that data-driven approach to things we do.”
This week’s two-day meeting is the only fully in-person gathering planned for the committee this year. (See “Future Meetings,” NERC RSTC Briefs: Dec. 6-7, 2022.) For the June meeting at the MRO offices and the September meeting at WECC’s office, leadership intends for only members to attend in person while observers participate online. The final meeting of the year in December will be entirely virtual.
Standards Projects Move Forward Despite Data Concerns
NERC’s System Planning Impacts from Distributed Energy Resources Working Group (SPIDERWG) brought two Standard Authorization Requests (SARs) to the committee for endorsement, one of two standards actions the committee took this week.
The SARs are intended to modify existing reliability standards FAC-001-4 (Facility interconnection requirements) and FAC-002-4 (Facility interconnection studies) to require more consideration of potential reliability impacts from distributed energy resources (DER) before they are integrated to the electric grid. (See p. 129+ of agenda for SARs.)
This was the SARs’ second time before the RSTC; SPIDERWG Chair Shayan Rizvi brought them to the committee in December as well, though at that point the group was only seeking comment from committee members.
At Wednesday’s session, Nate Schweighart of the Tennessee Valley Authority expressed concern that the SAR was “getting a little bit ahead of the data,” citing the lack of centralized information sources on DERs, and of agreed-upon channels for accessing the information.
“You guys are putting requirements on the DPs [distribution providers] to provide the data, but there’s a large number of DPs; how we coordinate the information between the DPs to aggregate the DER information in order to properly study it, I think that all has to be figured out,” Schweighart said. “And then to require those things to happen before we have the data, I think, will cause some chaos amongst the transmission planners to figure out how to do it.”
John Moura, NERC’s director of reliability assessment and performance analysis, pointed out that “there’s a lot of things we have to study that we don’t have the data for.” He suggested that the presence of a mandatory standard could provide an impetus for DPs and other stakeholders to build the communication infrastructure needed to share the information efficiently.
David Grubbs from the municipal electric utility in Garland, Texas — who described himself as representing “both the DPs and the TPs [transmission planners] in our organization” — supported the SARs, saying the measures are “probably several years overdue.”
However, he also warned that he didn’t “think the data exists right now.” He suggested that the standard drafting team (SDT) to which the SARs are eventually assigned be encouraged to give utilities “a year or two” to collect the data.
“It’s going to take a while for the DPs to get data that is meaningful, and even after you get the data to put it in the model, and [make] sure the model solves and … do some testing to make sure that represents the real world,” Grubbs said. “So, I agree it needs to be done, I just think that … in our implementation plan, [we need to] make sure that we give adequate time to get verifiable data out of the distribution providers.”
Calling for a vote on the SARs, Chair Greg Ford said the issue came down to “timing of data versus studies,” and said he was confident the committee could work with the SDT and others involved in the process “to make sure that timing is there.” Members voted unanimously to endorse the SARs; they will now move to the Standards Committee, which will decide whether to approve them and assign a SAR drafting team.
Also before the committee this week was a SAR to modify MOD-031-3 (Demand and energy data). The measure, which was also brought by the SPIDERWG, would allow planning coordinators (PC) to “obtain existing and forecasted DER information from DPs or TPs” to ensure that the data “is available to the parties that perform reliability studies and assessments.”
Unlike the earlier SARs, SPIDERWG was only seeking reviewers from the RSTC, so no vote was needed. Secretary Stephen Crutchfield promised to email the draft SAR to the committee so that any interested members could volunteer.
Guidelines Approved
The RSTC also approved several reliability guidelines at this week’s meeting. Although these are not binding, their adoption is “highly encouraged” by NERC.
The first guideline, “Electromagnetic Transient [EMT] Modeling for BPS-Connected Inverter-Based Resources,” was submitted by the Inverter-based Resources Performance Subcommittee (IRPS). Designed as a reference for TPs and PCs that are performing EMT studies during the interconnection study process, the guideline is intended to “serve as a foundation for future EMT modeling related activities of IRPS.”
Next was a guideline intended to inform utilities on the Institute of Electrical and Electronics Engineers’ (IEEE) Standard 1547-2018, which relates to the interconnection and operation of DER. Although the IEEE standard only involves resources that are connected to the distribution system — and therefore not subject to NERC jurisdiction — SPIDERWG felt a guideline was needed because the installation and use of DERs “require coordination between distribution and transmission entities.”
WASHINGTON — Panelists at the Electric Power Supply Association’s (EPSA) Competitive Power Summit on Tuesday warned that the clean energy transition could be slowed or side-tracked by consumers if their monthly energy bills continue to rise.
“We’re at a crossroads where costs are going nowhere but up,” said Christine Tezak, managing director at industry analysts ClearView Energy Partners. “And the question is, are we going to be able to make a value proposition so that the consumer feels they’re getting value for the increased cost?
“It’s going to be necessary to convince consumers that not only are they getting a lower-carbon alternative, but they’re getting increased reliability and better deliverability in that product,” Tezak said. “Because it’s not just about keeping … the body warm, but it’s not having my electricity bill be something that speaks to me every month in a negative way.”
From McKinsey to PJM to the International Energy Agency, estimates of the cost of the global energy transition, and the investments needed in the coming years, generally fall within a range of $1 trillion to $4 trillion annually through 2050. But the EPSA panelists had different view on how those figures might play out and what potential pathways to a reliable transition might look like.
Stacey Doré, chief strategy and sustainability officer for Vistra (NYSE:VST), sees maintaining and expanding competitive power markets as an effective way to keep costs down for consumers, arguing that utility bills in competitive markets are lower than in regulated markets. (See After a Quarter Century Industry Experts Still Split on Restructuring.)
“As a competitive retailer, a power generator, our shareholders are taking on a lot of risk [for] these higher costs as opposed to just passing them through to the ratepayer,” Doré said.
At the same time, Vistra’s investment strategy is centered on shareholder returns, she said. For example, with the acquisition of Energy Harbor, owner of four nuclear reactors in Ohio, Pennsylvania and West Virginia, Vistra now has the second largest portfolio of carbon-free dispatchable power in the country, according to a company press release. (See Vistra Pays more than $3 Billion for Energy Harbor.)
The company has committed to reducing its greenhouse gas emissions 60% below 2010 levels by 2030.
Representing Wall Street’s perspective, Anthony Crowdell, managing director at Mizuho Americas, an investment banking firm, said investors have gotten “very used to very attractive earnings growth rates” from regulated electric utilities, which receive guaranteed rates of return on their capital spending. Investors’ concerns now turn on the likelihood that inflation and higher electricity bills will trigger regulatory pushback ― limiting rates of return ― and whether “what utilities have promised in the past, they may not be able to deliver,” Crowdell said.
But most consumers don’t understand or care about competitive versus regulated markets or the skittishness of equity investors, said David Springe, executive director of the National Association of State Utility Consumer Advocates (NASUCA).
“They just know at the end of the day, the bills are going up,” Springe said. “It’s the same kilowatt-hours that were turning the lights on 20 years ago and turning the lights on 10 years ago and turning the lights on last week. It’s the same kilowatt-hour; it just costs 100% or 200% more than it used to. You’re not going to explain that to customers, and you will see political pushback. …
“The same people that just arbitrarily say we’re going to have 100% [electric vehicles] by 2035 are the same people that will arbitrarily tell utilities to stop raising rates,” he said.
Defining ‘Affordability’
Exactly how to balance the conflicting priorities of the transition has become an ongoing conversation within the energy industry and at conferences like the Competitive Power Summit. EPSA’s membership is predominately independent power producers who advocate for competitive wholesale power markets.
Climate advocates point to the mounting physical and financial impacts of extreme weather events, as well as the new federal subsidies for clean power in the Inflation Reduction Act as clear signs for acceleration. Releasing the U.N.’s 6th Assessment Report Synthesis on climate change on Monday, Secretary General António Guterres called for the largest industrialized nations of the world to phase out all coal-fired generation by 2030. (See Guterres: G20 Nations Should Commit to Net Zero by 2040.)
But industry insiders like Doré argue that reliability and cost should determine the pace of the transition. Wholesale power markets have a vital role to play, sending appropriate price signals to advance policy objectives while minimizing price increases for consumers, she said.
Pace is “the key to the transition,” Doré said. “Our markets need to send the right price signals to build the kind of generation that we need.”
The war in Ukraine, for example, has opened questions about the need for new gas-fired generation, Doré said. “We look all the time at whether it’s economic to build new gas plants. In most markets today, it’s not because the investment signals are not there.”
She called for “an honest conversation about what is the right pace. What is the all-of-the-above strategy [for] getting eventually to deep decarbonization? I think we have to talk about investment signals. We have to talk about demand response. We have to talk about all the different methods of getting there. But we also have to be realistic about what the goals are,” Doré said.
Springe countered that the focus on building big projects to push the transition forward could be counterproductive, given the long lead times and resulting high costs needed to permit and construct such installations.
“I worry that there’s sort of a focus on big and fancy, and where the money and incentives should be is local, close: demand response, energy efficiency, solar, batteries; things that are near, because we can build those. So, I worry that we’re going to lose speed, in a sense, chasing the big and really miss out on an opportunity to accomplish the small,” he said.
Another part of the problem is that few states or regulatory commissions have a legal or structural definition of “affordability,” Springe said. While not offering a definition of his own, he called for “a very specific process to define what [affordability] is, whether you have it in your statutes or you don’t,” he said. The process also needs to be part of project planning, Springe said, “not after they’ve built an asset and have come to bring it and integrate it” into a rate base.
“You’ve got to define a metric, and you’ve got to do it up front,” he said. “What is it? How do you enforce it? … And how many things can we actually build in the state in that affordability metric?”
How We Buy Electricity
Tezak took a more market-based approach to the issue of ordering priorities, noting first that the emerging technologies that will be needed for long-term decarbonization “require time to be demonstrated, for you have to have a couple of [projects] get online before anybody makes money.” A “real portfolio concept” for procuring capacity could incorporate “a lot of character attributes,” she said.
One way forward could be “rebundling some of the capacity for long-term procurement with [clean energy] development … and coming to grips with what that capacity is,” she said. “The capacity market doesn’t have to be limited to the auction. I think to build faith back into markets, we may have to step away from defining them solely as a terrifically functioning auction because it isn’t how you buy anything else, and it’s not how we’re buying energy for this transition,” Tezak said.
“We’re talking about [power purchase agreements]; … we’re talking about interconnection; we’re talking about all that stuff, and the perfect, well functioning auction that we had for a couple of years seems to exist in a parallel universe,” she said. “Is it time to take the plunge of talking about not doing tweaks but doing major changes and what that means? And that’s hard because investors don’t like uncertainty and many of them … really dislike change.”
But Doré doesn’t think the markets need fixing per se. “The problem is we’re not allowing the markets to function the way that they were designed to function,” she said. “Things like market caps or trying to adjust capacity accreditation in a way that disadvantages dispatchable generation are interferences in the market that are going to scare away investors. …
“The problem is we have so many changes in our markets every time the legislature meets or every time the commission meets or every time FERC or one of the ISOs meet. … That just injects a lot of uncertainty for investors,” she said. “So, the ground is always shaking beneath you a bit.”
Mizuho’s Crowdell agreed that investors are looking for stability in markets across a range of variables, such as cost recovery after extreme weather events. Should shareholders or consumers pay, and who decides? Securitizing costs after an extreme weather event could reduce impact on customers’ bills, but in the long term, the customers who end up paying 10 or 20 years down the road weren’t even around when the costs were incurred, he said.
“When you think about the regional market, their concerns are different that the actual individual state,” which could also be different from those of individual legislators or regulators, he said. And legislative turnover in states continues to accelerate.
“We’ve seen much quicker changes in the state house,” he said, with the projects and policies of one administration being rolled back by a new set of players. “The equity holders are trying to balance [to] see where it’s going.”
But the panel circled back to the core issue of whether consumers might reject any further rate increases for clean energy. While consumer advocates are often uncomfortable with such questions, Springe said, “we really need to have a much broader discussion around what the price is going to be and figuring out how to match that up with when assets or resources appear.”
The special rates some utilities have introduced that encourage charging EVs at specific times of the day are one example of the kinds of rate design that will be needed going forward, Springe said. Doré agreed, pointing to Vistra’s Free Nights and Solar Days pricing plan in Texas that “encourages customers to use energy at the time of day when there’s less burden on the system.”
“Those kinds of plans are not possible unless you have a robust, competitive retail market,” she said. “If you want customer innovation, you’ve got to have competition.”
Virginia Gov. Glenn Youngkin (R) signed a half dozen bills on Thursday that he said will deliver on his “All-American, All-of-the-Above Energy Plan.”
“Today is a great day for Virginia energy and American energy,” Youngkin said. “With the bills I’m signing, we’re moving closer to delivering on the All-American, All-of-the-Above Energy Plan I put forward last year. We can, in fact, make Virginia energy more reliable, affordable and clean while creating jobs and spurring innovation, and today is a testament to that.”
Youngkin said the legislation will help make Southwest Virginia the energy capital of the commonwealth while unleashing potential for the entire state.
The bills include HB 2386, introduced by Del. Israel O’Quinn (R), that creates the Virginia Power Innovation Fund, intended to jumpstart the creation of energy technologies and start to set up a nuclear innovation hub in the state. Other technologies that it will fund include carbon capture and storage, hydrogen, and energy storage.
The governor also signed Quinn’s HB 1779, creating the Nuclear Energy Grant Fund that will award grants to the commonwealth’s colleges and schools for the creation of employment and training pathways in the nuclear power industry, including nuclear engineering and nuclear welding.
A third bill from Quinn also got signed by the governor: HB 1781, which empowers the Southwest Virginia Energy Research and Development Authority to promote projects on brownfield coal sites, develop the energy workforce in the region and advance southwest Virginia’s energy industry. The research and development authority is a panel that seeks to promote energy development in the region, consistent with Virginia’s Energy Plan.
Youngkin signed HB 1643, which was introduced by House Majority Leader Terry Kilgore (R), which holds that it is the policy of Virginia to use coal mine methane gas produced from an underground area associated with mined-out coal seams. It requires the Department of Energy to evaluate the resource’s potential and to come back with a report to Youngkin and legislators on its findings by Nov. 15.
“Having lived my whole life in Southwest Virginia, I know the promise that exists in our mountains and valleys,” Kilgore said. “Energy innovation brought good paying jobs, and my bill to support the capture and use of coal mine methane from former coal sites is another example of Southwest Virginia leading the way in energy innovation.”
Sen. Travis Hackworth’s (R) SB 1468 provides that funds in localities’ Coal and Gas Road Improvement Funds may go toward flood mitigation infrastructure in the southwest of the state. Current law allows localities to tax up to 1% of the revenue from coal and gas production for building out roads and new water and sewer infrastructure.
The final bill Youngkin signed came from Del. Will Moorefield (R). HB 2178 is meant to add more coal mine methane extraction to the jobs eligible to receive green and alternative energy job creation credits.
FERC should get authority over the cybersecurity of natural gas pipelines, lawmakers said at a hearing of the Senate’s Energy and Natural Resources Committee on Thursday.
“I want to work with the committee and the chairman and ranking member to introduce legislation that will give FERC this very clear role,” said Sen. Maria Cantwell (D-Wash.).
“I think that’s what needs to be done” to protect pipelines from cybersecurity attacks, she added.
Cantwell has not officially introduced the legislation, according to Congress’ legislation tracker.
Sen. Angus King (I-Maine) noted that even if the New England grid had perfect cybersecurity, power could still be knocked out by a cyberattack focused on the pipelines that flow into the region. The Transportation Security Administration currently oversees cybersecurity for pipelines.
“So, it bothers me that we’ve got TSA over here and FERC over here, and I’m not sure there’s a consistent regulatory… structure,” King said.
Sen. Joe Manchin presiding over Thursday’s hearing | Senate ENR
“Trying to fix that, sir,” Committee Chairman Joe Manchin (D-W. Va.) chimed in before King could finish his sentence.
King said he’s worried that with authority split over two highly connected energy systems’ security, something could fall through the cracks.
FERC has been regulating cybersecurity on the electric side for a decade and the gas network needs to be just as reliable as the grid, said Stephen Swick, chief security officer at American Electric Power (NASDAQ: AEP).
“Now we’ve got regulations and a lot of pressure on the gas pipelines, but it should be standardized,” Swick said. “And if FERC can lead that, then I think they’ll line up well and we can have the same progress for both industries.”
Dragos CEO Robert Lee said his firm has worked with the power sector on cybersecurity as a vendor and that both industries should ideally have the same regulator.
“I would say that FERC is a very logical choice,” Lee said. “I don’t really particularly care which one takes it so long as it’s one.”
TSA’s first attempt at regulating pipelines was rushed, but the agency has since worked hard and improved its rules, Lee said, adding the issue would benefit from increased standardization under one agency.
Bills Would Change DOE’s Cybersecurity Functions
Other legislation discussed at the hearing would impact the Department of Energy, with Manchin and Sen. Jim Risch (R-Idaho) introducing the “Energy Threat Analysis Center Act of 2023,” which seeks to improve information sharing between the government and private industry.
“This legislation will empower the DOE to coordinate with the private sector on critical information sharing and risk assessments to help protect our great nation against cyber threats,” Manchin said.
Ranking Member John Barrasso (R-Wyo.) introduced S 2302 to elevate the head of DOE’s Office of Cybersecurity, Energy Security, and Emergency Response (CESER) back to the assistant secretary level.
“China and Russia threaten our nation’s cybersecurity. Our energy grid and pipeline network are too important to be left vulnerable to attacks by such hostile nations or rogue actors,” Barrasso said. “The Department of Energy plays a critical role. The department needs a Senate-confirmed head of its cyber office to help counter these threats.”
CESER Director Puesh Kumar thanked Barrasso for his continued support for the office at the hearing yesterday.
“This is the mission that brought me back from the private sector to come down and lead this,” Kumar said. “It was too important to not do it. I will defer to the president and Congress on the title of that position. But I can confidently tell you that I have access to the department’s resources and leaders to accomplish this mission.”
Lee praised Kumar and said the position should have stayed at the assistant secretary level.
“It’s caused him to be sidelined at some meetings, and titles matter in government, whether we like it or not,” Lee added.
Senators Seek Answers on Chinese Components
The supply chain and its impact on cybersecurity was an issue for Sen. Josh Hawley (R-Mo.), who asked Kumar how many components manufactured by China were in the transmission grid.
Kumar did not provide any firm numbers, saying the department is working to understand just how much equipment made in China is on the grid.
“The hard part about some of these questions is, you know, at the top level, it could be [that] it looks like an American manufacturer or friendly country,” Kumar said. “That’s why when you go down to the sub-component level is where it gets a lot harder. So, our focus is really looking at all of that equipment, and we’re now doing that analysis.”
Hawley complained about the lack of specifics in Kumar’s answer and said he wanted some actual numbers to be supplied by DOE in response to a written question he plans to submit. King said he also wants to see more firm data on Chinese components.
“This rarely happens with me, but I want to associate myself with the questions of Senator Hawley,” King said. “I think determining the Chinese-origin content of crucial parts of the electric system, whether it’s SCADA systems, transformers, wherever, is a ‘hair on fire’ urgent matter. Next time you’re here, we need a much sharper answer to that because that’s an enormous opportunity for malicious activity.”
LANSING, Mich. — Michigan Public Service Commission Chair Dan Scripps told members of the state Senate Tuesday that the state’s electric grid is “nowhere it needs to be,” as evidenced by the large number and long duration of utility outages that 1 million residents suffered through in February and early March.
Speaking at budget hearing for the PSC before a Senate Appropriations subcommittee, Scripps said the commission will approve regulatory changes to improve utilities’ performance this week. (See Consumers, DTE Energy on the Hot Seat over Michigan Outages.)
On March 24, the commission will take final action to change how utilities pay credits to customers who lose power for extended periods of time. The proposed rules have gotten the go ahead from the bipartisan Joint Committee on Administrative Rules, Scripps told the subcommittee.
Scripps spoke to the subcommittee after the PSC held public hearings about the outages in Jackson, home of CMS Energy (NYSE:CMS) and Dearborn, a suburb of Detroit, home of DTE Energy (NYSE:DTE).
Commissioners heard a wide variety of complaints from customers about the outages. Scripps told the subcommittee the PSC has had a major focus on outages for the last several years. The state suffers from too many outages and outages that last for too long, he said.
“We have a significant amount of work to do,” Scripps said.
An audit to investigate the state of Michigan’s utilities and how to reduce the number and duration of outages should improve the situation, he said. The PSC issued the bid request last week and hoped to have a decision on a company to conduct the audit by the end of April.
The PSC ordered the audit in October, prompting one senator to ask why it took so long to issue the bid request. Scripps said it was the first time the PSC had sought an audit, and the commission needed time to develop the questions and areas it wanted to focus on. Even so, Scripps said, he was surprised at how long it took. It was “eye opening,” he said.
Sen. Sylvia Santana (D), who represents Dearborn, said she hoped the PSC would act on the audit’s recommendations — which are not expected before April 2024 — before considering any rate hike requests by the utilities.
The subcommittee chair, Sen. Mary Cavanagh (D), asked if the PSC would consider requiring more lines to be put underground to help reduce outages. Utility executives have also said they will look at moving some lines underground.
Scripps said there was no single fix for reducing outages, but that moving lines underground — especially in some areas where it may be cheaper than trying to keep vegetative growth controlled — could be an option.
[EDITOR’S NOTE: This story has been updated with comments from MISO.]
NEW ORLEANS — FERC Commissioner James Danly paid a surprise visit to MISO’s Board of Directors meeting Thursday following a snag in the RTO’s new capacity accreditation process that will delay the planned April capacity auction.
Danly urged MISO’s leadership to “recommit” to market fundamentals. He said the grid operator must ensure that its prices incent resource adequacy and that it follows “steady, deliberate” changes to its tariff.
MISO will experience high capacity prices when scarcity conditions are present, Danly said.
“As the old saying goes, the solution to high prices is high prices,” he said.
FERC issued a show-cause order to the RTO on March 17, directing it to recalculate a systemwide capacity ratio used to validate accreditation values for planning resources or explain why it shouldn’t have to (EL23-46).
MISO said it will recalculate seasonal accredited capacity ratios but doing so will likely delay its first four-season auction. Its original unforced capacity to seasonal accredited capacity ratio erroneously counted some previously excused planned outages against some generators’ availability. (See FERC Order May Delay MISO’s 1st Seasonal Capacity Auction.)
Danly discouraged MISO from “chopping and changing” its market design, saying reactionary alterations make it “rationally impossible” for market participants to respond to and prepare for structural changes. He said his advice extended to other grid operators.
MISO told RTO Insider after the meeting that Danly’s appearance was coordinated weeks prior between it and FERC, though it did not tell stakeholders he was coming. The RTO said that as a rule, it does not place addresses from FERC commissioners on its meeting agendas. It also said that when it scheduled Danly’s visit, it had nothing to do with its seasonal capacity auction.
MISO CEO John Bear said staff will ensure stakeholders have enough time to understand the recalculated ratio and how it affects thermal resources’ accreditation before running the auction.
The recalculated ratios are expected to result in “reduced accreditation values for individual market participants and on an aggregate basis,” MISO says.
During an Advisory Committee meeting Wednesday, Jim Dauphinais, an energy consultant representing multiple MISO end-use customers, said it’s important that the grid operator back up and make sure it’s using correct values in the auction. He said while it was “unfortunate” how it played out, FERC’s order and subsequent delay illustrates how untested market changes can cause disruptions when systems and people aren’t prepared.
“Quite frankly, we don’t know if our seasonal construct is working,” Dauphinais said.
The U.S. Department of Energy this week released three reports assessing how the U.S. can decarbonize its economy by 2050 through massive development and deployment of clean hydrogen, advanced nuclear reactors and grid-scale energy storage.
The agency’s Pathways to Commercial Liftoff reports make broad assessments of the current state of the three technologies, which the Biden administration believes will be needed for decarbonization. The study projects the minimum technological advances that must be made by 2035 to attain the 2050 benchmarks.
The documents are also intended as a first step toward encouraging comprehensive communication between DOE and the nation’s industries as the agency sets technology standards and develops funding programs.
“These reports are intended to reinforce dialogue with the private sector, and DOE will be seeking continuous feedback from industry as these reports are updated and revised over time,” the reports’ authors write in an introduction.
Lucia Tian, a senior adviser to the DOE’s chief commercialization officer, reinforced the message during a Tuesday webinar arranged to promote the release of the reports.
“These liftoff reports represent a department-wide initiative to strengthen engagement between the public and private sectors to accelerate the commercialization and deployment of key clean energy technologies,” she said.
The compilations are intended to “create a common fact base” and chart what DOE and industry determine will be the best ways to achieve commercial success of the technologies by midcentury, she added.
The publication of the reports comes three weeks before the agency’s application deadlines for industry and local governments vying for federal matching grants and the designation as a “hydrogen hub.”
DOE has set aside $7 billion to invest in six to 10 regional projects designed to generate clean hydrogen close to where industry will use it, such as in steelmaking, oil refining and concrete manufacturing. DOE has said it intends to award matching grants to hub applications it judges to have the best chance of success.
That funding and the billions that will follow to develop the “liftoff” of clean hydrogen and other energy technologies come out of the Investment and Jobs Act in 2021 and Inflation Reduction Act in 2022, which together will direct billions of dollars in funding and tax credits to projects designed to move the economy from fossil fuels to renewable energy.
The legislation was also intended to identify and assist critical, emerging technologies, said David Crane, director of the newly created DOE Office of Clean Energy Demonstrations.
“These ‘Liftoff’ reports in many respects [reflect] the clear intent of Congress to expand one of DOE’s traditional missions of funding the demonstration of new energy technologies at scale [to] funding demonstration projects that will provide enduring value to American energy consumers because they are commercially and financially viable,” Crane said.
Citing hydrogen as an example, Crane said the government’s objective is to “de-risk hydrogen hubs to the extent necessary to attract private sector project sponsors.”
“Consistent with the entire history of the American energy industry, these hydrogen mega-projects are going to be developed built and operated by the private sector, not by the federal government. The clean energy transition will be private sector-led and government-enabled,” Crane said.
Vanessa Z. Chan, chief commercialization officer and director of DOE’s Office of Technology Transition, addressed the importance of advanced energy storage to the continued deployment of renewable energy.
The Biden administration’s goal is to deploy 10 to 15 GW of additional storage capacity annually by 2035, she said, a target that will not be achieved without the development of a supply chain. DOE’s goal is to reduce the cost of long-duration energy storage (LDES) by 90%.
“LDES is critical to the clean energy transition and has enormous potential to really help support the high renewable penetration because it helps overcome intermittency when the sun isn’t shining or the wind isn’t blowing, while simultaneously improving our grid resilience,” Chan said.
“LDES technology is still maturing, and investors are still cautious. There are over 100 LDES providers spanning a wide range of technology types, which are vying for this market. That is exciting because it gives a sector a lot of shots. To get to liftoff, the LDES technologies are going to require public and private investment to drive down costs,” she said
‘Clear Value Proposition’
Jigar Shah, head of the DOE’s loan program office, estimated the nation will need to build and deploy 100 to 200 GW in new nuclear capacity by 2050.
“I think advanced nuclear has a clear value proposition as a clean, firm power source to complement renewables on the path towards decarbonization,” said Shah, adding that he believes 10 new reactors must be ordered by 2025 if advanced nuclear is going to play a meaningful role.
Clockwise from top left: David Crane, Clean Energy Demonstrations; Lucia Tian, Office of Technology Transitions; Vanessa Chan, Technology Transitions; and Jigar Shah, Loan Programs | DOE
Shah also said the deployment of new reactors will create “high-paying jobs with concentrated economic benefits for communities most impacted by the energy transition such as coal communities,” a reference to DOE suggestions that small modular reactors still under development will be safe enough to locate on the grounds of former coal-fired power plants, which has existing connections to the electrical grid.
DOE’s Commercial Liftoff of Advanced Nuclear keeps nuclear power in the mix and looks for ways to stimulate new construction. The report says the U.S. nuclear industry has the potential to “scale to 300 GW by 2050 — driven by deployment of advanced nuclear technologies.”
But the study also finds that development is currently stymied, a situation that puts overall decarbonization goals at risk.
“Utilities and other potential customers recognize the need for nuclear power, but perceived risks of uncontrolled cost overruns and project abandonment have limited committed orders for new reactors,” the report said.
ISO-NE touted its role in New England’s clean energy transition on Tuesday as it announced the finalized results of Forward Capacity Auction 17, for the 2026-2027 procurement period.
Non-emitting generators secured nearly a quarter of the auction’s total obligations, the RTO said.
“The 7,620 MW of obligations secured by these resources represents an 11% increase over the 6,844 MW of obligations secured by non-carbon-emitting resources in the 12th Forward Capacity Auction, held in 2018,” the grid operator said in a press release.
Solar and wind generation accounted for 3.5% of all obligations in FCA 17, and battery storage accounted for another 3.5%.
In that vein, the auction may also signal that an end to the use of coal for generation in New England is near: The region’s last remaining coal-fired plant, Merrimack Station in Bow, N.H., submitted a dynamic delist bid and did not win a capacity supply obligation.
In its detailed explanation of the auction, the grid operator said that its reviews of delist bids, including three permanent ones totaling 12.5 MW and two retirements worth 7.8 MW, did “not show the need to retain for reliability any resources”; all of the bids were therefore accepted.
Among the significant delist bids were two oil units at the Middletown plant in Connecticut and the Millennium gas plant in Massachusetts.
ISO-NE also confirmed that the clearing prices it listed in its initial announcement were accurate: $2.59/kW-month in all zones and import interfaces except for the New Brunswick interface, which cleared at $2.551.
WASHINGTON — The energy transition still presents some key hurdles that need to be overcome for it to occur successfully, speakers said at Electric Power Supply Association’s (EPSA) Competitive Power Summit on Tuesday.
“We need to think broadly about how we can collaborate to ensure reliability,” EPSA President Todd Snitchler said. “We’re looking at working through a period of energy expansion, not merely passively watching an energy transition.”
Getting to 100% renewable power plus electrifying key new areas of demand such as home heating and transportation means the industry will have to build more supply than it has now as it cleans up its generation stack, he added.
“Reliability has been a top priority for as long as competitive markets have been in place, but competing interests from policymakers and regulators have drawn attention away from that first responsibility,” Snitchler said.
NERC CEO Jim Robb noted that the industry has been through a number of high-profile events in recent years that have kept his organization busy, from winter freezes to physical attacks on grid infrastructure.
“Many of the issues and challenges that we’re starting to see are really coming at us through the generation side of the business, which is a little bit different than what we dealt with when the ERO was originally stood out in the mid-2000s,” Robb said. “And those issues are particularly around fuel supply and energy production.”
The key challenge facing the grid is reliably transitioning to a more intermittent resource mix while preserving the key reliability services that traditional, synchronous power plants provide. The grid’s dependence on natural gas and the lack of coordination were “exposed in Technicolor” during the outages in Texas and its neighboring states in February 2021, Robb said.
“Managing the pace of this transition is going to be key to being able to navigate it successfully,” Robb said. “And we’ve seen, through our reliability assessments, a steady decline in the risk profile of the sector of the last five years. And that’s in spite of a very strong aggregate performance, but the risks are clearly growing.”
Extreme weather is becoming more commonplace, and that has huge impacts on demand, especially in markets that use electricity for heat.
“Once the temperature drops to a point where heat pumps can perform, and you switch to electric resistance heating, the demand goes pretty much vertical,” Robb said. “That I think is going to be one of the main headlines coming out of our inquiry into Winter Storm Elliott,” referring to the storm that led to outages in the Southeast over the holidays late last year.
The changing grid also means that weather has a greater impact on generation, as too little or too much wind can knock out power from that renewable resource, or snow and clouds can block sunlight from reaching solar panels.
NERC has recently implemented winterization standards that it started after a cold snap in 2018 and were updated after the winter storm of February 2021.
Robb said that NERC needs to step up the pace of developing new standards so it can adequately respond to the changing grid, but efforts at streamlining the standards development process hit a snag earlier this month when a set of proposed changes to the organization’s Standards Processes Manual (SPM) failed on its first ballot. He said that industry stakeholders had not been particularly constructive in that effort.
“Our goals here are to speed the process, eliminate low value-added time sinks; actually maintain stakeholder engagement, stakeholder ownership of the outcomes; and we do want to give the board the authority to set meaningful deadlines to move things along,” Robb said.
The proposed SPM changes included creating a tiered system of comment periods, under which the initial 45-day comment and balloting periods would be followed by shorter comment periods. Another significant change would have removed the requirement for a final ballot to confirm the results of the most recent successful ballot, if the standard drafting team (SDT) felt that no further “substantive changes” were needed. (See NERC Standards Process Changes Headed for Public Comment.)
The changes were approved by NERC’s Standards Committee in January, following an order issued by the Board of Trustees at its November meeting. Trustee Sue Kelly said in December that the board was trying to address concerns that NERC’s “deliberative” standards development process was not keeping up with the increasingly rapid pace of industry change. (See NERC Board Member Argues for Increased Authority.)
Industry rejected the proposed SPM changes by a significant margin, with 118 votes against and 76 in favor. Some commenters, such as the Northern California Power Agency (NCPA), said the revisions did not adequately address issues of “due process, openness and balance of interests, [which] are already problematic under current SPM rules.” NCPA also complained that “SAR [standard authorization request] drafting teams do not always appear to make an effort to resolve SAR objections” as the SPM currently requires.
Commenters also objected specifically to the proposed shortening of later ballot periods, with Andrea Jessup of the Bonneville Power Administration pointing out that “industry subject matter experts are all very busy and … need the full 45 days to allow time for” full review. Jessup said that reducing the time for comments “would likely cause less industry participation” in the process.
Referring to the idea of eliminating the final ballot, the Midwest Reliability Organization’s NERC Standards Review Forum said that “only language approved by industry should be considered by the Board of Trustees for approval,” a view echoed by multiple commenters. NCPA said it could only agree with the proposal if the SDT makes no changes to the standard that passed the final ballot, explaining that “one person’s … idea of ‘not making a substantive change’ may not always be consistent with entities that voted for the proposal prior to … change.”
LS Power Sees Much Work Ahead
LS Power Generation President Nathan Hanson argued that the industry was just getting started on the transition to cleaner energy.
“If you really step back and think how much progress we’ve really made facilitating the transition, either on the regulatory basis or even legislatively, I don’t think we’ve really made any ground, and we’re basically a year closer to having to manage the issues that are showing up at the grid in California and Texas, or PJM and New England, over the Christmas period,” Hanson said.
That changeover needs to happen in a reliable and affordable way to avoid any customer revolts, he added.
“We have legislation and regulations that are going to allow as many renewables into the space as we can. The question is … can you manage the grid when you do that?” Hanson said. “And I would argue we’re on the tip of being able to manage it effectively even right now.”
Keeping existing plants running is the cheapest way the industry can keep on balancing the grid, but that value is not coming through in many markets, leading to retirements of resources that could help maintain reliability even if they are only run rarely.
Robb also called out the RTOs, saying that they need to revisit their market rules in light of recent issues the industry has faced.
“RTOs really need to revisit their market rules and create some way through market incentives and compensation to synthetically recreate the obligation to serve that guided this industry for such a long period of time,” Robb said. “We allow too many decisions to be made based on probabilities, economic returns, the likely scenarios going forward; and those are great. And those work for 99% of the time. It’s that 1% though; if we get outside of that, we get into real trouble.”
Shell’s Comer Endorses the US Approach to Energy Transition
Shell Energy Americas President Carolyn Comer said her firm was well poised to move on the energy agenda and offered praise to the U.S.’ “carrot-heavy” policy approach to guiding the energy transition.
The main issue is getting clean sources of energy to scale up because as that work continues, demand is going to grow, with 2 billion more people expected by 2050 and demand for power expected to double globally in that same period, she said. Sometimes the arguments get too simplistic, such as pitting the transition to clean energy against affordability.
“I would argue, actually, if we don’t clean up our act and we don’t deal with climate change, or we don’t tackle the environmental stresses that we’re causing, the cost will be greater than the cost of investing in clean technologies in the first place,” Comer said.
While there is usually no line item on a power bill, customers are paying for catastrophic climate events from wildfires in the West to the deep freeze that led to days of outages in Texas in 2021, she added.
The Inflation Reduction Act will help the industry move on the transition with a number of “carrots” in the form of tax breaks and other forms of investment in clean technologies.
“I think it’s the right way to go because it protects the industrial base at the same time as we actually embark on an accelerated energy transition,” Comer said. “And so, I think it’s actually kind of leading the world from that perspective.”
Calpine has the largest geothermal fleet in the world, a collection of more than 350 wells with a nameplate capacity of about 1,590 MW, which CEO Thad Hill says the company is hoping to expand. But, in a “fireside chat” with EPSA CEO Snitchler, Hill said he does not see geothermal as a game-changer for the energy transition, as building new capacity, specifically closed-loop systems, will be expensive.
At the same time, Hill does see carbon capture as one of the new technologies that will be critical in reaching national and some state-level decarbonization goals, and Calpine hopes to lead the sector as it develops.
Turning to the summit’s key theme of reliability, Hill said, the lessons of the February 2021 winter storm in Texas — including the need for better forecasting and gas-electric coordination — have been addressed, but challenges still lie ahead.
“We’re in a very different era now. We’ve got a lot more intermittence. Our traditional definition of what was reliable [is changing],” he said. “Now we have a huge amount of other qualities of risk. We need to talk about reliability from a brand-new standpoint. We’re beginning to see that in every single organized market in the country right now.”
Compensation for reliability is already being rethought, but further changes may be needed as new intermittent renewable energy comes online, Hill said. “A system … based on how capacity got measured [is not] going to work when you’re putting in tens of thousands of megawatts of super-subsidized resources that make sense — almost regardless of the market conditions — to build economically,” he said. “So, we’ve got to think through how we’re going to compensate that.”
He pointed to PJM’s proposals for capacity accreditation as a potential solution, as well as more performance-based compensations schemes now being discussed across the industry.
“I happen to think you should get hammered if you don’t perform,” he said. “But then you should be able to bid some chance risk into the capacity price you’re going to receive in the market.”
Hill also sees the increase in corporate clean energy goals and procurement as a positive sign for independent power producers in competitive markets. Innovation on the generation side and the customer side could provide the best way to keep costs down, and he sees rate design, in particular, keeping non-bypassable charges on the low side, as a critical factor.
“I actually think you know, on this construct, we’re actually aligned more with our customers, our large customers,” he said. “The more non-bypassable charges we have, the less room there is for innovation … whether it’s behind the meter, generation [or] storage.”
